Occidental (NYSE: OXY) pivots with $9.7B OxyChem sale and debt reduction
Filing Impact
Filing Sentiment
Form Type
10-K
Rhea-AI Filing Summary
Occidental Petroleum outlines a major portfolio shift and balance sheet changes in its annual report for the year ended December 31, 2025. The company sold its OxyChem business to Berkshire Hathaway for
Proceeds are being used primarily to reduce debt. Occidental repaid about
In 2025 the company invested
Positive
- Major deleveraging using OxyChem sale proceeds: Occidental sold OxyChem for
$9.7 billion , realized an estimated$3.2 billion after‑tax gain, repaid about$4.0 billion of debt in 2025 plus$5.4 billion after year‑end, and reports principal debt of roughly$15 billion with a stated target of about$14.3 billion .
Negative
- None.
Insights
Occidental pivots with a large chemical sale and aggressive debt reduction.
Occidental Petroleum repositions its portfolio by selling OxyChem to Berkshire Hathaway for
Management is channeling proceeds into deleveraging, repaying about
The company also invested
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
| Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | ||||||||||||||||
| For the fiscal year ended | For the transition period from to | ||||||||||||||||
Commission File Number 1-9210
(Exact name of registrant as specified in its charter)
| State or other jurisdiction of incorporation or organization | |||||||||||||||||
| I.R.S. Employer Identification No. | |||||||||||||||||
| Address of principal executive offices | |||||||||||||||||
| Zip Code | |||||||||||||||||
| Registrant’s telephone number, including area code | |||||||||||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Trading Symbol | Name of Each Exchange on Which Registered | ||||||
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.
| ☑ | Accelerated Filer | ☐ | Emerging Growth Company | ||||||||||||||
| Non-Accelerated Filer | ☐ | Smaller Reporting 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 ☑
The aggregate market value of the registrant’s Common Stock held by nonaffiliates of the registrant was approximately $41.4 billion computed by reference to the closing price on the New York Stock Exchange of $42.01 per share of Common Stock on June 30, 2025.
As of January 31, 2026, there were 986,266,656 shares of Common Stock outstanding, par value $0.20 per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement, relating to its 2026 Annual Meeting of Stockholders, are incorporated by reference into Part III of this Form 10-K.
| TABLE OF CONTENTS | PAGE | |||||||
| Part I | ||||||||
| Items 1 and 2. | Business and Properties | 3 | ||||||
General | 3 | |||||||
Human Capital Resources | 3 | |||||||
Environmental Regulation | 5 | |||||||
Available Information | 5 | |||||||
Oil and Gas Operations | 6 | |||||||
Midstream and Marketing Operations | 7 | |||||||
| Item 1A. | Risk Factors | 8 | ||||||
| Item 1B. | Unresolved Staff Comments | 16 | ||||||
Item 1C. | Cybersecurity | 16 | ||||||
| Item 3. | Legal Proceedings | 17 | ||||||
| Item 4. | Mine Safety Disclosures | 17 | ||||||
Information about Executive Officers | 18 | |||||||
| Part II | ||||||||
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 19 | ||||||
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 21 | ||||||
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 52 | ||||||
| Item 8. | Financial Statements and Supplementary Data | 54 | ||||||
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 125 | ||||||
| Item 9A. | Controls and Procedures | 125 | ||||||
| Item 9B. | Other Information | 125 | ||||||
| Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 125 | ||||||
| Part III | ||||||||
| Item 10. | Directors, Executive Officers and Corporate Governance | 126 | ||||||
| Item 11. | Executive Compensation | 126 | ||||||
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 126 | ||||||
| Item 13. | Certain Relationships and Related Transactions and Director Independence | 126 | ||||||
| Item 14. | Principal Accounting Fees and Services | 127 | ||||||
| Part IV | ||||||||
| Item 15. | Exhibits and Financial Statement Schedules | 127 | ||||||
| Item 16. | Form 10-K Summary | 129 | ||||||
| ABBREVIATIONS AND DEFINED TERMS USED WITHIN THIS DOCUMENT | |||||
| AOC | Administrative Order on Consent | ||||
| Anadarko | Anadarko Petroleum Corporation and its consolidated subsidiaries | ||||
| Andes | Andes Petroleum Ecuador Ltd. | ||||
| ARO | asset retirement obligations | ||||
| ASC | Accounting Standards Codification | ||||
| Bcf | billions of cubic feet | ||||
| Bcf/d | billions of cubic feet per day | ||||
| Berkshire Hathaway | Berkshire Hathaway Inc., a related party | ||||
| Berkshire Warrant | Stock warrant issued on August 8, 2019 to Berkshire Hathaway with a $59.59 strike price | ||||
BlackRock | BlackRock Inc., which has formed a joint venture with the Company on the construction of STRATOS | ||||
| the Board | Occidental Board of Directors | ||||
| Boe | barrels of oil equivalent | ||||
| CAD | Canadian dollar | ||||
| CCUS | carbon capture, utilization and storage | ||||
| CERCLA | Comprehensive Environmental Response, Compensation, and Liability Act | ||||
CEO | chief executive officer | ||||
| CIO | chief information officer | ||||
CO2 | carbon dioxide | ||||
| CODM | chief operating decision maker | ||||
| Common Stock Warrants | Stock warrants issued to holders of Occidental common stock with a strike price of $22.00, listed on the NYSE under the symbol “OXY.WS” | ||||
| the Company | Occidental Petroleum Corporation, a Delaware corporation, and/or one or more entities in which it owns a controlling interest (subsidiaries) | ||||
| CROCE | cash return on capital employed | ||||
| CROCEI | cash return on capital employed incentive | ||||
| CrownRock | CrownRock, L.P. | ||||
CrownRock Acquisition | acquisition of all of the outstanding partnership interests of CrownRock by the Company | ||||
| DAC | direct air capture | ||||
| DASS | Diamond Alkali Superfund Site | ||||
| DD&A | depreciation, depletion and amortization | ||||
| DEL | Dolphin Energy Limited | ||||
| DJ | Denver-Julesburg | ||||
| DOE | U.S. Department of Energy | ||||
| DOJ | U.S. Department of Justice | ||||
| DSCC | Diamond Shamrock Chemicals Company | ||||
ECMC | Colorado Energy and Carbon Management Commission, formerly the Colorado Oil & Gas Conservation Commission | ||||
| EOR | enhanced oil recovery | ||||
| EPA | U.S. Environmental Protection Agency | ||||
| EPS | earnings per share | ||||
| Exchange Act | Securities Exchange Act of 1934 | ||||
| FCF | Free cash flow | ||||
| GAAP | Generally accepted accounting principles | ||||
| GHG | greenhouse gas, primarily including carbon dioxide and methane | ||||
| GOA | Gulf of America | ||||
| HSE | health, safety and environmental | ||||
IRA | Inflation Reduction Act | ||||
IRS | Internal Revenue Service | ||||
| Kerr-McGee | Kerr-McGee Corporation and certain of its subsidiaries | ||||
| Maxus | Maxus Energy Corporation | ||||
| Mbbl | thousands of barrels | ||||
| Mbbl/d | thousands of barrels per day | ||||
| Mboe | thousands of barrels of oil equivalent | ||||
| Mboe/d | thousands of barrels of oil equivalent per day | ||||
| ABBREVIATIONS AND DEFINED TERMS USED WITHIN THIS DOCUMENT | |||||
| Mcf | thousands of cubic feet | ||||
| MMbbl | millions of barrels | ||||
| MMbtu | million British thermal units | ||||
| MMcf | millions of cubic feet | ||||
MMcf/d | millions of cubic feet per day | ||||
| NAV | net asset value | ||||
NCI | noncontrolling interest | ||||
| NEPA | National Environmental Policy Act | ||||
| NGL | natural gas liquids | ||||
| NPL | National Priorities List | ||||
| NYMEX | New York Mercantile Exchange | ||||
| NYSE | New York Stock Exchange | ||||
| OBBBA | One Big Beautiful Bill Act | ||||
| Occidental | Occidental Petroleum Corporation, a Delaware corporation | ||||
OCI | other comprehensive income | ||||
OECD | Organization for Economic Cooperation and Development | ||||
| OLCV | Oxy Low Carbon Ventures, LLC and its consolidated subsidiaries | ||||
| OPEC | Organization of the Petroleum Exporting Countries | ||||
| OTC | over-the-counter | ||||
| OU | operable unit | ||||
| OxyChem | Occidental Chemical Corporation, a Texas corporation, and its consolidated subsidiaries | ||||
| OxyChem Transaction | the sale of all of the issued and outstanding equity interests in OxyChem to Berkshire Hathaway pursuant to a purchase and sale agreement dated October 2, 2025, which closed on January 2, 2026 | ||||
the Plans | the stockholder-approved 2015 Long-Term Incentive Plan, as amended and restated, for certain employees and directors and the Phantom Share Unit Award Plan | ||||
| PP&E | property, plant and equipment | ||||
| PSC | production sharing contracts | ||||
| PUD | proved undeveloped | ||||
| RCF | revolving credit facility | ||||
| Reserves Committee | Corporate Reserves Review Committee | ||||
| ROD | Record of Decision | ||||
| RSUs | restricted stock units | ||||
| Ryder Scott | Ryder Scott Company, L.P. | ||||
| S&P 500 | Standard & Poor’s 500 Stock Index | ||||
| SEC | U.S. Securities and Exchange Commission | ||||
| SOFR | Secured Overnight Financing Rate | ||||
| Sonatrach | the national oil and gas company of Algeria | ||||
| SPEE | Society of Petroleum Evaluation Engineers | ||||
| STEP | Strategic Technical Excellence Program | ||||
STRATOS | the Company’s first large-scale DAC facility in Ector County, Texas | ||||
| TSRI | total shareholder return incentive | ||||
| UAE | United Arab Emirates | ||||
| Waha | natural gas trading hub in the Permian Basin | ||||
| WES | Western Midstream Partners, LP | ||||
| WTI | West Texas Intermediate | ||||
| Form 10-K | the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 | ||||
 | table of contents | BUSINESS AND PROPERTIES | ||||||
Part I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
In this Form 10-K, “Occidental” refers to Occidental Petroleum Corporation, a Delaware corporation; “the Company,” “it,” and “our” refer to Occidental and/or one or more entities in which it owns a controlling interest (subsidiaries). Occidental’s executive offices are located at 5 Greenway Plaza, Suite 110, Houston, Texas 77046; telephone (713) 215-7000.
| GENERAL | ||
The Company is an international energy company recognized for its premier diversified assets, primarily situated in the United States, the Middle East and North Africa. The Company’s distinguished operational capabilities support sustainable value creation for shareholders. The Company ranks among the largest oil and gas producers in the U.S., holding leading positions in the Permian and DJ Basins as well as offshore Gulf of America, and is the largest independent oil producer in Oman. Our midstream and marketing segment ensures flow assurance and optimizes the value of oil and gas operations. Additionally, Oxy Low Carbon Ventures, a subsidiary within the midstream and marketing segment, focuses on advancing innovative decarbonization technologies and solutions—including direct air capture, carbon sequestration and lithium development to advance the Company’s growth opportunities while reducing overall emissions and delivering the energy and products the world needs.
RECENT DEVELOPMENTS
In October 2025, the Company announced entry into a purchase and sale agreement with Berkshire Hathaway to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion, subject to post closing adjustments. The sale was completed on January 2, 2026, resulting in an estimated gain of $3.2 billion, net of taxes subject to post-closing adjustments. As a result of the agreement to sell OxyChem, its results are reported separately as discontinued operations in our consolidated statements of operations for all periods presented and its assets and liabilities have been reclassified in our consolidated balance sheet to assets and liabilities held for sale. Prior to presentation of OxyChem as discontinued operations, the Company’s chemical business was a reportable segment.
As a result of our agreement to sell OxyChem, the following changes in our basis of presentation have occurred:
■In accordance with ASC 205, Discontinued Operations, intersegment sales from our oil and gas and midstream and marketing segments to the chemical segment are no longer eliminated as intercompany transactions. All periods presented have been retrospectively adjusted to reflect this change.
■Beginning October 1, 2025, in accordance with ASC 360, PP&E, depreciation and amortization were no longer recorded for the chemical segment’s PP&E and right of use lease assets.
| HUMAN CAPITAL RESOURCES | ||
The Company’s culture is built upon the following core values:
■Lead with Passion
■Outperform Expectations
■Deliver Results Responsibly
■Unleash Opportunities
■Commit to Good
The Company’s human capital resources and programs are managed by its Human Resources department, with support from business leaders across the Company. The Company’s senior management team plays a key role in setting and monitoring the Company’s culture, values and broader human capital management practices, with oversight by the Company’s Board of Directors, the Sustainability and Shareholder Engagement Committee of the Board and the Environmental, Health and Safety Committee of the Board. To enhance senior leadership’s engagement with employees, the Company hosts quarterly executive virtual conversations led by its President and CEO, Vicki Hollub, who along with other executives reviews financial and operational performance of the Company and responds to employee questions.
The Company strives to create an environment where employees’ differences are appreciated, celebrated and encouraged. The Company has attracted, and continues to recruit, a diverse workforce of exceptional talent. This diversity enriches the Company’s culture and its employees’ experiences on the job and contributes to an innovative and effective business model that helps communities where we operate thrive. The Human Resources department supports several
OXY 2025 FORM 10-K | 3 | ||||
| table of contents | BUSINESS AND PROPERTIES | ||||||
voluntary Employee Resource Groups, which promote peer engagement and education to help advance inclusion and a sense of belonging of employees with common interests.
TALENT ATTRACTION, DEVELOPMENT AND RETENTION
The Company recruits candidates in numerous ways, including through job fairs, professional societies and campus recruiting. To attract and retain talent, the Company has implemented programs that afford employees flexibility and promote work-life balance. Among them is the Balanced Workplace Program under which eligible office-based employees may opt to work three days in the office and two days at home each week.
In addition, the Company’s global STEP was formed to recruit, develop and retain highly skilled and valued geoscientists, engineers, scientists and other petrotechnical professionals who collectively drive innovation, advance performance and inspire the future of energy development. STEP is a highly valued program for individual contributors to focus and advance on a technical, non-managerial career path, providing a competitive advantage for the Company through the optimum application of technology. The Chief Petrotechnical Officer leads all aspects of STEP and reports directly to the Company’s Chief Operating Officer.
Company employees have access to extensive development and training opportunities and programs to expand their personal and professional skills and knowledge. The Company’s approach to education includes leadership/management training to develop leadership skills at all levels and expanded on-demand professional and development classes and mentoring to enhance critical business skills, broaden employee networks, and engage its employees.
EMPLOYEE COMPENSATION AND BENEFITS
The Company’s compensation and benefits program is designed to attract and retain the talent necessary to achieve its business strategy. The compensation and benefits program recognizes and rewards strong Company and individual performance with competitive base salaries, as well as an annual bonus program, recognition awards, long-term performance incentives and advancement opportunities for eligible individuals. The Company’s compensation and benefits program is routinely reviewed and benchmarked to ensure competitiveness and to provide the benefits that matter most to current and future employees.
The Company strives to give employees the tools and resources they need to succeed both professionally and personally and to foster a safe and collaborative work environment. To that end, the Company offers, and regularly evaluates, its comprehensive health, welfare and retirement and savings benefits plans, professional memberships and work-life balance benefits. It also provides programs to enhance and support employees’ overall well-being, including their physical, mental, social and financial health. Addressing well-being is imperative to ensure that the Company’s employees stay resilient, healthy and productive. The Company offers an enhanced mental health benefit, providing cost-free and convenient care for employees and their eligible dependents. Professional support is available virtually or in person for a range of concerns, including anxiety, depression, stress management, parenting challenges, relationship conflicts and sleep issues.
HEALTH AND SAFETY
The health and safety of the Company’s workforce and communities is a top priority as reflected in the Company’s HSE and Sustainability Principles. The Company’s Operating Management System sets expectations, provides guidance, training and resources, and empowers employees and contractors to stop any job or activity if they observe conditions that may give rise to a safety or environmental incident. The Company is also focused on reducing incident severity, enhancing contractor safety programs and harmonizing safety systems, programs and tools. These efforts helped the Company sustain its robust safety record in 2025 and promote continued improvements and innovations in safety, efficiency, reliability and environmental stewardship.
WORKFORCE COMPOSITION
The table below shows the regional distribution of the Company’s employees working in continuing operations as of December 31, 2025:
| North America | Middle East | Latin America | Other (a) | Total (b) | ||||||||||||||||||||||||||||
| Union | — | 409 | — | — | 409 | |||||||||||||||||||||||||||
| Non-Union | 6,793 | 3,032 | 67 | 111 | 10,003 | |||||||||||||||||||||||||||
| Total | 6,793 | 3,441 | 67 | 111 | 10,412 | |||||||||||||||||||||||||||
(a)Other headcount included North Africa, Europe and Asia.
(b)Excludes employees related to OxyChem, a discontinued operation.
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| table of contents | BUSINESS AND PROPERTIES | ||||||
| ENVIRONMENTAL REGULATION | ||
For environmental regulation information, including associated costs, see the information under Environmental Expenditures in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section under Part II, Item 7 of this Form 10-K, Risk Factors under Part I, Item 1A of this Form 10-K and in Note 11 - Environmental Liabilities and Expenditures and Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
| AVAILABLE INFORMATION | ||
The Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are available free of charge on its website, www.oxy.com, as soon as reasonably practicable after the Company electronically files the material with, or furnishes it to, the SEC. In addition, copies of the Company’s annual report will be made available, free of charge, upon written request.
From time to time, the Company has made and expects in the future to use its website as a channel of distribution of material information regarding the Company. Financial and other material information regarding the Company is routinely posted on the Company’s website and accessible at www.oxy.com/investors/.
Information contained on the Company’s website is not part of or incorporated into this Form 10-K or any other filings with the SEC.
OXY 2025 FORM 10-K | 5 | ||||
| table of contents | BUSINESS AND PROPERTIES | ||||||
| OIL AND GAS OPERATIONS | ||
GENERAL
The Company’s oil and gas business is primarily located in the United States, the Middle East and North Africa. Within the United States, the Company has operations primarily in Texas, New Mexico and Colorado, as well as offshore in the Gulf of America. The Company’s international assets are primarily located in Algeria, Oman, Qatar and the UAE. Refer to the Oil and Gas Acreage section in Supplemental Oil and Gas Information under Item 8 of this Form 10-K for further disclosure of the Company’s holdings of developed and undeveloped oil and gas acreage.
COMPETITION
The Company produces oil, NGL and natural gas in both domestic and international markets, competing with public, private, and state-owned producers. Market conditions significantly influence hydrocarbon pricing and demand. The Company pursues capital-efficient production through conventional and unconventional field development, employing primary, secondary (waterflood), and tertiary (e.g., CO₂ and steam flood) recovery methods in areas where it has established advantages. The Company focuses on safe, sustainable and cost-effective reserve development, supported by a skilled workforce and quality service providers. The Company’s expertise in CO₂ separation, transportation, utilization, recycling and storage for EOR provides a competitive edge as the energy sector transitions toward lower carbon intensity products.
PROVED RESERVES AND SALES VOLUMES
The table below shows the Company’s year-end oil, NGL and natural gas proved reserves. See the information under Oil and Gas Segment in the Management’s Discussion and Analysis section under Part II, Item 7, of this Form 10-K for details regarding the Company’s proved reserves, the reserves estimation process, sales and production volumes, production costs and other reserves-related data.
COMPARATIVE OIL AND GAS PROVED RESERVES AND SALES VOLUMES
Oil and NGL are in MMbbl; natural gas is in Bcf.
| 2025 | 2024 | 2023 | |||||||||||||||||||||||||||||||||||||||||||||
| Oil | NGL | Gas | Boe | (a) | Oil | NGL | Gas | Boe | (a) | Oil | NGL | Gas | Boe | (a) | |||||||||||||||||||||||||||||||||
Proved Reserves | |||||||||||||||||||||||||||||||||||||||||||||||
| United States | 1,824 | 990 | 5,842 | 3,788 | 1,832 | 1,060 | 5,394 | 3,791 | 1,600 | 802 | 4,235 | 3,108 | |||||||||||||||||||||||||||||||||||
| International | 338 | 160 | 1,903 | 815 | 303 | 176 | 2,049 | 821 | 340 | 181 | 2,117 | 874 | |||||||||||||||||||||||||||||||||||
| Total | 2,162 | 1,150 | 7,745 | 4,603 | 2,135 | 1,236 | 7,443 | 4,612 | 1,940 | 983 | 6,352 | 3,982 | |||||||||||||||||||||||||||||||||||
| Sales Volumes | |||||||||||||||||||||||||||||||||||||||||||||||
| United States | 226 | 105 | 643 | 438 | 209 | 102 | 548 | 402 | 195 | 90 | 480 | 365 | |||||||||||||||||||||||||||||||||||
| International | 40 | 14 | 186 | 85 | 38 | 14 | 191 | 84 | 39 | 13 | 176 | 81 | |||||||||||||||||||||||||||||||||||
| Total | 266 | 119 | 829 | 523 | 247 | 116 | 739 | 486 | 234 | 103 | 656 | 446 | |||||||||||||||||||||||||||||||||||
(a)Natural gas volumes are converted to Boe at six Mcf of gas per one barrel of oil. Conversion to Boe does not necessarily result in price equivalency.
6 | OXY 2025 FORM 10-K | ||||
| table of contents | BUSINESS AND PROPERTIES | ||||||
| MIDSTREAM AND MARKETING OPERATIONS | ||
GENERAL
The Company’s midstream and marketing operations primarily support and enhance its oil and gas business. The midstream and marketing segment evaluates opportunities across the value chain to provide services to Occidental’s subsidiaries as well as third parties by optimizing the use of its gathering, processing, transportation, storage and terminal commitments and to provide access to domestic and international markets. The midstream and marketing segment operates or contracts for services on gathering systems, gas plants and storage facilities and invests in entities that conduct similar activities, such as WES in the United States and DEL in the Middle East, which are accounted for as equity method investments. WES owns gathering systems, plants and pipelines and earns revenue from fee-based and service-based contracts with the Company and third parties. DEL owns and operates a pipeline that connects its gas processing and compression plant in Qatar and its receiving facilities in the UAE, and uses its network of DEL-owned and other existing leased pipelines to supply natural gas to the UAE and Oman. The midstream and marketing segment also includes Al Hosn Gas, a processing facility in the UAE that removes sulfur from natural gas and processes the natural gas and sulfur for sale.
The midstream and marketing segment also has the OLCV businesses, which leverage the Company’s carbon management expertise. OLCV primarily focuses on advancing carbon removal and CCUS projects, including developing and commercializing DAC technology and supporting the Company’s EOR operations. STRATOS, the Company’s first large-scale DAC facility, is designed to capture up to 500,000 tons of CO2 per annum once complete. Operations are expected to begin in 2026, with an initial capacity of up to 250,000 tons of CO2 per annum from trains 1 and 2, with the remaining 250,000 tons of capacity upon completion of trains 3 and 4. OLCV also invests in third-party entities developing technologies to advance other low-carbon initiatives.
COMPETITION
The Company’s midstream and marketing businesses operate in competitive and highly regulated markets and competes for capacity and infrastructure for the gathering, processing, transportation, storage and delivery of its products, which are sold at market prices or on a forward basis to refiners, end users and other market participants. The Company’s marketing business competes with other market participants on exchange platforms and through other bilateral transactions with direct counterparties. OLCV and its businesses and investees also face a broad range of competitors, with nascent markets for low-carbon products and CO2 removal credits that are subject to evolving laws, regulations, policies and reporting and verification mechanisms that can significantly impact the financing, construction and operation of projects and the development of markets.
The Company’s midstream and marketing operations are conducted in the locations described below as of December 31, 2025:
| Location | Description | Capacity (a) | ||||||
| Gas Plants | ||||||||
| Texas, New Mexico and Colorado | Company and third-party-operated natural gas/CO2 gathering, compression and processing systems | 2.2 Bcf/d | ||||||
| Texas, Rocky Mountains and Other | Equity investment in WES, which owns and operates gas processing facilities | 5.8 Bcf/d | ||||||
| UAE | Natural gas processing facilities for Al Hosn Gas | 1.45 Bcf/d | ||||||
| Pipelines and Gathering Systems | ||||||||
| Texas, New Mexico and Colorado | CO2 fields and pipeline systems transporting CO2 to oil and gas producing locations | 2.8 Bcf/d | ||||||
| Qatar, UAE and Oman | Equity investment in the DEL natural gas pipeline | 3.2 Bcf/d | ||||||
| United States | Equity investment in WES involved in gathering and transportation | 14,910 miles of pipeline | ||||||
| OLCV | ||||||||
| Texas | Company-owned solar generation facility | 16.8 megawatts of electricity | ||||||
| Texas | Equity investment in a low emissions natural gas based power generation demonstration facility | up to 50 megawatts of electricity | ||||||
| Texas and Louisiana | Five CO2 sequestration hubs under development | over 310,000 acres | ||||||
(a)Amounts are gross, including interests held by third parties.
OXY 2025 FORM 10-K | 7 | ||||
| table of contents | RISK FACTORS | ||||||
ITEM 1A. RISK FACTORS
The following risk factors, as well as the other information included in this Form 10‑K, should be carefully considered. These risk factors are not exhaustive, and additional risks and uncertainties, whether known or unknown, or currently believed to be immaterial, may also adversely affect the Company. Additional risk factors may also be described in registration statements, prospectus supplements or other offering documents that the Company files in connection with the issuance of securities. Any of the risks, individually or in combination, could have a material adverse effect on the Company’s business, financial condition, results of operations, cash flows, reserves or the value of an investment in our securities. Although the risks are presented under separate headings, many are interrelated.
Volatile global and local commodity pricing strongly affects the Company’s results of operations.
The Company’s financial results correlate closely to the prices it obtains for its products, particularly oil and, to a lesser extent, NGL and natural gas. With the completion of the OxyChem Transaction, the Company’s business is more exposed to fluctuations in the markets for oil, NGL and natural gas. Historically, the markets for oil, NGL and natural gas have been volatile and may continue to be volatile in the future. Prices for oil, NGL and natural gas fluctuate widely. Prices are determined by global and local market forces which are not in the Company’s control. These factors include, among others:
•Domestic and international supplies of, and demand for, oil, NGL, natural gas and refined products;
•General economic conditions, including domestic or international economic slowdowns or recessions;
•The cost of exploring for, developing, producing, refining and marketing oil, NGL, natural gas and refined products;
•Operational impacts such as production disruptions, technological advances and regional market conditions, including available transportation capacity and infrastructure constraints in producing areas;
•Changes in weather patterns and climate;
•Actions by OPEC and non-OPEC oil producing countries;
•The domestic and international military and political environment, including uncertainty or instability resulting from an escalation or outbreak of armed hostilities or acts of terrorism in the United States or elsewhere;
•The price and availability of and demand for alternative and competing fuels;
•The effect of energy conservation efforts and technological advances affecting energy consumption and supply;
•Government policies and support and market demand for low-carbon technologies;
•Domestic and international laws, regulations, tariffs and taxes, shareholder activism or activities by advocacy groups that restrict the exploration, development, production, import or export of hydrocarbons and other products and goods;
•Additional or increased nationalization and expropriation activities by governments;
•The impact and uncertainty of significant health events, including pandemics and epidemics; and
•The effect of releases from or replenishment of the U.S. Strategic Petroleum Reserve.
The long-term effects of these and other conditions on the prices of oil, NGL and natural gas are uncertain and there can be no assurance that the demand or pricing for the Company’s products will follow historic patterns. Prolonged or substantial decline, or sustained market uncertainty, in these commodity prices may have the following effects on the Company’s business:
•Adversely affect the Company’s financial condition, results of operations, cash flows, ability to reduce debt, access to and cost of capital, and ability to finance planned capital expenditures or planned acquisitions, pay dividends or repurchase shares;
•Cause the Company to record impairments of its proved and unproved oil and gas properties;
•Reduce the amount of oil, NGL and natural gas that the Company can produce economically;
•Cause the Company to delay or postpone capital projects;
•Reduce the amounts of the Company’s estimated proved oil, NGL and natural gas reserves;
•Reduce the standardized measure of discounted future net cash flows relating to oil, NGL and natural gas reserves; and
•Adversely impact the ability of the Company’s partners to fund their working interest capital requirements.
Generally, the Company’s historical practice has been to remain exposed to the market prices of commodities at the corporate level. As of December 31, 2025, there were no commodity hedges in place. Management may choose to put hedges in place in the future for oil, NGL and natural gas commodities. Commodity price risk management activities may prevent the Company from fully benefiting from price increases and may expose it to regulatory, counterparty credit and other risks.
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Anadarko’s Tronox settlement may not be deductible for income tax purposes and the Company may be required to repay the tax refund Anadarko received in 2016 related to the deduction of the Tronox settlement payment.
The Company may be required to repay the $881 million tentative cash tax refund Anadarko received in 2016 before it was acquired by the Company, plus other related cash tax benefits received, plus applicable interest, which as of December 31, 2025, totaled approximately $2.3 billion, if the U.S. Tax Court determines that Anadarko’s $5.2 billion Tronox settlement payment related to a 2014 settlement agreement between Anadarko and Kerr-McGee is not deductible. The IRS disallowed the deduction, and the matter remains pending before the U.S. Tax Court following trial and closing arguments.
In accordance with ASC Topic 740’s guidance on the accounting for uncertain tax positions, the Company has not recorded a tax benefit for the tentative cash tax refund or for the additional cash tax benefits realized from the utilization of tax attributes associated with the claimed deduction. If the settlement payment is ultimately determined not to be deductible, the Company would be required to repay the tentative cash tax refund Anadarko received, plus other related cash tax benefits received, plus applicable interest. The Company has recorded an uncertain tax position for the estimated amount of taxes and interest that may be payable, which is not covered by insurance. For additional information on income taxes generally and the Tronox tax matter, see Note 9 - Income Taxes and Note 12 - Lawsuits, Claims, Commitments and Contingencies, respectively, in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
The Company’s indebtedness could limit financial flexibility and increase vulnerability to adverse conditions.
The Company’s level of indebtedness may make it more vulnerable to adverse changes in general economic or industry conditions and could limit the Company’s ability to respond to changing business conditions. Periodically, the Company has relied on access to capital markets for funding. The Company’s future access to capital markets and/or availability at favorable terms or at all will be subject to a number of factors, including general economic and market conditions such as rising interest rates, inflation or unstable or illiquid market conditions, investor sentiment, risks impacting financial institutions or the credit markets more broadly and/or the Company’s performance, credit ratings or ability to meet existing debt obligations. The Company is regularly evaluated by the major credit rating agencies based on numerous factors, including its financial strength, conditions affecting the oil and gas industry and commodity price outlooks. Any downgrade or announcement of a potential downgrade of the Company’s credit ratings could increase costs associated with indebtedness or impair the Company’s access to additional indebtedness, financial assurance or other forms of liquidity and such events may occur at unfavorable times due to changing economic and business conditions. If the Company is unable to generate sufficient funds from its operations or complete divestitures on favorable terms, or at all, to fund its capital requirements, including its existing debt obligations, or to raise additional capital on acceptable terms, the Company’s financial condition, results of operations, cash flows and/or stock price could be adversely affected.
Government actions, regulatory changes and political, economic and social instability may adversely affect the Company’s operations and results of operations.
The Company’s domestic and international operations are subject to extensive laws and regulations and may be adversely affected by the actions and decisions of many federal, state, local and international governments, political interests and advocacy groups.
Changes in U.S. and international tax laws, regulations and interpretations, as well as examinations by taxing authorities, could adversely affect the Company’s effective tax rate, financial condition and results of operations. Tax laws and their interpretation may change, including through repeal or modification of existing provisions, creating uncertainty regarding their impact on the Company’s tax obligations and cash flows. Additionally, the Company’s tax positions are subject to examination by tax authorities, and the resolution of such matters may differ from amounts recorded in the financial statements. Governments may increase existing taxes, eliminate tax incentives or enact new taxes, such as windfall profit taxes or taxes targeting the oil and gas industry. For example, the IRA enacted a 15% corporate alternative minimum tax (CAMT) and a 1% excise tax on net share repurchases. Furthermore, the recently enacted OBBBA made permanent the 21% corporate tax rate, reinstated 100% bonus depreciation on assets placed in service after January 19, 2025, reinstated the deduction for certain research and development expenses, adjusted deduction limits, imposed new environmental levies and imposed limitations on certain clean energy credits, which may change the Company’s tax liability and compliance costs. While the IRA and OBBBA expanded policy support for certain low-carbon projects and enhanced certain tax credits, these benefits remain subject to administrative action, regulatory interpretation and potential legislative repeal. For instance, recent executive orders and proposals to rescind or reduce funding for these programs create uncertainty regarding the long-term realization of such credits. Unfavorable changes, interpretations or audit outcomes or sunsetting of certain provisions could result in increased tax liabilities, interest and penalties. For additional discussion of some of these matters, see Note 9 - Income Taxes in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
Furthermore, instability and unforeseen changes in political, regulatory, economic and social environments in the markets where the Company operates could result in business disruptions, contractual or regulatory changes or operational challenges. As a result, the Company faces risks of, but not limited to, the following:
•Uncertain or volatile political, social and economic conditions;
•Political instability, social unrest, terrorism, war or armed conflict;
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•Public health crises or other catastrophic events, such as pandemics;
•Confiscatory taxation or other adverse tax policies or currency controls;
•Trade regulations, tariffs or sanctions;
•Theft of, or lack of sufficient legal protection for, proprietary technology and other intellectual property;
•Changes in laws, regulations or interpretation or enforcement practices, including those related to drilling, completions, production, environmental protection, taxation, royalties, trade and climate change;
•Restrictions on the repatriation of income or capital;
•Inflation, currency fluctuations or changes in global trade practices;
•Changes in the usage of the U.S. dollar in global trade;
•Expropriation, nationalization or loss of property rights;
•Delays or refusals in granting or renewing permits, licenses or contracts, including for exploration, development or production contracts or leases;
•Developmental delays and cost overruns due to approval delays for, or denial of, drilling, construction, environmental and other regulatory approvals, permits and authorizations; and
•Litigation, investigations or penalties arising from changes in law or government action or violation of laws or regulations.
The realization of any of these risks could increase costs, limit access to resources, delay or halt projects or restrict the Company’s ability to operate in certain jurisdictions. Such developments may also result in litigation, penalties or operational shutdowns. In addition, restrictions imposed by the U.S. or international governments could limit the Company’s ability to acquire or divest assets, repatriate earnings or maintain licenses and permits necessary for drilling and development. Domestic and international regulatory efforts are evolving, including the international alignment of such efforts, and the Company cannot predict what final regulations will be enacted, modified or reversed or what their ultimate impact on the Company’s business would be. Currency fluctuations and other economic uncertainties may further impact cash flows. Any of these factors could materially affect the Company’s financial condition, results of operations and cash flows.
The Company may be adversely affected by claims, litigation, government investigations and other proceedings.
The Company is subject to actual and threatened claims, litigation, assessments, investigations and other proceedings, including proceedings by governments and regulatory authorities, involving a wide range of issues, such as taxes, drilling, completions, production processes, commercial disputes, regulatory compliance, environmental remediation and health and safety. In addition, in connection with the OxyChem Transaction, the Company retained environmental liabilities relating to legacy sites. Furthermore, there are post-closing indemnification obligations for, among other items, (i) such legacy environmental liabilities and (ii) pre-closing liabilities of OxyChem, including pre-closing environmental liabilities, in each case subject to certain limitations and procedures, and Occidental entered into a guaranty in favor of Berkshire Hathaway to guarantee those indemnification obligations of its subsidiaries. The outcomes of these matters are inherently unpredictable and subject to significant uncertainties. Determining legal reserves or reasonably possible losses from such matters involves judgment and may not reflect the full range of uncertainties and unpredictable outcomes. Until the final resolution of such matters, the Company may be exposed to losses in excess of the amounts recorded, and such amounts could be material. Should any of its estimates and assumptions change or prove to have been incorrect, it could have a material adverse effect on the Company’s financial condition, results of operations and cash flows. For additional discussion of some of these matters, see Note 11 – Environmental Liabilities and Expenditures and Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
The Company is subject to operational hazards and catastrophic events.
The Company’s operations, both onshore and offshore, face risks and hazards inherent to operating in the energy industry. These include well blowouts, fires, explosions, pipeline ruptures, spills, emissions or releases of regulated materials into the soil, surface water, ground water or the marine environment, material or mechanical failures, power outages, industrial accidents, abnormally pressured or structured formations, severe weather events (such as hurricanes, floods, freezes, heat waves or droughts), land deformations (such as earthquakes, landslides or subsidence), other acts of nature, pandemics, physical or cyber-attacks, terrorist attacks, piracy and other events that cause operations to be curtailed or cease. Coastal and offshore operations are particularly susceptible to disruption from severe weather events. The aforementioned events may present acute risks, such as specific storms or wildfires, or chronic risks, such as sea level rise or water scarcity. Any of these risks could adversely affect the Company as a result of:
•Injuries or impacts to the Company’s workforce and local communities;
•Damage to or destruction of property and equipment, including property and equipment owned by third parties which the Company’s operations rely upon;
•Damage to natural resources;
•Pollution or other environmental damage;
•Regulatory investigations, claims, fines or penalties;
•Loss of well location, acreage, expected production or related reserves;
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•Suspension or delay of permits or operations or closure of facilities;
•Substantial liability claims;
•Significant response, repair or remediation costs that negatively impact the Company’s breakeven economics;
•Demand for or deployment of significant resources including capital, personnel, materials and equipment to respond to an event; and
•Legislative or regulatory changes resulting from an event.
The Company conducts offshore operations in the Gulf of America and international locations through certain subsidiaries. Offshore operations are vulnerable to unique risks in addition to those listed above, including deep-water technical complexity, logistical and security challenges, a limited number of partners available to participate in projects and more stringent permitting and regulatory requirements. The Company may also face longer recovery times and higher remediation costs for offshore incidents compared to onshore operations. Deep-water projects (greater than 1,000 feet) are especially challenging and costly due to limited infrastructure and support services, often requiring more time between discovery and ability to market production, thereby increasing commercial and operational risk. These factors can increase the potential for and impact of catastrophic events, which could result in significant operational disruption, increased costs or loss of production and could have a material adverse effect on the Company’s financial condition, results of operations, cash flows and reserves.
Health, safety and environmental laws and regulations and climate-related policies could have a material adverse effect on the Company’s financial condition, results of operations and cash flows.
The Company’s operations, properties and assets are subject to extensive health, safety and environmental laws and regulations, including those governing drilling, completions, production, GHG and other air emissions, water use and discharges, waste management, environmental remediation and protection of wildlife and ecosystems. The requirements of these laws and regulations are complex, stringent and expensive to implement. Costs of compliance with these laws and regulations are significant and can be unpredictable and may require significant capital investment and operating costs, and violations can result in penalties, operational restrictions or cessation of operations in affected areas. In addition, evolving climate-related policies, such as those related to CCUS, monitoring, reporting or control of methane and other GHG emissions, and carbon pricing and associated allowances, credits, taxes, fees or incentives, as well as recent legislative developments such as the OBBBA, could increase costs or reduce demand for certain products. Some of these laws and regulations provide for strict, joint and several liability, and the Company could be liable for the actions of others, including prior owners or operators of properties or other assets.
Collectively, international, federal, state and local government and private actions relating to air emissions may require the Company to incur additional operating and maintenance costs, including for service providers and costs to purchase, operate and maintain emissions control systems, acquire emission allowances or credits, pay taxes or fees for methane and other GHG emissions or comply with new regulatory or reporting requirements. They could also affect permitting or other regulatory approvals or prevent the Company from conducting oil and gas development activities in certain areas. In addition, they could promote the use of alternative sources of energy and thereby decrease demand for the Company’s oil, NGL, natural gas and other products. Future legislation or regulatory or market changes could also increase the cost of consuming or reduce demand for the Company’s products and thereby lower the value of the Company’s reserves, potentially resulting in impairments. Consequently, actions designed to reduce GHG or other air emissions could cause the Company to make changes with respect to its business plan, operations or assets that may have an adverse effect on its financial condition, results of operations, cash flows and reserves.
It is difficult to predict the timing, likelihood and scope of such government and private actions and their ultimate effect on the Company, which could depend on, among other things, the type and extent of air emissions reductions required, the availability and price of emission allowances or credits, carbon accounting standards, the availability and price of alternative fuel sources, the energy sectors covered, market conditions (including consumer responsiveness to such changes), the Company’s ability to recover the costs incurred through its operating agreements or the pricing of its oil, NGL, natural gas and other products and whether service providers are able to pass increased costs through to the Company.
The Company uses and generates regulated substances in its operations, which have resulted in, and may in the future result in, further environmental remediation costs. The Company discloses on a consolidated basis the amounts currently recorded for environmental remediation with respect to existing conditions from alleged past practices at the sites the Company is currently monitoring and the range of reasonably possible additional losses at those sites beyond the amounts currently recorded. For additional discussion of such matters, see Note 11 – Environmental Liabilities and Expenditures and Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K. In addition, stricter enforcement, changing interpretations or reversal of existing laws and regulations, the enactment of new laws and regulations, the discovery of previously unknown contamination or the imposition of new or increased requirements could require the Company to incur costs or become the basis for new or increased liabilities that could have a material adverse effect on its financial condition, results of operations and cash flows.
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The Company’s carbon management and sustainability initiatives and strategic objectives involve significant risks and uncertainties.
The Company’s aspirations, goals, initiatives and investments related to carbon management, DAC and sustainability, and the execution of its broader business strategies, expose it to significant financial, operational, regulatory, technological, legal, market, reputational and other risks. The Company’s results of operations depend on the extent to which it can execute new business strategies effectively, particularly in the context of climate-related policies that seek to lower carbon intensity, and evolving laws, regulations and government and private actions regarding the environment and climate change.
Efforts to reduce GHG emissions, other air emissions and carbon intensity and to advance sustainability initiatives are subject to numerous uncertainties and contingencies, many of which are beyond the Company’s control. These include evolving market conditions (such as demand for carbon sequestration and related CO2 removal credits, allowances or other attributes), supply chain constraints or delays (such as with respect to raw materials, equipment and electrical infrastructure), changes in the Company’s portfolio and the availability of grants, loans or tax deductions, incentives or credits (including, as applicable, the transferability thereof).
Certain of the Company’s strategic goals depend on the successful implementation of new and existing technologies on a commercial scale, including the deployment of DAC technology, start-up operations at STRATOS and the development of proposed CCUS projects. These technologies are in various stages of development or implementation and may require more capital, or take longer to develop, than currently expected. The Company may also be required to develop or implement additional technologies at substantial cost, and effective execution of these initiatives may necessitate significant new capital, which might not be available in the amounts or at the times anticipated. Any such capital‑raising activities could increase the Company’s leverage or overall cost of doing business. There is also a risk that some of these technologies may not perform as intended, may fail to achieve commercial viability, or may never develop to the stage necessary to support the Company’s long‑term plans. Further, these carbon management technologies are in competition with technologies being developed by governments and other companies, and the market for carbon sequestration and related CO2 removal credits, allowances or other attributes is not well established. If this market does not develop, or if the regulatory environment does not support carbon management activities, the Company may not be successful in the carbon management industry.
Sustainability-related disclosures rely on developing standards, assumptions and methodologies that may continue to change, and new or amended rules could require the Company to modify reported goals or incur additional compliance costs. The Company may face scrutiny from investors, customers, advocacy groups and regulators, and failure, or perceived failure, to meet goals or reporting expectations could result in reputational harm, litigation or enforcement actions. Divergent stakeholder views, legislation and government policies on environmental and social matters may affect the Company’s access to capital, cost of financing and business relationships.
The Company’s low-carbon investments in subsidiaries, property, intangibles and goodwill are subject to impairment testing. If these initiatives do not perform as intended or fail to achieve commercial viability or markets do not develop, the Company may impair those assets. Future costs associated with reducing emissions and carbon intensity, as well as impacts resulting from other risk factors described herein, could lead to impairments in the future, particularly if such costs significantly impact the Company’s breakeven economics. These factors could materially impact the Company’s financial condition, results of operations and cash flows.
The Company operates in highly competitive environments and may not be able to source production or replace reserves.
Oil and gas reservoirs are characterized by declining production rates. Unless the Company conducts successful exploration or development activities, acquires properties containing proved reserves, or both, proved reserves will generally decline and negatively impact the Company’s revenue. Reserve replacement is subject to factors such as geology, government regulation, permitting, capital availability, commodity prices, costs of oilfield goods and services and the effectiveness of development plans, many of which are partially or fully outside of management’s control.
The exploration and production of oil, NGL and natural gas is a highly competitive business. The Company has many competitors (including national oil companies), some of which are larger and better funded, more risk-tolerant, have greater access to capital, technology and talent or have special competencies. As competitors develop or adopt new technologies (including artificial intelligence), the Company may be placed at a disadvantage and may be required to invest significant resources to remain competitive.
Competition for access to reserves may make it more difficult to find attractive investment opportunities or require delay of reserve replacement efforts. Further, during periods of low product prices, any cash conservation efforts may delay production growth and reserve replacement efforts. Also, there is substantial competition for capital available for investment in the oil and gas industry. The Company may be unable to acquire properties, grow production or replace reserves.
In addition, the Company’s acquisition activities carry risks including the potential for less-than-expected reserves or production or changed circumstances, such as declines in oil, NGL and natural gas prices, unexpected integration costs or difficulties, share price declines based on the market’s evaluation of the activity or unforeseen liabilities.
The Company may not be successful in finding, developing or acquiring additional reserves, and its efforts may not be economic. The value of Occidental’s securities and its ability to raise capital will be adversely impacted if it is not able to replace reserves that are depleted by production or replace its declining production with new production by successfully allocating capital to maintain its reserves and production base.
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The Company’s oil and gas reserves and other significant financial statement items are estimates based on professional judgment and may be subject to revision.
Reported oil and gas reserves are estimates based on professional judgment and numerous assumptions regarding geophysical, engineering, technical and economic factors. The procedures and methods for estimating the reserves by the Company’s internal engineers have been reviewed by independent petroleum consultants. However, those procedures and methods are complex and require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and the resulting estimated oil and gas reserves are therefore inherently uncertain and may be estimated differently by different engineers, even when analyzing the same data. Actual production, revenues, expenditures, oil, NGL and natural gas prices and taxes with respect to the Company’s reserves may vary from estimates and the variance may be material.
In addition, the discounted cash flows included in this Form 10-K should not be construed as the fair value of the reserves attributable to the Company’s properties. The estimated discounted future net cash flows from proved reserves are based on an unweighted arithmetic average of the first-day-of-the-month price for each month within the year in accordance with SEC regulations. Actual future prices and costs may differ materially from SEC regulation-compliant prices and costs used for purposes of estimating future discounted net cash flows from proved reserves. Also, actual future net cash flows may differ from these discounted net cash flows due to the amount and timing of actual production, availability of financing for capital expenditures necessary to develop the Company’s undeveloped reserves, supply and demand for oil, NGL or natural gas, increases or decreases in consumption of oil, NGL or natural gas and changes in government regulations or taxation.
In preparing its periodic reports and financial statements, the Company is required to make estimates and assumptions as of a specified date. These estimates and assumptions, including those related to oil and gas or other reserves, are based on management’s best knowledge and experience at the time, but are subject to substantial uncertainty. Changes in business plans, market conditions, commodity prices, and the pace of energy transition or new information may materially differ from estimates. If these estimates and assumptions prove to be inaccurate or materially differ from actual results, the Company’s financial position, results of operations and cash flows could be adversely affected.
The Company may experience delays, cost overruns, losses or unrealized expectations in development efforts and exploration activities.
Oil, NGL and natural gas exploration and production activities are subject to numerous risks beyond the Company’s control, including the risk that drilling will not result in commercially viable oil, NGL or natural gas production. In its development and exploration activities, the Company bears the risks of:
•Equipment failures;
•Construction delays;
•Escalating costs for, competition for, shortages of or delays in services, materials, supplies, equipment or labor or other supply chain constraints;
•Increasing prices as a result of inflation;
•Disappointing drilling results or reservoir performance;
•Actions by third-party operators of its properties;
•Delays imposed by or resulting from compliance with permits, laws, regulations or litigation and costs of drilling wells on lands subject to complex development terms or circumstances;
•Oil, NGL and natural gas gathering, transportation and processing availability, restrictions or limitations; and
•Title, property or access issues or border disputes and other associated risks that may affect its ability to profitably grow production, replace reserves and achieve its targeted returns.
Exploration is inherently risky and is subject to delays, misinterpretation of geologic or engineering data, unexpected geologic conditions or finding reserves of disappointing quality or quantity, which could have a material adverse effect on the Company’s financial condition, results of operations, cash flows and reserves.
The Company’s operations could be adversely affected if it is unable to source water or sand or dispose of surplus fluids.
Water and sand are essential inputs for the exploration and production of oil and gas. The Company’s ability to obtain water or sand for its operations may be affected by factors such as regional supply and demand, price volatility, transportation availability and other market conditions. Additionally, some government authorities have restricted the use of water subject to their jurisdiction for hydraulic fracturing. Restrictions on sourcing water or sand, increased costs or regulatory changes affecting the use of these inputs could disrupt operations, increase expenses or limit production. Compliance with evolving environmental regulations or shortages of water or sand may require the Company to curtail activities or incur additional costs. As a result, the Company may be unable to economically produce oil, NGL and natural gas, which could have a material adverse effect on its financial condition, results of operations and cash flows.
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The Company must also dispose of the surplus fluids produced from oil and gas operations, including produced water, either directly or through the use of third-party vendors. Legal requirements related to the subsurface injection of produced water are subject to change. In response to increased seismic activity, some states have curtailed water disposal and suspended disposal permits in seismic response areas (SRAs), particularly in deep disposal wells, and adopted additional regulations governing produced water disposal and recycling. While the Company has retained the ability to dispose of surplus produced water under applicable guidelines and regulations, increased seismicity and formation pressures, or responses to such events by agencies and companies, such as curtailing or relocating disposal, could impact the location, timing and cost of development programs and existing operations, particularly in or near SRAs. Restrictions or higher operating costs as a result of more stringent regulations, permits or government directives, potential litigation or other developments could materially impact the Company’s ability to dispose of produced water, which could have a material adverse effect on its financial condition, results of operations and cash flows.
The Company’s production from CO2 EOR operations may decline if it is unable to obtain sufficient amounts of CO2.
CO2 EOR operations are critical to the Company’s long-term strategy. Oil production from these projects depends on reliable access to sufficient amounts of naturally occurring or anthropogenic (human-made) CO2. Supply disruptions due to, among other things, CO2 producing well and facility issues, third-party failures, regulatory constraints or market conditions could limit CO2 availability and delay or reduce production. This could have a material adverse effect on the Company’s financial condition, results of operations or cash flows.
Acquisitions, divestitures and other transactions may cause financial results to differ from the Company’s or investors’ expectations, may not deliver anticipated benefits and could disrupt current operations.
The success of acquisitions, divestitures and other transactions will depend, in part, on the Company’s ability to successfully complete and realize the anticipated benefits of such transactions. Both acquisitions and divestitures (including the OxyChem Transaction) and associated restructuring may result in the Company bearing unforeseen or greater liabilities, costs, tax consequences or regulatory or contractual issues than anticipated and divert management’s attention from ongoing business operations. In addition, in the case of acquisitions, difficulties in integrating businesses or employees may result in the failure to realize anticipated results, benefits and synergies in the expected timeframes and in operational challenges. Any of the foregoing risks associated with acquired or divested properties or businesses may have an adverse impact on the Company’s financial condition, operating results or cash flows. For further information on such transactions, see Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
An Occidental subsidiary acts as the general partner of WES, a publicly traded master limited partnership, which may involve potential legal liability.
An Occidental subsidiary, Western Midstream Holdings, LLC, acts as the general partner of WES, a publicly traded master limited partnership. Its general partner interest in WES may increase the possibility that it could be subject to claims of breach of duties owed to WES, including claims of conflict of interest. Any such claims could increase the Company’s costs and any liability resulting from such claims could have a material adverse effect on the Company’s financial condition, operating results or cash flows.
The Company is exposed to cybersecurity, digital infrastructure and data security risks.
The Company relies on technology to enable its business operations. The increasing use of digital technology, information technology and operational technology, including services and networks maintained by the Company as well as third parties, exposes the Company to evolving threats, including unauthorized access, ransomware or other malware, service disruptions, threats to the security of facilities and infrastructure, cyber terrorism, critical infrastructure attacks, supply chain attacks and other attacks on third-party vendors. Cyber incidents, whether from insiders or external actors, such as criminals, hacktivists or nation state threat actors, could disrupt operations or compromise sensitive information, which may impact the Company’s reputation, result in regulatory penalties or result in financial losses.
Technology failures, network disruptions and breaches of data security could disrupt the Company’s operations in numerous ways, including by causing accidents, delays or losses and impacts to the Company’s workforce, customers and local communities, impeding processing of transactions and reporting financial results, and leading to the unintentional disclosure of Company, partner, customer or employee information. In addition, the Company faces risks related to the unauthorized access, theft or misuse of proprietary information, including intellectual property, trade secrets and sensitive business data. These risks may arise not only from external actors but also from current or former insiders, including former employees, contractors or other parties with prior access to the Company’s systems. Loss or compromise of proprietary information could adversely impact the Company’s competitive position, strategic initiatives or business relationships. The Company also has exposure to cybersecurity risks where its systems, data and proprietary information are accessed, collected, hosted and/or processed by third-party cloud and other service providers. The Company also faces increased risk with the growing sophistication of artificial intelligence capabilities, which may improve or expand the existing capabilities of
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cyber threat actors. While the Company uses advanced technologies, including AI-based tools, to strengthen its defenses and support business operations, such measures may not be successful in preventing or mitigating cyber threats.
Moreover, laws and regulations governing cybersecurity and data privacy and the unauthorized disclosure of confidential, regulated or protected information pose increasingly complex compliance challenges and potential costs, and any failure to comply with these requirements or other applicable laws and regulations in this area could result in significant regulatory penalties or other legal liabilities.
Despite robust cybersecurity measures, the Company has experienced cyber-attacks in the past and expects such threats to continue to evolve, including increasing in magnitude and sophistication. The cyber risk landscape changes over time due to a variety of internal and external factors, including during geopolitical tensions and as a result of technological developments. There can be no assurance that the Company’s cybersecurity and operational resilience measures, or the efforts of its partners, will be sufficient to prevent, identify or effectively address cybersecurity incidents. The Company may incur significant increased costs in order to continue to enhance its cybersecurity measures and to investigate and remediate cybersecurity incidents. A significant cyber incident could have a material adverse affect on the Company’s financial condition, results of operations or cash flows.
Insurance does not cover all risks, which could result in significant financial exposure.
Third-party insurance may not provide adequate, or any, coverage with respect to the risks the Company faces or the Company may be self-insured or uninsured with respect to the related losses. In addition, under certain circumstances, the Company may be liable for environmental conditions on properties that it currently owns, leases or operates that were caused by previous owners or operators of those properties. As a result, the Company may incur substantial liabilities to third parties or government entities for which it does not have sufficient insurance coverage, which could reduce or eliminate funds available for exploration, development, acquisitions or other investments, or cause it to incur losses. The Company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that arise from time to time, but there can be no assurance that those sources will be available or adequate. The occurrence of a significant incident, series of events or unforeseen liability for which the Company is self-insured, not fully insured or uninsured or for which the insurance recovery is significantly delayed could have a material adverse effect on the Company’s financial condition, results of operations and cash flows.
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| table of contents | OTHER INFORMATION | ||||||
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
RISK MANAGEMENT AND STRATEGY
The Company has developed a robust cybersecurity program which is reviewed by senior leadership including its CIO and other stakeholders as part of its standard general IT controls. Business network and ICS cybersecurity risks are handled by separate and dedicated Company teams and are incorporated into the Company’s enterprise risk management program.
The Company has implemented and maintains a cybersecurity incident response plan that provides the organizational and operational protocol for the Company to effectively and timely respond to cybersecurity incidents. In the event of a material cybersecurity incident, the Company’s CIO will receive regular updates and monitor detection, mitigation and remediation through reports from a team of experienced cybersecurity leaders responsible for actioning the Company’s cybersecurity incident response plan. As a material cybersecurity incident is handled by the team, the CIO will maintain communication and information flow to senior leadership as well as the Audit Committee and/or the Board, as appropriate. Cybersecurity risks and associated mitigation strategies and efforts are analyzed by senior leadership as part of the enterprise risk assessments that are reported to and discussed by the Board.
GOVERNANCE
BOARD
SENIOR MANAGEMENT
The Company’s CIO , who has over 20 years of IT and cybersecurity experience at the Company and elsewhere, heads the team responsible for implementing and maintaining cybersecurity and data protection practices across the Company’s businesses and reports directly to the President and CEO. The Company has a centrally coordinated team, led by its CIO, responsible for implementing and maintaining cybersecurity and data protection practices across the Company. The Company’s CIO regularly reviews risk management measures and the overall cyber risk strategy implemented and maintained by the Company. The CIO receives regular updates on the Company’s cybersecurity program and monitors the
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ITEM 3. LEGAL PROCEEDINGS
The Company has elected to use a $1 million threshold for disclosing certain proceedings arising under federal, state or local environmental laws when a government authority is a party and potential monetary sanctions are involved.
In September 2025, the New Mexico Environment Department (the Department) proposed a penalty amount to resolve alleged delayed reporting under the Department’s rules of two emission events in 2020 at an Occidental subsidiary’s facility in Lea County, New Mexico. The subsidiary is actively pursuing resolution of this matter with the Department.
For information regarding legal proceedings, see the information under Lawsuits, Claims, Commitments and Contingencies in the Management’s Discussion and Analysis section of this Form 10-K and in Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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| INFORMATION ABOUT EXECUTIVE OFFICERS | ||
Each executive officer holds his or her office from the date of election by the Board of Directors until the first board meeting held after the next Annual Meeting of Stockholders or until his or her removal or departure or a successor is duly elected, if earlier.
The following table sets forth the executive officers of the Company as of February 18, 2026:
Name Current Title | Age as of February 18, 2026 | Positions with the Company and Employment History | ||||||
Christopher O. Champion Vice President, Chief Accounting Officer and Controller | 56 | Vice President, Chief Accounting Officer and Controller since August 2019; Anadarko Petroleum Corporation: Senior Vice President, Chief Accounting Officer and Controller, 2017-2019, Vice President, Chief Accounting Officer and Controller, 2015-2017. | ||||||
Kenneth Dillon Senior Vice President and President International Oil and Gas Operations | 66 | Senior Vice President since December 2016; President – International Oil and Gas Operations since June 2016. | ||||||
Vicki Hollub President and Chief Executive Officer | 66 | President, Chief Executive Officer and Director since April 2016. | ||||||
Richard A. Jackson Senior Vice President and Chief Operating Officer | 49 | Senior Vice President and Chief Operating Officer since October 2025; President Operations U.S. Onshore Resources and Carbon Management 2020-2025; President and General Manager, EOR and Oxy Low Carbon Ventures, LLC, 2020; President Low Carbon Ventures, 2019-2020; Senior Vice President, Operation Support, 2018-2019; Vice President, Investor Relations, 2017-2018; President and General Manager Permian Resources Delaware Basin, 2014-2017. | ||||||
Sylvia J. Kerrigan Senior Vice President and Chief Legal Officer | 60 | Senior Vice President and Chief Legal Officer since October 2022; Executive Director of the Kay Bailey Hutchison Energy Center for Business, Law and Policy at The University of Texas, 2017-2022; Executive Vice President, General Counsel and Corporate Secretary of Marathon Oil Corporation, 2009-2017. | ||||||
Sunil Mathew Senior Vice President and Chief Financial Officer | 55 | Senior Vice President and Chief Financial Officer since August 2023; Vice President, Strategic Planning, Analysis and Business Development, 2020-2023; Vice President, Strategic Planning and Analysis, 2014-2020. | ||||||
Robert L. Peterson Senior Vice President | 55 | Senior Vice President since April 2020; Executive Vice President, Essential Chemistry, 2023-January 2026; Chief Financial Officer, 2020-2023; Senior Vice President, Permian EOR, 2019-2020; Vice President, Permian Strategy, 2018-2019; Director, Permian Business Area, 2017-2018; President, OxyChem, 2014-2017. | ||||||
Jeff F. Simmons Senior Vice President and Chief Petrotechnical Officer | 66 | Senior Vice President, Subsurface Technology since February 2026 and Chief Petrotechnical Officer since January 2021; Senior Vice President, Technical and Operations Support, 2021-2026; Senior Vice President, Technical Planning and Evaluation, 2017-2021; Executive Vice President, Growth and Operations Support, 2016-2017. | ||||||
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Part II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
| MARKET INFORMATION, HOLDERS AND DIVIDEND POLICY | ||
Occidental’s common stock is listed and traded on the NYSE under the ticker symbol “OXY.” The common stock was held by approximately 21,000 stockholders of record as of January 31, 2026, which does not include beneficial owners for whom Cede and Co. or others act as nominees.
The Company declared dividends of $0.96 per share in 2025. On February 18, 2026, the Board of Directors declared a regular quarterly dividend of $0.26 per share on common stock, over an 8% increase from the previous quarter, payable in April 2026. The declaration of future dividends is a business decision made by the Board of Directors from time to time and will depend on the Company’s financial condition and other factors deemed relevant by the Board of Directors.
| SHARE REPURCHASE PROGRAM | ||
In February 2023, the Company announced a share repurchase program to repurchase up to $3.0 billion of Occidental’s shares of common stock. The program does not obligate the Company to acquire any specific number of shares and may be discontinued at any time. The value remaining in the Company’s share repurchase program as of December 31, 2025 was $1.2 billion. There were no share repurchases under the Company’s share repurchase program in 2025.
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| PERFORMANCE GRAPH | ||
The following graph compares the yearly percentage change in the Company’s cumulative total return on its common stock with the cumulative total return of the S&P 500, which includes the Company, and with the Company’s peer group over the five-year period ended December 31, 2025. The graph assumes that $100 was invested at the beginning of the five-year period shown in the graph below and that all dividends were reinvested in: (i) Occidental common stock (ii) the stock of the companies in the S&P 500; and (iii) each of the peer group companies’ common stock weighted by their relative market capitalization within the peer group.
The Company’s peer group consists of BP p.l.c., Chevron Corporation, ConocoPhillips, EOG Resources, Inc., ExxonMobil Corporation, Shell and TotalEnergies.
| Fiscal Year Ended December 31, | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | ||||||||||||||
Occidental | $ | 100 | $ | 168 | $ | 367 | $ | 353 | $ | 296 | $ | 252 | ||||||||
| Peer Group | $ | 100 | $ | 147 | $ | 236 | $ | 235 | $ | 234 | $ | 268 | ||||||||
| S&P 500 | $ | 100 | $ | 129 | $ | 105 | $ | 133 | $ | 166 | $ | 196 | ||||||||
The information provided in this Performance Graph shall not be deemed “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C under the Exchange Act, other than as provided in Item 201 to Regulation S-K under the Exchange Act, or subject to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent the Company specifically requests that it be treated as soliciting material or specifically incorporates it by reference.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8 and the information set forth in Risk Factors under Part 1, Item 1A. The following sections include a discussion of results for fiscal 2025 compared to fiscal 2024 as well as certain 2023 results. The comparative results for fiscal 2024 with fiscal 2023 generally have not been included in this Form 10-K, but may be found in “Part II - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024.
| INDEX | PAGE | ||||
Current Business Outlook and Strategy | 22 | ||||
Oil and Gas Segment | 24 | ||||
Midstream and Marketing Segment | 34 | ||||
Segment Results of Operations and Items Affecting Comparability | 36 | ||||
Consolidated Results of Operations | 39 | ||||
Income Taxes | 42 | ||||
Liquidity and Capital Resources | 43 | ||||
Lawsuits, Claims, Commitments and Contingencies | 45 | ||||
Environmental Expenditures | 46 | ||||
Global Investments | 46 | ||||
Critical Accounting Policies and Estimates | 47 | ||||
Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data | 51 | ||||
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| CURRENT BUSINESS OUTLOOK AND STRATEGY | ||
GENERAL
The Company’s financial results are significantly influenced by oil prices, and to a lesser extent, NGL and natural gas prices, and commodity market differentials. Oil prices have been and are expected to remain volatile due to shifts in energy supply and demand, ongoing geopolitical factors and OPEC supply actions. In 2025, compared to 2024, the average annual WTI price per barrel decreased to $64.81 from $75.72, and the average annual Brent price per barrel decreased to $68.18 from $79.79.
The Company’s costs are influenced by inflationary trends, market conditions, the availability and cost of oilfield services, electricity, and CO₂, and other operational expenditures. In April 2025, a U.S. tariff policy was announced that imposed a 10% base tariff rate on most imports, with higher rates applied to certain countries. Since then, the U.S. has negotiated trade deals, and certain tariff rates have been adjusted or paused amid ongoing litigation. These tariffs may increase the Company’s supplier costs and affect demand and prices for its products. The Company works to manage inflation impacts by capitalizing on operational efficiencies, locking in pricing on longer-term contracts and working closely with vendors to secure the supply of critical materials. Seasonality is not a primary driver of changes in the Company’s consolidated quarterly earnings.
STRATEGY
The Company is focused on delivering a unique shareholder value proposition with its portfolio of oil and gas and midstream and marketing assets, as well as its ongoing development of carbon management and storage solutions and GHG emissions reduction efforts. The Company conducts its operations with a priority on HSE, sustainability and social responsibility. In order to maximize shareholder returns, the Company will:
■ Maintain production base to preserve asset base integrity and longevity;
■Deliver a sustainable and growing dividend;
■Prioritize excess cash flow and proceeds from divestitures, including the OxyChem Transaction, for deleveraging until principal debt is approximately $14.3 billion, after which available cash will be allocated to opportunistic share repurchases and/or further net debt reduction;
■Enhance its asset base with investments in its cash-generative oil and gas business; and
■Advance integrated technologies in CO2, power and midstream to enable differentiated resource recovery and value.
OXYCHEM TRANSACTION
In October 2025, the Company announced entry into a purchase and sale agreement with Berkshire Hathaway to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion. The sale was completed on January 2, 2026, resulting in an estimated gain of $3.2 billion, net of taxes and subject to post-closing adjustments. As a result, OxyChem’s results of operations, cash flows and the related retained liabilities and indemnification obligations are reported as discontinued operations in the Company’s Consolidated Statements of Operations and Cash Flows for all periods presented, with its assets and liabilities reclassified as held for sale in the Company’s Consolidated Balance Sheets.
An Occidental subsidiary, Environmental Resource Holdings, LLC (ERH), has retained legacy tort claims and environmental liabilities primarily associated with historical operations outside of the footprint of the operating facilities that were sold. Glenn Springs Holdings, Inc. will continue to manage the remedial activities at environmental sites on behalf of ERH. The Company expects to expend funds for remediation over many years based on the approved workplans.
CAPITAL INVESTMENT
In 2025, the Company invested $5.6 billion in high-return oil and gas assets to generate long-term free cash flow throughout the commodity cycle. In the midstream and marketing segment, the Company invested $0.7 billion before contributions from noncontrolling interest, primarily related to STRATOS.
DEBT
In 2025, the Company used proceeds from divestitures and cash on hand to repay approximately $4.0 billion of debt. Subsequent to December 31, 2025, but before the date of this filing, the Company used proceeds from the OxyChem Transaction to pay or satisfy and discharge an additional $5.4 billion of debt.
As of the date of this filing, the principal debt outstanding was approximately $15 billion, of which $24 million is due in 2026, $48 million in 2027, $14 million in 2028, $367 million in 2029 and $14.6 billion due in 2030 and thereafter.
For detailed information on the Company’s debt activity, see Note 5 - Long-Term Debt in the notes to the Consolidated Condensed Financial Statements in Part II, Item 8 of this Form 10-K.
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SHAREHOLDER RETURN PRIORITIES
Capital is returned to shareholders through the Company’s dividend and share repurchases. In 2025, the Company declared dividends to common shareholders of $945 million, or $0.96 per share. As of December 31, 2025, $1.2 billion remained of the Company’s $3.0 billion share repurchase program, which the Board authorized in February 2023. After using the proceeds from the OxyChem Transaction to reduce the principal of outstanding debt to approximately $15 billion, the Company’s shareholder return priorities are to continue to provide a sustainable and growing dividend and further reduce principal debt to approximately $14.3 billion. Available cash will be allocated, as appropriate, to opportunistic share repurchases and/or further debt reduction.
SUSTAINABILITY STRATEGY
The Company’s sustainability strategy is organized around four pillars: principles of governance, people, planet, and prosperity. The Company integrates these sustainability pillars into our strategic planning and investment decision-making processes.
In 2020, the Company was the first U.S. oil and gas company to announce goals to achieve net-zero GHG emissions for its total emissions inventory including use of sold products. These goals include achieving net-zero GHG emissions (i) from its operations and energy use before 2040, with an ambition to do so before 2035, and (ii) from its total carbon inventory, including the use of its sold products, with an ambition to do so before 2050. In 2020, the Company also set various interim targets, including 2025 carbon and methane intensity targets, and the Company was the first U.S. oil and gas company to endorse the World Bank’s initiative for zero routine flaring by 2030. In 2022, the Board of Directors adopted the Company’s updated HSE and Sustainability Principles, based on engagement with shareholders, employees and other stakeholders. The HSE and Sustainability Principles reinforce the alignment among the Company’s core values, goals and strategies, underpin its Operating Management System, and help to guide the workforce across its operations. In 2023, the Company was an original signatory to the Oil and Gas Decarbonization Charter, committed funding to the World Bank’s Global Flaring and Methane Reduction Partnership, and established a new, medium-term 2030 methane intensity target. In 2025, the Company established a new, medium-term 2030 CO2 equivalent intensity target.
The Company seeks to meet its sustainability and environmental goals by implementing practices and technologies to reduce operational emissions coupled with its development and commercialization of technologies that lower both GHG emissions from industrial processes and existing atmospheric concentrations of CO2. The Company believes that carbon removal technologies, including DAC and CCUS, can, with incentives necessary for their development and deployment, provide essential CO2 reductions to assist the world’s transition to a lower carbon-intensive economy. Through fiscal 2024, the Company reduced estimated methane emissions by approximately 78.6% from 2019 and 40% from 2023, along with a 28.7% reduction in CO2 equivalent emissions since 2019. The following actions helped the Company advance its low-carbon business strategy in 2025:
■Completed construction of STRATOS central processing facilities and obtained Class VI permits to sequester CO2, with operations expected to begin in 2026.
■Actively progressed its sequestration hub plans, with five sequestration hubs in various stages of development primarily in the Permian Basin and across the Texas and Louisiana Gulf Coast; and
■Implemented emissions reduction projects involving hundreds of facilities and wells and thousands of pieces of equipment across its oil and gas operations.
The future costs associated with emissions reduction, carbon removal and CCUS to meet the Company’s long-term net-zero GHG goals may be substantial and the execution of its plans and net-zero pathway depends on securing third-party capital investments. As reflected by the joint venture with BlackRock, the Company is pursuing multiple avenues to fund these projects including project financing, long-term carbon removal or CCUS agreements, and identifying business opportunities with stakeholders in carbon-intensive industries.
KEY PERFORMANCE INDICATORS
The Company seeks to meet its strategic goals by continually measuring its success against key performance indicators that drive total stockholder return. In addition to efficient capital allocation and deployment discussed below in the section titled “Oil and Gas Segment - Business Strategy,” the Company believes its most significant performance indicators are:
OPERATIONAL
■Total spend per barrel - In 2026, the Company will continue our emphasis on controlling total costs from a per-barrel perspective. Total spend per barrel is the sum of capital spending, general and administrative expenses, other operating and non-operating expenses and oil and gas lease operating costs divided by global oil, NGL and natural gas sales volumes.
■Daily production - the Company seeks to maximize field operability and minimize production down-time.
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FINANCIAL
■CROCE - CROCE is calculated as (i) the cash flows from operating activities, before changes in working capital, plus distributions from WES classified as investing cash flows, divided by (ii) the average of the opening and closing balances of total equity plus total debt.
■FCF - FCF is calculated as the cash flows from operating activities, before changes in working capital, less the Company’s capital expenditures, net of contributions from noncontrolling interests.
■Financial Leverage- Reduce debt to achieve metrics consistent with an investment grade credit rating.
SUSTAINABILITY AND ENVIRONMENTAL
■Interim targets to advance the goal of net-zero operational and energy use emissions before 2040, with an ambition to achieve before 2035.
■Milestones in specific carbon removal and CCUS projects that advance a net-zero total emissions inventory, including use of sold products, with an ambition to achieve before 2050.
■Facilitate deployment of carbon removal, CCUS and other solutions to advance total carbon impact past 2050.
| OIL AND GAS SEGMENT | ||||||||||||||
BUSINESS STRATEGY
The Company’s oil and gas segment focuses on long-term value creation in the key performance indicators noted above of total spend per barrel, field operability, daily production, and leadership through our HSE and sustainability initiatives. In each core operating area, the Company’s operations benefit from scale, technical expertise, decades of high-margin inventory, HSE leadership and commercial and governmental collaboration. These attributes allow the Company to bring additional production quickly to market, extend the life of mature fields at lower costs and pursue low-cost returns-driven growth opportunities with advanced technology.
The Company is one of the largest U.S. producers of liquids, which includes oil and NGL, enabling it to maximize cash margins on a per barrel basis. The Company’s robust portfolio, combined with our subsurface characterization expertise and proven ability to execute, support long-term value creation and full-cycle success. The oil and gas segment strives to maximize efficiencies to lower breakeven costs, generate excess free cash flow and maintain low development and operating costs — thereby enhancing the full-cycle value of its assets.
The oil and gas segment implements the Company’s strategy primarily by:
■Operating and developing areas where reserves are known to exist and optimizing capital intensity in the Permian Basin, Rockies, Gulf of America, and our international locations;
■Maintaining a disciplined and prudent approach to capital expenditures with a focus on high-return, short and mid-cycle, cash-flow-generating opportunities and an emphasis on creating value and further enhancing the Company’s existing positions;
■Applying the Company’s subsurface characterization and technical expertise to both conventional and unconventional resources;
■Using secondary and tertiary recovery techniques in mature fields and leveraging the Company’s EOR position, experience and infrastructure to extend U.S. unconventional resources; and
■Focusing on cost-reduction efficiencies and innovative technologies to reduce carbon emissions.
In 2025, oil and gas capital expenditures, including exploration, were approximately $5.6 billion and primarily focused on the Company’s assets in the Permian Basin, DJ Basin, Gulf of America and Oman.
OIL AND GAS PRICE ENVIRONMENT
Oil and gas prices are the major variables that drive the industry’s financial performance. The following table presents the average daily WTI and Brent prices for oil and NYMEX natural gas prices for 2025 and 2024:
| 2025 | 2024 | % Change | |||||||||
| WTI Oil ($/Bbl) | $ | 64.81 | $ | 75.72 | (14) | % | |||||
| Brent Oil ($/Bbl) | $ | 68.18 | $ | 79.79 | (15) | % | |||||
| NYMEX Natural Gas ($/Mcf) | $ | 3.55 | $ | 2.34 | 52 | % | |||||
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The following table presents the Company’s average realized prices for continuing operations as a percentage of WTI, Brent and NYMEX for 2025 and 2024:
| 2025 | 2024 | |||||||
| Worldwide oil as a percentage of average WTI | 100 | % | 99 | % | ||||
| Worldwide oil as a percentage of average Brent | 95 | % | 94 | % | ||||
| Worldwide NGL as a percentage of average WTI | 32 | % | 28 | % | ||||
| Worldwide NGL as a percentage of average Brent | 30 | % | 27 | % | ||||
| Domestic natural gas as a percentage of NYMEX | 45 | % | 40 | % | ||||
Prices and differentials can vary significantly, even on a short-term basis, making it difficult to predict realized prices with a reliable degree of certainty.
DOMESTIC INTERESTS
BUSINESS REVIEW
The Company conducts its domestic operations through land leases, subsurface mineral rights it owns, or a combination of both. The Company’s domestic oil and gas leases have a primary term ranging from one to 10 years, which is extended through the end of production once it commences. The Company has leasehold and mineral interests in 8.9 million net acres, of which approximately 51% is leased, 48% is owned subsurface mineral rights and 1% is owned land with mineral rights.
DOMESTIC ASSETS (a)
 | 1. Powder River Basin 2. DJ Basin 3. Permian Basin 4. Gulf of America | ||||
(a)Map represents geographic outlines of the respective basins.
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The Permian Basin
The Permian Basin extends throughout West Texas and Southeast New Mexico and is one of the largest and most active oil basins in the United States, accounting for more than 49% of total United States oil production in 2025. In 2025, the Company sustained a leading position in the Permian Basin, producing approximately 10% of the total oil in the basin. The Company’s 2025 production in the Permian Basin was 786 Mboe/d. In 2025, the Company invested approximately $3.4 billion of development capital in the Permian Basin.
The Company manages its Permian Basin operations through two businesses: Permian Resources, which includes unconventional opportunities, and Permian EOR, which utilizes secondary and tertiary recovery techniques. By exploiting the natural synergies between Permian Resources and Permian EOR, the Company is able to deliver unique short- and long-term advantages, efficiencies and expertise across its Permian Basin operations.
The Permian Resources business is focused on developing and producing unconventional reservoir targets using horizontal drilling technology. The development programs are designed to create long-term value from primary development by maximizing the recovery of oil, utilizing sustainable practices and providing strong financial returns. In 2025, Permian Resources prioritized core development areas, focusing on maintaining the industry-leading capital intensity through optimized surface infrastructure and customized well designs. Permian Resources has 1.5 million net acres. In 2025, Permian Resources produced from approximately 6,300 gross wells and added 390 MMboe to the Company’s proved reserves through infill development projects and extensions of proved areas.
The Permian Basin’s concentration of large conventional reservoirs, strong CO2 flooding performance and the expansive CO2 transportation and processing infrastructure has resulted in decades of high-value enhanced oil production. With 34 active CO2 floods and over 50 years of experience, Permian EOR is the industry leader in Permian Basin CO2 flooding, which can increase ultimate oil recovery by 10% to 25%. Technology improvements, such as the recent trend toward vertical expansion of the CO2 flooded interval into residual oil zone targets, continue to yield more recovery from existing projects. Significant opportunities also remain to gain additional recovery by expanding the Company’s existing CO2 projects into new portions of reservoirs that have only been waterflooded. Permian EOR has 1.4 million net acres with a large inventory of future CO2 projects, which could be developed over the next 20 years or accelerated, depending on market conditions. Permian EOR produced from approximately 11,900 gross wells in 2025.
Rockies and Other Domestic
In 2025, the Company produced 284 Mboe/d and invested capital of approximately $0.8 billion in the Rockies and Other Domestic locations. Production in the DJ Basin is derived from approximately 3,500 gross wells primarily focused in the Niobrara and Codell formations. The DJ Basin comprises approximately 0.5 million total net acres and provides competitive economics, low breakeven costs and free cash flow generation through the Company’s contiguous acreage position and royalty uplift.
Operations in the DJ Basin are subject to regulations that impose siting requirements, or “setback,” on certain oil and gas drilling locations based on the distance of a proposed well pad to occupied structures. The Company has a dedicated stakeholder relations team that conducts regulatory and community outreach with respect to its permit applications and operations in Colorado with a focus on building trust and fostering open communication with those who live and work near its operations. The Company has established a steady cadence of permit approvals from various agencies, local governments and the ECMC through robust community outreach, protective site selection, thoughtful facility design and planning, and best-in-class measures to mitigate potential impacts from operations. In 2025, the Company submitted Oil and Gas Development Plans comprising approximately 100 wells to the ECMC. As of December 31, 2025, the Company has permits for over 90% of the 2026 drilling schedule and over 45% of the 2027 drilling schedule with the remaining percentage of activity pending regulatory approval or scheduled for submission in 2026. The Company continues to gain efficiencies in the permitting process and will continue to look for additional opportunities to do so in the future.
The Company has interests in approximately 0.2 million net acres in the Powder River Basin, mainly located in Converse County and Campbell County, Wyoming. The Powder River Basin contains the Turner, Niobrara, Mowry, Parkman, and Teapot formations that hold both liquids and natural gas and produces from 139 gross wells.
The Company holds approximately 4.5 million net acres in other domestic locations, which consist of acreage and fee minerals outside of the Company’s core operated areas including parts of Arkansas, Colorado, Louisiana, Texas, West Virginia and Wyoming.
OFFSHORE DOMESTIC ASSETS
Gulf of America
The Company is the fourth-largest oil and gas producer in the deep-water Gulf of America, operating 8 strategically located deep-water floating platforms and producing from 14 active fields while owning a working interest in approximately 230 blocks, covering approximately 0.8 million net acres.
In 2025, the Company’s Gulf of America production was 132 Mboe/d from 96 gross wells. The Company’s focused production management processes and development projects resulted in increased production from the prior year. Operational efficiency focus continued in 2025, with Production Operations and Asset Integrity teams achieving world class highest platform operating efficiencies, with major equipment uptimes of over 99%.
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The Company’s Gulf of America assets continued to be among the lowest carbon emissions operations in the industry with zero routine flaring and zero cold venting.
The Company invested $0.5 billion of development capital in 2025 with a continued strategy of low risk, infill drilling opportunities and accelerated project delivery at its Horn Mountain, Constitution and Lucius facilities. Drilling and well service projects were implemented utilizing two floating drill ships and several service rigs. During 2025, all necessary regulatory permits for new wells and existing operations were obtained timely without any operational delays.
As part of its Gulf of America 2.0 program (GOA 2.0), the Company successfully implemented several state-of-the-art artificial lift projects, including down-hole gas-lift and caisson electric submersible pumps at its Horn Mountain platform in 2025, delivering some of the highest margin production in the Company’s portfolio. In addition, the Company’s asset development and facilities teams began implementation of several GOA 2.0 growth projects to significantly increase recovery from the Company’s existing producing oil and gas reservoirs with the first water injection at Marlin planned to be on stream in Summer 2026 and at Horn Mountain in 2027. Several major secondary recovery uplift projects and new horizontal/extended reach well opportunities will continue implementation in 2026 onwards.
The Company’s Gulf of America operations will conduct both development and exploration activities in 2026 using two floating drill ships and several other well service vessels and will continue to develop and expand its extensive portfolio of lease working interests through its GOA 2.0 program.
The following table shows key areas of ongoing development in the Gulf of America, along with the corresponding working interest in those areas.
| Working Interest | |||||
| Horn Mountain | 100 | % | |||
| Holstein | 100 | % | |||
| Marlin | 100 | % | |||
| Lucius | 67 | % | |||
| K2 Complex | 51 | % | |||
| Caesar Tonga | 34 | % | |||
| Constellation | 33 | % | |||
INTERNATIONAL INTERESTS
BUSINESS REVIEW
The Company primarily conducts its international operations in two sub-regions: the Middle East and North Africa. Its activities include oil, NGL and natural gas production through direct working interests and PSCs. Under the PSCs, the Company records a share of production and reserves to recover certain development and production costs and an additional share for profit. These contracts do not transfer any right of ownership to the Company and reserves reported from these arrangements are based on the Company’s economic interest as defined in the contracts. The Company’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, the Company’s net economic benefit from these contracts is greater when product prices are higher.
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MIDDLE EAST / NORTH AFRICA ASSETS
 | 1.Algeria 2.Oman 3.Qatar 4.UAE | ||||
Algeria
The Company’s interests in Algeria consists of production rights in 18 fields within Blocks 404a and 208, both of which expire in 2048, located in the Berkine Basin in Algeria’s Sahara Desert. The Company also owns interests in 3 unitized fields within Blocks 404a and 208 (the Ourhoud Unit, the EMK Unit and the HBN Unit) as well as in 3 processing facilities (the El Merk central processing facility in Block 208 that processes produced oil, NGL and natural gas; and the Hassi Berkine South and Ourhoud central processing facilities in Block 404a that process produced oil).
In 2025, net production in Algeria was 28 Mboe/d from 219 gross wells, and annual development capital expenditures were $0.1 billion.
Oman
In Oman, the Company is the operator of Block 9, Block 27, Block 53 (Mukhaizna Field), Block 62 and Block 65 and has additional interests in Blocks 30, 51 and 72, which are under the exploration phase. The working interest and contract expiration year for each of the respective blocks are shown in the table below. The Company holds 6.0 million gross acres and has 10,000 potential well inventory locations. In 2025, the Company’s share of production was 72 Mboe/d.
| Working Interest | Block Expiration (Year) | |||||||
| Block 9 | 50 | % | 2030 | |||||
| Block 27 | 65 | % | 2035 | |||||
| Block 53 | 47 | % | 2050 | |||||
| Block 62 | 100 | % | 2028 | |||||
| Block 65 | 51 | % | 2037 | |||||
| Blocks 30, 51 and 72 | 100 | % | Exploration Phase | |||||
The Company has produced over 853 million gross barrels from Block 9 since the beginning of its operation through successful exploration, continuous drilling improvements and EOR projects. The Mukhaizna Field in Block 53 is a major pattern steam flood project for EOR that utilizes some of the largest mechanical vapor compressors ever built. Since assuming operations in the Mukhaizna Field in 2005, the Company has drilled over 3,600 new wells and has substantially increased production to deliver over 662 million gross barrels, while maintaining a strong commitment to operational excellence, environmental stewardship and community engagement. The Company signed a 15-year contract extension for Block 53 in 2025, which is expected to deliver significant value to all stakeholders. In 2025, the Company invested development capital of $0.4 billion across all of the Oman blocks to drill 120 wells and execute facilities projects to support development and EOR activities.
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Qatar
In Qatar, the Company partners in the Dolphin Energy Project, an investment that is comprised of two separate economic interests. The Company has a 24.5% interest in the upstream operations to develop and produce NGL, natural gas and condensate from Qatar’s North Field through mid-2032. The Company also has a 24.5% interest in Dolphin midstream in the UAE, which operates a pipeline and is discussed further in the midstream and marketing segment section in this Form 10-K under Pipeline. In 2025, the Company’s net share of production from Dolphin was 40 Mboe/d.
UAE
The Company has a 40% participating interest in the Shah gas field (Al Hosn Gas), in conjunction with ADNOC, the UAE’s national oil company, which expires in 2041. In 2025, the Company’s net share of production from Al Hosn Gas was 283 MMcf/d of natural gas and 42 Mbbl/d of NGL and condensate. Al Hosn Gas includes gas processing facilities which are discussed further in the midstream and marketing segment section in this Form 10-K under Gas Processing, Gathering and CO2.
In 2019 and 2020, the Company acquired 9-year exploration concessions and, subject to a declaration of commerciality, 35-year production concessions for Onshore Block 3 and Block 5, which cover a combined area of approximately 2.5 million acres, and are adjacent to Al Hosn Gas. In 2023, the Company commenced first oil production in Onshore Block 3.
PROVED RESERVES
Proved oil, NGL and natural gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGL and natural gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs.
The following table shows the 2025, 2024 and 2023 calculated first-day-of-the-month average prices for both WTI and Brent oil prices, as well as the Henry Hub gas and Mt. Belvieu NGL prices:
| 2025 | 2024 | 2023 | |||||||||
| WTI Oil ($/Bbl) | $ | 65.34 | $ | 75.48 | $ | 78.22 | |||||
| Brent Oil ($/Bbl) | $ | 68.42 | $ | 79.65 | $ | 82.80 | |||||
| Henry Hub Natural Gas ($/MMbtu) | $ | 3.39 | $ | 2.13 | $ | 2.64 | |||||
| Mt. Belvieu NGL ($/Bbl) | $ | 31.79 | $ | 33.04 | $ | 29.94 | |||||
The Company had proved reserves from continuing operations at year-end 2025 of 4,603 MMboe, compared to the year-end 2024 proved reserves of 4,612 MMboe. Proved developed reserves represented approximately 72% and 69% of the Company’s total proved reserves as of December 31, 2025 and 2024, respectively. The following table shows the Company’s proved reserves from continuing operations by commodity as a percentage of total proved reserves:
| 2025 | 2024 | |||||||||||||
| Oil | 47 | % | 46 | % | ||||||||||
| NGL | 25 | % | 27 | % | ||||||||||
| Natural gas | 28 | % | 27 | % | ||||||||||
The Company does not have any reserves from non-traditional sources. For further information regarding the Company’s proved reserves, see the Supplemental Oil and Gas Information section in Item 8 of this Form 10-K.
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CHANGES IN PROVED RESERVES
Changes in the Company’s 2025 reserves were as follows:
| MMboe | 2025 | |||||||
| Balance — beginning of year | 4,612 | |||||||
| Revisions of previous estimates | 161 | |||||||
| Improved recovery | 60 | |||||||
| Extensions and discoveries | 340 | |||||||
| Purchases | 10 | |||||||
| Sales | (57) | |||||||
| Production | (523) | |||||||
| Balance — end of year | 4,603 | |||||||
The Company’s ability to add reserves, other than through purchases, depends on the success of infill development, extension, discovery and improved recovery projects, each of which depends on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside management’s control and may negatively or positively affect the Company’s reserves.
Revisions of Previous Estimates
Revisions can include upward or downward changes to previous proved reserve estimates for existing fields due to the evaluation or interpretation of geologic, production decline or operating performance data. In addition, product price changes affect proved reserves recorded by the Company. For example, lower prices may decrease the economically recoverable reserves, particularly for domestic properties, because the reduced margin limits the expected life of the operations. Offsetting this effect, lower prices increase the Company’s share of proved reserves under PSCs because more oil is required to recover costs. Conversely, when prices rise, the Company’s share of proved reserves decreases for PSCs and economically recoverable reserves may increase for other operations. Reserve estimation rules require that estimated ultimate recoveries be much more likely to increase or remain constant than to decrease, as changes are made due to increased availability of technical data.
In 2025, the Company’s revisions of previous estimates of proved reserves were positive 161 MMboe, which were composed of positive revisions related to additions associated with infill development projects (115 MMboe), changes in economic conditions (131 MMboe), and the Oman contract extension (61 MMboe). The positive revisions were partially offset by negative revisions associated with price revisions (85 MMboe) and updates based on reservoir performance (45 MMboe).
Positive revisions related to additions associated with infill development projects of 115 MMboe were mainly in the Permian Basin (54 MMboe) and the DJ Basin (49 MMboe).
Positive revisions associated with changes in economic conditions of 131 MMboe were primarily in the Permian Basin (122 MMboe).
Negative price revisions of 85 MMboe were primarily associated with the Permian Basin (94 MMboe), which were partially offset by positive price revisions of 7 MMboe on international PSCs.
Negative revisions of 45 MMboe associated with updates based on reservoir performance were primarily related to the Permian Basin (66 MMboe), which were partially offset by positive reservoir performance updates in GOA (19 MMboe).
Improved Recovery
In 2025, the Company added proved reserves of 60 MMboe related to improved recovery in GOA (44 MMboe), Permian EOR (9 MMboe) and Oman (7 MMboe). These properties comprise conventional projects, which are characterized by the deployment of EOR development methods, largely employing application of CO2 flood, waterflood or steam flood. These types of conventional EOR development methods can be applied through existing wells, though additional drilling is frequently required to fully optimize the development configuration. Waterflooding is the technique of injecting water into the formation to displace the oil to the offsetting oil production wells. The use of either CO2 or steam flooding depends on the geology of the formation, the evaluation of engineering data, availability and cost of either CO2 or steam and other economic factors. Both techniques work similarly to lower viscosity, causing the oil to move more easily to the producing wells.
Extensions and Discoveries
The Company also added proved reserves from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2025, extensions and discoveries added 340 MMboe primarily related to the recognition of proved reserves in the Permian Basin (336 MMboe).
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Purchases of Proved Reserves
In 2025, the Company purchased proved reserves of 10 MMboe consisting of proven reserves in the Permian Basin related to acreage trades.
Sales of Proved Reserves
In 2025, the Company sold 57 MMboe in proved reserves related to the divestitures of certain non-strategic assets in the Permian Basin and the DJ Basin.
Proved Undeveloped Reserves
The Company had PUD reserves at year-end 2025 of 1,309 MMboe, compared to the year-end 2024 amount of 1,421 MMboe.
Changes in PUD reserves were as follows:
| MMboe | 2025 | |||||||
| Balance — beginning of year | 1,421 | |||||||
| Revisions of previous estimates | 46 | |||||||
| Improved recovery | 55 | |||||||
| Extensions and discoveries | 247 | |||||||
| Purchases | 1 | |||||||
| Sales | (23) | |||||||
| Transfer to proved developed reserves | (438) | |||||||
| Balance — end of year | 1,309 | |||||||
Revisions of previous estimates were a positive 46 MMboe. Approximately 238 MMboe of the positive revisions were associated with updates based on reservoir performance, primarily due to positive performance revisions in the Permian Basin (242 MMboe). Further positive revisions were composed of positive revisions related to additions associated with infill development projects (102 MMboe), changes in economic conditions (16 MMboe), and the Oman contract extension (11 MMboe). The positive revisions were partially offset by negative revisions of 318 MMboe associated with management changes in development plans, mainly in the Permian Basin (314 MMboe).
The positive revisions related to additions associated with infill development projects of 102 MMboe were mainly in the Permian Basin (47 MMboe) and the DJ Basin (44 MMboe). Positive revisions associated with changes in economic conditions of 16 MMboe were primarily in the Permian Basin.
Extensions and discoveries added 247 MMboe primarily related to the recognition of proved reserves in the Permian Basin (243 MMboe). Total improved recovery additions of 55 MMboe were the result of implementing secondary and tertiary projects in GOA (44 MMboe), Permian EOR (7 MMboe) and Oman (4 MMboe). In 2025, the Company purchased PUD reserves of 1 MMboe consisting of development projects in the Permian Basin related to acreage trades and sold 23 MMboe consisting of development projects primarily related to certain non-strategic assets in the Permian Basin. The 2025 additions to PUD reserves were partially offset by transfers to proved developed reserves of 438 MMboe. The transfers were primarily associated with the Permian Basin (278 MMboe), the DJ Basin (98 MMboe) and GOA (47 MMboe).
In 2025, the Company incurred approximately $2.2 billion to convert PUD reserves to proved developed reserves, and converted approximately 31% of its PUD reserves to proved developed, when adjusted for revisions and sales. As of December 31, 2025, the Company had 1,309 MMboe of PUD reserves of which 82% were associated with domestic onshore, 5% with GOA and 13% with international assets. The Company’s most active development areas are located in the Permian Basin, which represented 69% of the PUD reserves as of December 31, 2025. Overall, the Company plans to spend approximately $8.4 billion over the next five years to develop its PUD reserves in the Permian Basin.
PUD reserves are supported by a five-year detailed field-level development plan, which includes the timing, location and capital commitment of the wells to be drilled. Only PUD reserves which are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the PUD reserves are expected to be developed beyond the five years and are tied to approved long-term development projects.
As of December 31, 2025, the Company had 185 MMboe of pre-2021 PUD reserves that remained undeveloped. These PUD reserves relate to approved long-term development plans, primarily associated with international development projects (168 MMboe) with physical limitations in existing gas processing capacity and related to approved long-term development plans for Permian EOR projects (17 MMboe), also with physical limitations in existing gas processing capacity. The Company remains committed to these projects and continues to actively progress the development of these volumes.
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RESERVES EVALUATION AND REVIEW PROCESS
The Company’s estimates of proved reserves and associated future net cash flows as of December 31, 2025 were made by the Company’s technical personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and funding commitments by the Company to develop the reserves. This process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of the proved reserves estimation process, all reserve volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Price differentials between benchmark prices (the unweighted arithmetic average of the first-day-of-the-month price for each month within the year) and realized prices and specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including estimates from decline curve analysis, type well profile analysis, computer simulation of the reservoir performance and volumetric analysis calculations that take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes supported by various technologies including seismic analysis. These reliable field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities.
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods for which the incremental cost of any additional required investment is relatively minor.
Net PUD reserves are those volumes 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. PUD reserves are supported by a five-year detailed field-level development plan, which includes the timing, location and capital commitment of the wells to be drilled. The development plan is reviewed and approved annually by senior management and technical personnel. Annually, a detailed review is performed by the Company’s Corporate Reserves Group and its technical personnel on a lease-by-lease basis to assess whether PUD reserves are being converted on a timely basis within five years from the initial disclosure date. Any leases not showing timely transfers from PUD reserves to proved developed reserves are reviewed by senior management to determine if the remaining reserves will be developed in a timely manner and have sufficient capital committed in the development plan. Only PUD reserves that are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the PUD reserves are expected to be developed beyond the five years and are tied to approved long-term development plans.
The current Vice President, Reserves for Oxy Oil and Gas is responsible for overseeing the preparation of reserve estimates, in compliance with SEC rules and regulations, including the internal audit and review of the Company’s oil and gas reserves data. She has over 24 years of experience in the upstream sector of the exploration and production business and has extensive experience evaluating a variety of assets in basins around the world. She is a past President of the International Executive Committee for the SPEE and a member of the Society of Petroleum Engineers. She is a licensed Professional Engineer in the State of Texas and currently serves on the SPEE Reserves Definitions Committee. She has Bachelor of Science degree in chemical engineering from the University of Illinois Urbana-Champaign.
The Company has a Reserves Committee, consisting of senior corporate officers, to review and approve the Company’s oil and gas reserves. The Reserves Committee reports to the Audit Committee of the Company’s Board of Directors during the year. Since 2003, the Company has retained Ryder Scott, independent petroleum engineering consultants, to review its annual oil and gas reserve estimation processes. For additional reserves information, see Supplemental Oil and Gas Information under Item 8 of this Form 10-K.
In 2025, Ryder Scott conducted a process review of the methods and analytical procedures utilized by the Company’s engineering and geological staff for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as of December 31, 2025, in accordance with SEC regulatory standards. Ryder Scott reviewed the specific application of such methods and procedures for selected oil and gas properties considered to be a valid representation of the Company’s 2025 year-end total proved reserves portfolio. In 2025, Ryder Scott reviewed approximately 39% of the Company’s proved oil and gas reserves. Since being engaged in 2003, Ryder Scott has reviewed the specific application of the Company’s reserve estimation methods and procedures for approximately 97% of the Company’s existing proved oil and gas reserves.
Management retained Ryder Scott to provide objective third-party input on its methods and procedures and to gather industry information applicable to the Company’s reserve estimation and reporting process. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities reported by the Company. The Company has filed Ryder Scott’s independent report as an exhibit to this Form 10-K.
Based on its reviews, including the data, technical processes and interpretations presented by the Company, Ryder Scott has concluded that the overall procedures and methodologies the Company utilized in estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications for the reviewed properties are appropriate for the purpose thereof and comply with current SEC regulations.
OUTLOOK
The oil and gas exploration and production industry remains highly competitive and is subject to significant volatility due to various market conditions, with operations highly dependent on oil prices and, to a lesser extent, NGL and natural gas
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prices. In 2025, compared to 2024, the average daily price per barrel of WTI crude decreased to $64.81 from $75.72, the average daily Brent price per barrel decreased to $68.18 from $79.79 and the average daily NYMEX natural gas price per MMcf increased to $3.55 from $2.34.
Oil prices will continue to be affected by: (i) global supply and demand, which are generally a function of global economic conditions, inventory levels, production or supply chain disruptions, technological advances, regional market conditions and the actions of OPEC, other significant producers and governments; (ii) transportation capacity, infrastructure constraints, and associated costs in producing areas; (iii) currency exchange rates and inflation; and (iv) the impact of these variables on market sentiment. It is expected that the price of oil will be volatile for the foreseeable future given the ongoing geopolitical risks, the evolving macro-economic environment and supply activity from OPEC and non-OPEC oil producing countries. The Company does not operate or own assets in either Russia or Ukraine, or in the immediate vicinity of ongoing conflicts in the Middle East.
NGL pricing is influenced by the supply and demand for the individual components of these liquids. Some are closely tied to oil prices, while others are affected by natural gas prices and the demand for chemical products that use NGLs as feedstock. In addition, regional infrastructure constraints continue to amplify pricing volatility.
Domestic natural gas prices and local differentials are primarily driven by local supply and demand fundamentals, government regulations, global LNG demand and transportation capacity from producing areas. International gas prices are generally fixed under long-term contracts.
These and other factors make it difficult to reliably forecast oil, NGL and domestic gas prices. For its current capital plan, the Company will continue to focus on allocating capital to high-return assets with the flexibility to adapt to market conditions including commodity price fluctuations, supply chain constraints, tariffs, higher interest rates, global logistics and persistent inflation, all of which disrupt global supply and demand balances. The Company’s objective is to deliver our free cash flow needs without impacting operational performance.
The timing, process and ultimate cost of transitioning to a less carbon-intensive economy remain largely uncertain; various industry forecasts indicate a growing demand for hydrocarbons for the next decade. The Company believes its operational flexibility to achieve low development and operating costs to maximize full-cycle value of its assets and its knowledge and experience in CO2 separation, transportation, use, recycling and storage position its oil and gas segment for opportunities to lower carbon intensity.
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| MIDSTREAM AND MARKETING SEGMENT | ||
BUSINESS STRATEGY
The midstream and marketing segment strives to maximize value by optimizing the use of its gathering, processing, transportation, storage and terminal commitments and by providing the oil and gas segment access to domestic and international markets. To generate returns, the segment evaluates opportunities across the value chain and uses its assets to provide services to Occidental’s subsidiaries, as well as third parties. The midstream and marketing segment operates or contracts for services on gathering systems, gas plants, and storage facilities and invests in entities that conduct similar activities.
This segment also seeks to minimize the costs of gas and power used in the Company’s operations. Also included in the midstream and marketing segment is OLCV. OLCV seeks to leverage the Company’s experience with carbon management in EOR. OLCV invests in emerging low-carbon technologies that are expected to reduce the Company’s carbon footprint and ensure the long-term sustainability of the Company’s principal business, and enable others to do the same.
Capital is employed to sustain or expand assets to improve the competitiveness of the Company’s business. In 2025, capital expenditures related to the midstream and marketing segment totaled $720 million, before contributions from noncontrolling interests, the majority of which were related to the construction of STRATOS.
BUSINESS ENVIRONMENT
Midstream and marketing segment earnings are primarily affected by the performance of its marketing, gathering and transportation business, as well as its gas processing business. The marketing business aggregates, markets and stores Company and third-party volumes. Marketing performance is affected primarily by commodity price changes and margins in oil and gas transportation and storage programs. The marketing business results can experience significant volatility depending on commodity prices and the Midland-to-Gulf-Coast oil spreads and Waha-to-Gulf-Coast gas spreads. The Midland-to-Gulf-Coast oil spreads have decreased to an average of $0.30 per barrel in 2025 from an average of $0.49 per barrel in 2024. The Waha-to-Gulf-Coast gas spreads have increased to an average of $2.21 per MMbtu in 2025 from an average of $1.49 per MMbtu in 2024. Gas gathering, processing and transportation results are affected by fluctuations in commodity prices and the volumes that are processed and transported through the segment’s plants, as well as the margins obtained on related services from investments in which the Company has an equity interest. Excluding items affecting comparability, midstream and marketing’s results in 2025, compared to 2024, were impacted by higher sulfur prices at Al Hosn, higher Waha-to-Gulf-Coast gas spreads, and lower long-haul crude transportation costs, partially offset by higher losses from equity method investees and higher expenses due to the increase in OLCV activities.
BUSINESS REVIEW
MARKETING
The marketing group markets substantially all of the Company’s oil, NGL and natural gas production and optimizes its transportation and storage capacity. The Company’s third-party marketing activities focus on purchasing oil, NGL and natural gas for resale from parties whose oil and gas supply is located near its transportation and storage capacity. These purchases allow the Company to aggregate volumes to better utilize and optimize its assets.
DELIVERY AND TRANSPORTATION COMMITMENTS
The Company has made long-term commitments to certain refineries and other buyers to deliver oil, NGL and natural gas. The total amount contracted to be delivered is approximately 74 MMbbl of oil through 2026, 693 MMbbl of NGL through 2034 and 545 Bcf of gas through 2029. The price for these deliveries is set at the time of delivery of the product.
The Company has crude pipeline take-or-pay capacity of approximately 750 Mbbl/d to the Gulf Coast, leased crude storage capacity of approximately 9 MMbbl and capacity at the crude terminal of approximately 525 Mbbl/d.
PIPELINE
The Company’s pipeline business mainly consists of its 24.5% ownership interest in DEL. DEL owns and operates a 230-mile-long, 48-inch-diameter natural gas pipeline, known as the Dolphin Pipeline, which transports dry natural gas from Qatar to the UAE and Oman. The Dolphin Pipeline has capacity to transport up to 3.2 Bcf/d and currently transports approximately 2.0 Bcf/d and up to 2.2 Bcf/d in the summer months.
GAS PROCESSING, GATHERING AND CO2
The Company processes its own and third-party domestic wet gas to extract NGL and other gas byproducts, including CO2, and delivers dry gas to pipelines. Margins primarily result from the difference between inlet costs of wet gas and market prices for NGL.
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WES is a publicly traded limited partnership with its limited partner units traded on the NYSE under the ticker symbol “WES.” As of December 31, 2025, the Company owned all of the 2.2% non-voting general partner interest, 40.6% of the WES limited partner units, and a 2% non-voting limited partner interest in WES Operating, a subsidiary of WES. As of December 31, 2025, the Company’s combined share of net income from WES and its subsidiaries was 43.1%. In February 2026, in connection with certain contract amendments, the Company transferred 15.3 million units to WES; after this transfer, the combined share of net income in WES and its subsidiaries is 40.9%. See Note 1 - Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for more information regarding the Company’s equity method investment in WES. WES owns gathering systems, plants and pipelines and earns revenue from fee-based and service-based contracts with the Company and third parties.
The Company’s 40% participating interest in Al Hosn Gas also includes sour gas processing facilities that are designed to process 1.45 Bcf/d of natural gas and separate it into salable gas, condensate, NGL and sulfur. In 2025, the Al Hosn Gas processing facilities produced 13,000 tons per day of sulfur, of which the Company’s net share was 5,200 tons per day of sulfur.
LOW-CARBON VENTURES
OLCV capitalizes on the Company’s extensive experience in utilizing CO2 in its development of CCUS projects and providing services to third parties to facilitate the implementation of their CCUS projects. Moreover, OLCV fosters emerging technologies, including DAC and low-emissions power sources, and other business models with the potential to position the Company as a leader in the production of lower carbon intensity energy and products.
The Company expects to begin sequestering CO2 captured at STRATOS, the first commercial-scale direct air capture facility in Ector County, Texas, in 2026. The Company holds permits for Class VI CO2 injection wells in support of STRATOS. The Company has a joint venture agreement with BlackRock, through a fund managed by its Diversified Infrastructure business, for the development of STRATOS. See Note 1 - Summary of Significant Accounting Policies.
OLCV has acquired access to over 0.3 million acres of pore space to date, and has continued to pursue permits for Class VI CO2 injection wells with the intention of developing additional sequestration hubs. OLCV continues to explore a number of projects to capture and sequester CO2, either from the atmosphere or from industrial point sources. The profitability of sequestration projects is dependent upon the costs of developing, building and operating sequestration infrastructure, demand for sequestration services from emitters and the availability of certain tax attributes and credits generated from the capture and storage of CO2.
The Company owns a 40.3% interest in NET Power Inc., an energy technology company focused on delivering low-carbon gas power solutions. NET Power is currently traded on the NYSE under the symbol “NPWR.”
OUTLOOK
Midstream and marketing segment results can experience volatility depending on commodity price changes, demand impacting export sales, the Midland-to-Gulf-Coast oil spreads and Waha-to-Gulf-Coast gas spreads. Gas gathering, processing and transportation results are affected by fluctuations in commodity prices and the volumes that are processed and transported through the segment’s plants, as well as the margins obtained on related services from investments in which the Company has an equity interest.
OLCV is affected by elements of supply chain and economy-wide cost increases that could increase the cost of sequestration. In addition, there is still uncertainty around recent legislation, such as the IRA and OBBBA, for certain tax credits related to low carbon businesses. For more information refer to the heading Income Taxes below.
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| SEGMENT RESULTS OF OPERATIONS AND ITEMS AFFECTING COMPARABILITY | ||
SEGMENT RESULTS OF OPERATIONS
Segment earnings exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from divestitures of segment assets and income from segment equity investments. Seasonality is not a primary driver of changes in the Company’s consolidated quarterly earnings during the year.
The following table sets forth the sales and earnings of each operating segment and corporate items for the years ended December 31:
| millions, except per share amounts | 2025 | 2024 | 2023 | ||||||||
NET SALES (a,b) | |||||||||||
| Oil and gas | $ | 20,902 | $ | 21,705 | $ | 21,284 | |||||
| Midstream and marketing | 1,279 | 886 | 2,433 | ||||||||
| Eliminations | (588) | (572) | (561) | ||||||||
| Total | $ | 21,593 | $ | 22,019 | $ | 23,156 | |||||
SEGMENT RESULTS AND EARNINGS (b) | |||||||||||
Domestic | $ | 3,192 | $ | 3,715 | $ | 4,822 | |||||
International | 1,643 | 1,774 | 1,859 | ||||||||
Exploration | (249) | (275) | (441) | ||||||||
| Oil and gas | 4,586 | 5,214 | 6,240 | ||||||||
| Midstream and marketing | 252 | 563 | (35) | ||||||||
| Total | $ | 4,838 | $ | 5,777 | $ | 6,205 | |||||
Unallocated corporate items | |||||||||||
Interest expense, net | (1,079) | (1,169) | (957) | ||||||||
Income tax expense | (1,021) | (1,158) | (1,330) | ||||||||
| Other | (631) | (584) | (586) | ||||||||
Income from continuing operations | $ | 2,107 | $ | 2,866 | $ | 3,332 | |||||
Discontinued operations, net | 262 | 212 | 1,364 | ||||||||
Net income | 2,369 | 3,078 | 4,696 | ||||||||
| Less: Net income attributable to noncontrolling interests | (43) | (22) | — | ||||||||
Less: Preferred stock dividends and redemption premiums | (679) | (679) | (923) | ||||||||
Net income attributable to common stockholders | $ | 1,647 | $ | 2,377 | $ | 3,773 | |||||
Net income attributable to common stockholders—basic | $ | 1.65 | $ | 2.59 | $ | 4.22 | |||||
Net income attributable to common stockholders—diluted | $ | 1.61 | $ | 2.44 | $ | 3.90 | |||||
(a)Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.
(b)Sales and net results related to the OxyChem Transaction are reflected in discontinued operations, net.
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ITEMS AFFECTING COMPARABILITY
OIL AND GAS SEGMENT
Results of Operations
| millions | 2025 | 2024 | 2023 | ||||||||
| Segment Sales | $ | 20,902 | $ | 21,705 | $ | 21,284 | |||||
Segment Results (a) | |||||||||||
Domestic | $ | 3,192 | $ | 3,715 | $ | 4,822 | |||||
International | 1,643 | 1,774 | 1,859 | ||||||||
Exploration | (249) | (275) | (441) | ||||||||
Total | $ | 4,586 | $ | 5,214 | $ | 6,240 | |||||
| Items affecting comparability | |||||||||||
Gains (losses) on sales of assets and other, net - domestic (b) | $ | (99) | $ | (585) | $ | 142 | |||||
Legal reserves and other (c) | $ | (105) | $ | (54) | $ | 26 | |||||
Asset impairments and related items - domestic (d) | $ | (6) | $ | (334) | $ | (209) | |||||
| Gain on sales of assets and other, net - international | $ | 30 | $ | — | $ | 25 | |||||
(a)Results included significant items affecting comparability discussed in the footnotes below.
(b)The 2024 amount included $572 million of losses primarily related to the sale of non-core onshore U.S. assets. The 2023 amount included gains on sales primarily related to certain non-strategic assets in the Permian Basin of $142 million.
(c)The 2025 amount included additions to legal reserves and inventory adjustments.
(d)The 2024 amount included a pre-tax impairment of $334 million related to certain wells in the Gulf of America whose future net cash inflows did not indicate that the asset value is recoverable. The 2023 amount included a pre-tax impairment of $180 million related to undeveloped acreage in the northern non-core area of the Powder River Basin where the Company decided not to pursue future exploration and appraisal activities as well as a $29 million impairment related to an equity method investment in Black Butte Coal Company.
Domestic oil and gas results, excluding significant items affecting comparability, decreased in 2025, compared to 2024, primarily due to lower realized oil prices, partially offset by higher oil volumes, largely driven by a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024, and higher realized domestic gas prices. International oil and gas results, excluding significant items affecting comparability, decreased in 2025, compared to 2024, primarily due to lower oil and NGL prices, partially offset by higher oil volumes.
Average Realized Prices
The following table sets forth the average realized prices for oil, NGL and natural gas from ongoing operations for each of the three years in the period ended December 31, 2025, and includes a year-over-year change calculation:
| 2025 | Year over Year Change | 2024 | Year over Year Change | 2023 | |||||||||||||
| Average Realized Prices | |||||||||||||||||
Oil ($/Bbl) | |||||||||||||||||
| United States | $ | 64.01 | (14)% | $ | 74.62 | (2)% | $ | 76.42 | |||||||||
| International | $ | 67.93 | (12)% | $ | 77.46 | (2)% | $ | 79.03 | |||||||||
Total worldwide | $ | 64.60 | (14)% | $ | 75.05 | (2)% | $ | 76.85 | |||||||||
NGL ($/Bbl) | |||||||||||||||||
| United States | $ | 19.96 | (3)% | $ | 20.48 | 1% | $ | 20.19 | |||||||||
| International | $ | 25.43 | (9)% | $ | 28.00 | (5)% | $ | 29.35 | |||||||||
| Total worldwide | $ | 20.60 | (4)% | $ | 21.38 | —% | $ | 21.32 | |||||||||
Natural Gas ($/Mcf) | |||||||||||||||||
| United States | $ | 1.58 | 68% | $ | 0.94 | (54)% | $ | 2.04 | |||||||||
| International | $ | 1.89 | —% | $ | 1.89 | 1% | $ | 1.88 | |||||||||
Total worldwide | $ | 1.65 | 40% | $ | 1.18 | (41)% | $ | 2.00 | |||||||||
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Realized Price and Sales Volume Variance
The following table presents an analysis of the impacts of changes in average realized prices and sales volumes with regard to the Company’s domestic and international oil and gas revenue:
| Increase (Decrease) Related to | ||||||||||||||||||||
| millions | Year ended December 31, 2024 | (a) | Price Realizations | Net Sales Volumes | Year ended December 31, 2025 | (a) | ||||||||||||||
| United States Revenue | ||||||||||||||||||||
| Oil | $ | 15,604 | $ | (2,386) | $ | 1,241 | $ | 14,459 | ||||||||||||
| NGL | 1,865 | (21) | 53 | $ | 1,897 | |||||||||||||||
| Natural gas | 514 | 498 | 5 | $ | 1,017 | |||||||||||||||
| Total | $ | 17,983 | $ | (1,909) | $ | 1,299 | $ | 17,373 | ||||||||||||
| International Revenue | ||||||||||||||||||||
| Oil | $ | 2,940 | $ | (330) | $ | 105 | $ | 2,715 | ||||||||||||
| NGL | 390 | (34) | (4) | 352 | ||||||||||||||||
| Natural gas | 361 | 3 | (12) | 352 | ||||||||||||||||
| Total | $ | 3,691 | $ | (361) | $ | 89 | $ | 3,419 | ||||||||||||
(a) Results excluded “other” oil and gas revenue. See Note 2 - Revenue in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional information regarding other revenue.
Production
The following table sets forth the production volumes of oil, NGL and natural gas per day for each of the three years in the period ended December 31, 2025, and includes a year-over-year change calculation:
| Production per Day (Mboe/d) | 2025 | Year over Year Change | 2024 | Year over Year Change | 2023 | ||||||||||||
| United States | |||||||||||||||||
| Permian | 786 | 18 | % | 664 | 14 | % | 584 | ||||||||||
| Rockies & Other Domestic | 284 | (8) | % | 310 | 14 | % | 271 | ||||||||||
| Gulf of America | 132 | 6 | % | 125 | (14) | % | 145 | ||||||||||
| Total | 1,202 | 9 | % | 1,099 | 10 | % | 1,000 | ||||||||||
| International | |||||||||||||||||
| Algeria & Other International | 31 | (3) | % | 32 | (9) | % | 35 | ||||||||||
| Al Hosn Gas | 89 | (2) | % | 91 | 10 | % | 83 | ||||||||||
| Dolphin | 40 | 3 | % | 39 | — | % | 39 | ||||||||||
| Oman | 72 | 9 | % | 66 | — | % | 66 | ||||||||||
| Total | 232 | 2 | % | 228 | 2 | % | 223 | ||||||||||
Total Production (Mboe/d) (a) | 1,434 | 8 | % | 1,327 | 9 | % | 1,223 | ||||||||||
(a)Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil. Boe equivalence does not necessarily result in price equivalence. Please refer to the Supplemental Oil and Gas Information (unaudited) section of this Form 10-K for additional information on oil and gas production and sales.
Average daily production volumes increased by 8% in 2025, compared to 2024. The increase in production was primarily driven by a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024.
Lease Operating Expense
The following table sets forth the average lease operating expense per Boe for each of the three years in the period ended December 31, 2025:
| 2025 | 2024 | 2023 | |||||||||
| Average lease operating expense per Boe | $ | 8.94 | $ | 9.75 | $ | 10.48 | |||||
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Average lease operating expense per Boe decreased in 2025, compared to 2024, primarily due to operational efficiencies in the Permian Basin and lower energy costs in Oman.
MIDSTREAM AND MARKETING SEGMENT
| millions | 2025 | 2024 | 2023 | ||||||||
| Segment Sales | $ | 1,279 | $ | 886 | $ | 2,433 | |||||
Segment Results (a) | $ | 252 | $ | 563 | $ | (35) | |||||
| Items affecting comparability | |||||||||||
Gains on sales of assets and other, net (b) | $ | 301 | $ | 647 | $ | 51 | |||||
| Equity method investments fair value gains | $ | 61 | $ | 27 | $ | — | |||||
| Derivative losses, net | $ | (29) | $ | (32) | $ | (14) | |||||
Asset impairments and other charges, net (c) | $ | (487) | $ | (21) | $ | (60) | |||||
Acquisition-related costs (d) | $ | — | $ | — | $ | (20) | |||||
Carbon Engineering fair value gain (d) | $ | — | $ | — | $ | 283 | |||||
(a)Results included significant items affecting comparability discussed in the footnotes below.
(b)The 2025 amount included a gain of $301 million resulting from pro-rata ownership reduction in WES following an acquisition by WES. The 2024 and 2023 amounts included gains on sale of $489 million and $51 million, respectively, from the sales of 19.5 million and 5.1 million limited partner units in WES, respectively. The 2024 amount also included $158 million of income from equity investments and other related to the Company’s share of WES’ gains on its asset divestitures.
(c)The 2025, 2024 and 2023 amounts primarily included the Company’s proportionate amounts from impairments and other charges recorded by its equity method investees.
(d)The 2023 amount included a gain of $283 million from the remeasurement of the noncontrolling interest held prior to the Carbon Engineering acquisition to fair value and acquisition-related costs of $20 million.
Midstream and marketing segment results, excluding items affecting comparability, increased in 2025, compared to 2024, due to higher sulfur prices at Al Hosn, higher gas margins from transportation capacity optimization in the Permian Basin, and lower long-haul crude transportation costs, partially offset by higher losses from equity method investees and higher expenses related to the increase in OLCV activities.
CORPORATE
Significant corporate items include the following:
| millions | 2025 | 2024 | 2023 | ||||||||
| Items Affecting Comparability | |||||||||||
Acquisition-related costs(a) | $ | (13) | $ | (150) | $ | (6) | |||||
| Early retirement plan | $ | (39) | $ | — | $ | — | |||||
| Early debt extinguishment | $ | 20 | $ | — | $ | — | |||||
| Gains on sales of assets and other, net | $ | — | $ | 48 | $ | — | |||||
(a)The 2024 amount included $66 million of financing costs related to the CrownRock Acquisition and the remaining amounts were related to CrownRock transaction costs. The 2023 amount related to costs incurred for the CrownRock Acquisition.
DISCONTINUED OPERATIONS
Significant discontinued operations items include the following:
| millions | 2025 | 2024 | 2023 | ||||||||
| Discontinued operations, net of taxes | $ | 262 | $ | 212 | $ | 1,364 | |||||
Items Affecting Comparability(a) | $ | (283) | $ | (622) | $ | 204 | |||||
(a)The 2025 amount included a one-time foreign income tax charge of $101 million and adjustments to legal reserves of $142 million, net of taxes. The 2024 amount included $725 million, net of taxes, related to an increase in the DASS environmental remediation reserve retained in the OxyChem Transaction, partially offset by a gain of $182 million, net of taxes, resulting from a legal settlement related to the Andes Arbitration. The 2023 amount related to a $204 million, net of taxes, remeasurement of the valuation allowance established against the Company’s claims against Maxus. Refer to Note 11 - Environmental Liabilities and Expenditures and Note 12 - Lawsuits, Claims, Commitments and Contingencies for additional details.
| CONSOLIDATED RESULTS OF OPERATIONS | ||
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REVENUE AND OTHER INCOME ITEMS
| millions | 2025 | 2024 | 2023 | ||||||||
| Net sales | $ | 21,593 | $ | 22,019 | $ | 23,156 | |||||
Interest, dividends and other income | $ | 219 | $ | 192 | $ | 153 | |||||
| Gains (losses) on sales of assets and other, net | $ | 263 | $ | (16) | $ | 522 | |||||
NET SALES
Revenue declined from 2024 to 2025, primarily as a result of lower crude oil prices in the oil and gas segment, partially offset by increased sales volumes due to a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024, and higher domestic natural gas prices. Additionally, midstream and marketing revenue improved year over year due to higher sulfur prices at Al Hosn and enhanced natural gas margins.
GAINS (LOSSES) ON SALES OF ASSETS AND OTHER, NET
Gains (losses) on sales of assets and other, net increased from 2024 to 2025, primarily as a result of a gain of $301 million from a fourth quarter pro-rata ownership reduction in WES following an acquisition by WES.
EXPENSE ITEMS
| millions | 2025 | 2024 | 2023 | ||||||||
| Oil and gas operating expense | $ | 4,681 | $ | 4,738 | $ | 4,677 | |||||
| Transportation and gathering expense | $ | 1,660 | $ | 1,608 | $ | 1,481 | |||||
| Purchased commodities and midstream cost of sales | $ | 176 | $ | 431 | $ | 2,116 | |||||
| Selling, general and administrative | $ | 986 | $ | 960 | $ | 987 | |||||
| Other operating and non-operating expense | $ | 1,556 | $ | 1,319 | $ | 1,165 | |||||
| Taxes other than on income | $ | 1,030 | $ | 1,039 | $ | 1,087 | |||||
| Depreciation, depletion and amortization | $ | 7,533 | $ | 6,951 | $ | 6,449 | |||||
| Asset impairments and other charges | $ | 60 | $ | 356 | $ | 209 | |||||
Acquisition-related costs | $ | 13 | $ | 84 | $ | 26 | |||||
| Exploration expense | $ | 249 | $ | 275 | $ | 441 | |||||
| Interest and debt expense, net | $ | 1,079 | $ | 1,169 | $ | 957 | |||||
PURCHASED COMMODITIES AND MIDSTREAM COST OF SALES
Purchased commodities and midstream cost of sales decreased in 2025, compared to 2024, due to certain crude supply contracts which expired in 2024.
OTHER OPERATING AND NON-OPERATING EXPENSE
Other operating and non-operating expense increased in 2025, compared to 2024, primarily due to higher compensation costs, adjustments to legal reserves, and increased research and development activities.
DEPRECIATION, DEPLETION, AND AMORTIZATION
Depreciation, depletion and amortization increased in 2025, compared to 2024, primarily related to increased sales volumes due to a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024.
ASSET IMPAIRMENTS AND OTHER CHARGES
Asset impairments in 2024 included $334 million related to certain wells in the Gulf of America whose future net cash inflows did not indicate that the asset value is recoverable.
OTHER ITEMS
Income (expense) millions | 2025 | 2024 | 2023 | ||||||||
Income from equity investments and other | $ | 76 | $ | 759 | $ | 426 | |||||
Income tax expense | $ | (1,021) | $ | (1,158) | $ | (1,330) | |||||
| Discontinued operations, net | $ | 262 | $ | 212 | $ | 1,364 | |||||
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INCOME FROM EQUITY INVESTMENTS AND OTHER
Income from equity investments and other decreased in 2025, compared to 2024, primarily due to the Company’s proportionate amount of impairments and other charges recorded by its equity method investees.
DISCONTINUED OPERATIONS, NET
Discontinued operations, net for all periods presented resulted from the OxyChem Transaction that closed on January 2, 2026. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.
Discontinued operations, net in 2024 also included a gain of $182 million, net of taxes, from the Andes Arbitration final legal settlement. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.
Select results for discontinued operations are reflected in the following table:
| millions | 2025 | 2024 | 2023 | ||||||||
| Income before income taxes | $ | 495 | $ | 285 | $ | 1,767 | |||||
| Income tax expense | (233) | (73) | (403) | ||||||||
| Income from discontinued operations, net of tax | $ | 262 | $ | 212 | $ | 1,364 | |||||
| Effective tax rate | 47 | % | 26 | % | 23 | % | |||||
Income before income taxes increased in 2025, compared to 2024, due to a 2024 pre-tax charge related to the DASS environmental remediation reserve of $925 million, partially offset by a gain of $239 million from the Andes Arbitration legal settlement in 2024 and lower chemical sales and higher raw material costs in 2025. Income taxes and the effective tax rate for discontinued operations increased from 2024 to 2025 primarily due to international tax charges as a result of the OxyChem Transaction.
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| INCOME TAXES | ||
Total deferred tax assets, after valuation allowance, were $2.6 billion and $2.4 billion as of December 31, 2025 and 2024, respectively. The Company expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The total deferred tax liabilities were $8.2 billion and $7.7 billion as of December 31, 2025 and 2024, respectively. See Note 9 - Income Taxes in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.
WORLDWIDE EFFECTIVE TAX RATE
The following table sets forth the calculation of the worldwide effective tax rate for income from continuing operations:
| millions | 2025 | 2024 | 2023 | ||||||||
| Income from continuing operations before taxes | $ | 3,128 | $ | 4,024 | $ | 4,662 | |||||
| Income tax benefit (expense) | |||||||||||
| Federal and state | (437) | (586) | (588) | ||||||||
| Foreign | (584) | (572) | (742) | ||||||||
Total income tax expense | (1,021) | (1,158) | (1,330) | ||||||||
Income from continuing operations | $ | 2,107 | $ | 2,866 | $ | 3,332 | |||||
| Worldwide effective tax rate | 33% | 29% | 28% | ||||||||
The Company’s worldwide effective tax rate in 2025, 2024 and 2023 was higher than the U.S. statutory rate of 21% and primarily driven by the Company’s jurisdictional mix of income from continuing operations, where international income is subject to tax at statutory rates as high as 55%. The reclassification of OxyChem, which is primarily domestic, to discontinued operations increased this impact.
LEGAL ENTITY REORGANIZATION
The IRS is currently reviewing the legal entity reorganization transaction as part of the Company’s 2022 federal tax audit. Following the acquisition of Anadarko and related divestitures, the Company reorganized its legal entities to better align with the nature of its business activities. This reorganization resulted in the Company making an adjustment to the tax basis in a portion of its operating assets, reducing deferred tax liabilities and recording a $2.7 billion tax benefit in 2022.
RECENT TAX LEGISLATION
The OBBBA was enacted on July 4, 2025 and introduced provisions expected to benefit the Company including accelerated depreciation for newly acquired and constructed assets, favorable adjustments to interest expense limitation, immediate deduction of research and development costs, and increased tax credit values for qualified CO2 projects. In accordance with ASC 740, the financial statement impact of the OBBBA was recognized beginning in the third quarter of 2025.
The OECD Pillar Two initiative proposes to apply a 15% global minimum tax on multinational entities, applied on a jurisdiction-by-jurisdiction basis. Several countries, including European Union member states, Canada and Oman, have enacted or are in the process of enacting legislation aligned with all or portions of Pillar Two. The Company continues to monitor and assess the impact of new OECD Pillar Two administrative guidance and Pillar Two compliant legislation proposed or enacted in the jurisdictions in which the Company operates. Based on developments to date, the Company does not anticipate any significant impact on the Company’s results of operations or cash flows from the enactment of Pillar Two legislation.
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| LIQUIDITY AND CAPITAL RESOURCES | ||
SOURCES AND USES OF CASH
The Company currently expects its operational cash flows and cash on hand to be sufficient to meet its current debt maturities and other obligations for the next 12 months from the date of this filing. As of December 31, 2025, the Company’s sources of liquidity included $2.0 billion of cash and cash equivalents and $4.15 billion of borrowing capacity under its RCF. Subsequent to December 31, 2025, but before the date of this filing, the Company used proceeds from the OxyChem Transaction to pay or satisfy and discharge the remaining balance of the term loan of $1.3 billion, current maturities of $270 million, and long-term maturities of $3.8 billion, leaving principal debt outstanding of $15 billion. Following these repayments, $24 million is due in 2026, $48 million in 2027, $14 million in 2028, $367 million in 2029 and $14.6 billion due in 2030 and thereafter.
The Company’s RCF expires on June 30, 2028, and has a borrowing capacity of $4.15 billion. There were no borrowings outstanding on the Company’s RCF as of December 31, 2025. As of December 31, 2025, and through the date of this filing, the Company was in compliance with all covenants in its financing agreements.
The Company’s planned 2026 capital expenditures are between $5.5 billion and $5.9 billion.
The Company is party to various purchase agreements that are not accounted for as leases or otherwise accrued as liabilities as of December 31, 2025. These agreements consist primarily of obligations to secure terminal, pipeline and processing capacity, purchase services used in the normal course of business including transporting and disposing of produced water, purchase goods used in oil and gas production and agreements relating to equipment maintenance and service. Refer to the line item “Purchase Obligations” in the table below under Contractual Obligations for the amounts that will be paid for such outstanding off-balance sheet purchase obligations from 2025 and thereafter.
CONTRACTUAL OBLIGATIONS
The following table summarizes and cross-references the Company’s contractual obligations and indicates on- and off-balance sheet obligations as of December 31, 2025. Commitments related to discontinued operations and liabilities of held for sale assets are excluded.
millions | Payments Due by Year | ||||||||||||||||
| Total | 2026 | 2027 and 2028 | 2029 and 2030 | 2031 and thereafter | |||||||||||||
| On-Balance Sheet | |||||||||||||||||
| Current portion of long-term debt (Note 5) | $ | 1,575 | $ | 1,575 | $ | — | $ | — | $ | — | |||||||
Long-term debt (Note 5) (a) | 18,852 | — | 2,411 | 4,373 | 12,068 | ||||||||||||
Expected interest payments on debt (b) | 11,616 | 1,213 | 2,197 | 1,884 | 6,322 | ||||||||||||
Leases (Note 6) (c) | 2,212 | 635 | 893 | 390 | 294 | ||||||||||||
| Asset retirement obligations (Note 1) | 4,553 | 381 | 535 | 677 | 2,960 | ||||||||||||
Other long-term liabilities (d) | 3,057 | — | 702 | 244 | 2,111 | ||||||||||||
| Off-Balance Sheet | |||||||||||||||||
Purchase obligations (e) | 12,617 | 3,038 | 4,699 | 2,627 | 2,253 | ||||||||||||
| Total | $ | 54,482 | $ | 6,842 | $ | 11,437 | $ | 10,195 | $ | 26,008 | |||||||
(a)Excluded unamortized debt premium, net, debt issuance costs and interest.
(b)As noted above, the Company has repaid or otherwise discharged $5.4 billion subsequent to December 31, 2025. Taking into account these debt repayments, expected interest payments on debt would be $934 million in 2026, $1.9 billion in 2027 and 2028, $1.8 billion in 2029 and 2030, and $6.3 billion in 2031 and thereafter, for a total of $10.9 billion.
(c)The Company is the lessee under various agreements for real estate, equipment, plants and facilities.
(d)Included long-term obligations under postretirement benefits, accrued transportation commitments, ad valorem taxes and other accrued liabilities.
(e)Amounts included payments which will become due under long-term agreements to purchase goods and services used in the normal course of business including, but not limited to, capital commitments to secure terminal, pipeline and processing capacity, CO2, drilling rigs and services, electrical power and non-lease components. Amounts excluded certain product purchase obligations related to marketing activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Long-term purchase contracts were discounted at a 5.44% discount rate.
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GUARANTEES
The Company has entered into various commitments, indemnities and guarantees provided by the Company to third parties, mainly to provide assurance that the Company or its consolidated subsidiaries or affiliates will meet their various obligations. In addition, the Company has entered into certain covenants, indemnities and guarantees related to the OxyChem Transaction. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.
As of the date of this filing, the Company has provided required financial assurance through a combination of cash, letters of credit and surety bonds. The Company has not issued any letters of credit under the RCF or other committed facilities. For additional information, see Risk Factors in Part I Item 1A of this Form 10-K.
CASH FLOW ANALYSIS
CASH PROVIDED BY OPERATING ACTIVITIES
| millions | 2025 | 2024 | 2023 | ||||||||
| Operating cash flow from continuing operations | $ | 9,606 | $ | 10,519 | $ | 10,235 | |||||
| Operating cash flow from discontinued operations | 926 | 920 | 2,073 | ||||||||
| Net cash provided by operating activities | $ | 10,532 | $ | 11,439 | $ | 12,308 | |||||
Continuing Operations
Cash flow provided by operating activities from continuing operations decreased in 2025, compared to 2024, primarily driven by higher use of cash in working capital related to higher tax payments in 2025, as certain 2024 tax payments were deferred into 2025 under the federal disaster relief program following 2024 Hurricane Beryl, and timing of payments for accounts payable and accrued liabilities.
Discontinued Operations
Cash flow provided by operating activities from discontinued operations was $926 million, $920 million and $2.1 billion in 2025, 2024 and 2023, respectively, primarily due to chemical segment income. In addition, the 2024 amount included a gain of $239 million from the Andes Arbitration legal settlement.
CASH USED BY INVESTING ACTIVITIES
| millions | 2025 | 2024 | 2023 | ||||||||
| Capital expenditures | |||||||||||
| Oil and gas | $ | (5,615) | $ | (5,320) | $ | (4,960) | |||||
| Midstream and marketing | (720) | (869) | (641) | ||||||||
| Corporate | (92) | (74) | (95) | ||||||||
| Total | $ | (6,427) | $ | (6,263) | $ | (5,696) | |||||
| Changes in capital accrual | 32 | 100 | (22) | ||||||||
| Purchase of businesses, assets and equity investments, net | (280) | (9,117) | (713) | ||||||||
| Proceeds from sale of assets and equity investments, net | 2,278 | 1,673 | 447 | ||||||||
| Other investing activities, net | (286) | (214) | (479) | ||||||||
| Investing cash flow from continuing operations | $ | (4,683) | $ | (13,821) | $ | (6,463) | |||||
| Investing cash flow from discontinued operations | (1,116) | (769) | (517) | ||||||||
Net cash used by investing activities | $ | (5,799) | $ | (14,590) | $ | (6,980) | |||||
Continuing Operations
Cash flow used by investing activities from continuing operations decreased by $9.1 billion in 2025 compared to 2024, The decrease was primarily attributable to the cash portion of the CrownRock Acquisition, which was paid in 2024.
Capital expenditures of $6.4 billion in 2025 were primarily related to continued development in the oil and gas segment, which included $3.4 billion related to the Permian Basin, $0.8 billion related to the Rockies, $0.5 billion related to GOA and the remainder to international locations. In 2024, capital expenditures of $6.3 billion were primarily related to development in
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the oil and gas segment, which included $3.1 billion related to the Permian Basin, $0.9 billion related to the Rockies, $0.8 billion related to GOA, and the remainder to international locations.
Midstream capital expenditures were primarily related to the completion of central processing facilities and continued work on Trains 3 and 4 at STRATOS.
The Company purchased $280 million of assets in 2025 primarily related to oil and gas properties, compared to $9.1 billion in 2024 of which $8.8 billion was related to the CrownRock Acquisition.
In 2025, the Company sold non-core assets for $2.3 billion, which included working interests in the Permian Basin for proceeds of approximately $800 million, non-operated proved and unproved royalty and mineral interests in the DJ Basin for proceeds of approximately $840 million and certain gas gathering assets in the Permian Basin for approximately $580 million. In 2024, the Company sold non-core assets in the Powder River Basin with near- to intermediate-term lease expirations and certain Delaware Basin assets in Texas and New Mexico for combined net proceeds of $769 million and 19.5 million of its limited partner units in WES for proceeds of $697 million. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for a listing of assets and equity investments acquired and sold in 2025, 2024 and 2023.
Discontinued Operations
Cash flow used by investing activities from discontinued operations in 2025, 2024 and 2023 was $1.1 billion, $769 million and $517 million, respectively, primarily due to capital expenditures associated with OxyChem.
CASH PROVIDED (USED) BY FINANCING ACTIVITIES
| millions | 2025 | 2024 | 2023 | ||||||||
| Proceeds from debt issuance | $ | — | $ | 9,612 | $ | (46) | |||||
| Payments of debt | (3,754) | (4,514) | (22) | ||||||||
| Preferred stock redemption | — | — | (1,661) | ||||||||
| Purchases of treasury stock | — | (27) | (1,798) | ||||||||
| Cash dividends paid | (1,594) | (1,446) | (1,365) | ||||||||
| Proceeds from issuance of common stock | 966 | 584 | 135 | ||||||||
| Other financing activities, net | (453) | (360) | (129) | ||||||||
| Financing cash flow from continuing operations | (4,835) | 3,849 | (4,886) | ||||||||
| Financing cash flow from discontinued operations | (9) | (5) | (4) | ||||||||
| Net cash provided (used) by financing activities | $ | (4,844) | $ | 3,844 | $ | (4,890) | |||||
In 2025, cash used by financing activities included payments of debt of $3.8 billion, dividends of $1.6 billion, and the final deferred payment for the Carbon Engineering acquisition of $0.4 billion. These payments were partially offset by proceeds from the issuance of stock of $1.0 billion, mainly from exercises of common stock warrants, and $200 million of contributions from noncontrolling interest related to the BlackRock joint venture for STRATOS.
Net cash provided by financing activities was $3.8 billion in 2024, which included net proceeds from debt issuance of $9.6 billion and proceeds from the issuance of common stock of $584 million primarily related to common stock warrant exercises, offset by debt repayment of $4.5 billion and cash dividends paid on common and preferred stock of $1.4 billion. See Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities in Part II of this Form 10-K and Note 13 - Stockholders’ Equity in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional information related to the Company’s share repurchases.
| LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES | ||
LEGAL MATTERS
For information on the Company’s Lawsuits, Claims, Commitments and Contingencies, see the information in Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
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| ENVIRONMENTAL EXPENDITURES | ||
Environmental expenditures relate to the prevention, monitoring, control, treatment or abatement of waste, spills, emissions or releases to air, water or land from the Company’s operations. These activities are generally integrated with ongoing operations or development projects and therefore are estimated using definitions and guidelines established by the American Petroleum Institute. The Company estimated the environmental expenditures to be approximately $874 million in 2025 compared to $663 million in 2024. Included in these expenditures were $402 million and $222 million in 2025 and 2024, respectively, related to longer-lived improvements in properties currently operated by the Company. They also included $472 million of operating expenses in 2025 and $441 million in 2024, which are incurred on a continual basis. While the Company does not expect these costs to fluctuate significantly in the near term, changes in environmental regulations may increase these costs. The environmental expenditures do not include litigation-related costs, including fines, penalties or settlements, the Company’s investments in low-carbon ventures, costs incurred to satisfy asset retirement obligations, or remediation expenses.
The Company’s remediation expenses related to ongoing operations, which are not included in the expenditures above, were $18 million in 2025 and $20 million in 2024. For discontinued operations, these costs were $64 million in 2025 and $56 million in 2024.
For additional information on the Company’s Environmental Liabilities and Expenditures, see the information in Note 11 - Environmental Liabilities and Expenditures in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
| GLOBAL INVESTMENTS | ||
A portion of the Company’s assets are located outside North America. The following table shows the geographic distribution of the Company’s assets as of December 31, 2025, at both the segment and consolidated level:
| millions | Oil and gas | Midstream and marketing | Corporate and other | Assets Held for Sale | Total Consolidated | ||||||||||||||||||||||||
| North America | |||||||||||||||||||||||||||||
| United States | $ | 55,735 | $ | 9,229 | $ | 3,372 | $ | 6,340 | $ | 74,676 | |||||||||||||||||||
| Canada | — | 1,638 | — | 85 | $ | 1,723 | |||||||||||||||||||||||
| Middle East | 3,743 | 2,861 | — | — | $ | 6,604 | |||||||||||||||||||||||
| North Africa and Other | 915 | 173 | — | 95 | $ | 1,183 | |||||||||||||||||||||||
| Consolidated | $ | 60,393 | $ | 13,901 | $ | 3,372 | $ | 6,520 | $ | 84,186 | |||||||||||||||||||
In 2025, net sales outside North America totaled $4.2 billion, or approximately 19% of total net sales, excluding discontinued operations.
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| CRITICAL ACCOUNTING POLICIES AND ESTIMATES | ||
The process of preparing financial statements in accordance with United States GAAP requires the Company’s management to make informed estimates and judgments regarding certain items and transactions. Changes in facts and circumstances or discovery of new information may result in revised estimates and judgments and actual results may differ from these estimates upon settlement, but generally not by material amounts. The selection and development of these policies and estimates have been discussed with the Audit Committee of the Board of Directors. The Company considers the following to be its most critical accounting policies and estimates that involve management’s judgment.
OIL AND GAS PROPERTIES
The carrying value of the Company’s PP&E represents the cost incurred to acquire or develop the asset, including any AROs and capitalized interest, net of DD&A and any impairment charges. For assets acquired in a business combination, PP&E cost is based on fair values at the acquisition date. AROs and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the useful lives of the related assets.
The Company uses the successful efforts method to account for its oil and gas properties. Under this method, the Company capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities and, in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
The Company expenses annual lease rentals, the costs of injectants used in production and geological and geophysical costs as incurred for exploration activities.
The Company determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. It amortizes leasehold acquisition costs over total proved reserves and capitalized development and successful exploration costs over proved developed reserves.
Proved oil and gas reserves are those quantities of oil and gas 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Several factors could change the Company’s proved oil and gas reserves. For example, the Company receives a share of production from PSCs to recover its costs and generally an additional share for profit. The Company’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Generally, the Company’s net economic benefit from these contracts is greater at higher product prices. In other cases, particularly with long-lived properties, lower product prices may lead to a situation where production of a portion of proved reserves becomes uneconomical. For such properties, higher product prices typically result in additional reserves becoming economical. Estimation of future production and development costs is also subject to change partially due to factors beyond the Company’s control, such as energy costs and inflation or deflation of oilfield service costs. These factors, in turn, could lead to changes in the quantity of proved reserves. Additional factors that could result in a change of proved reserves include production decline rates and operating performance differing from those estimated when the proved reserves were initially recorded. Changes in the political and regulatory climate, including new or amended laws and regulations or changes in the interpretation of those laws and regulations, could lead to decreases in proved reserves as development horizons may be extended into the future, changes to development locations may be necessary or such changes may result in higher development or operating costs.
The Company performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to significant and prolonged declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped on a field-by-field basis or by logical grouping of assets if there is a significant shared infrastructure. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change
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significantly over time. These assumptions include estimates of future production, product prices, contractual prices, estimates of risk-adjusted oil and gas proved and unproved reserves and estimates of future operating and development costs. It is reasonably possible that prolonged declines in commodity prices, reduced capital spending in response to lower prices, or increases in operating costs could result in impairments.
For impairment testing, unless prices are contractually fixed, the Company uses observable forward strip prices for oil and natural gas prices when projecting future cash flows. Future operating and development costs are estimated using the current cost environment applied to expectations of future operating and development activities to develop and produce oil and gas reserves. Market prices for oil, NGL and natural gas have been volatile and may continue to be volatile in the future. Changes in global supply and demand, transportation capacity, currency exchange rates, applicable laws and regulations and the effect of changes in these variables on market perceptions could impact current forecasts. Future fluctuations in commodity prices could cause estimates of future cash flows to vary significantly.
Net capitalized costs attributable to unproved properties were $7.7 billion as of December 31, 2025 and $10.2 billion as of December 31, 2024. The unproved amounts are not subject to DD&A until they are classified as proved properties. Individually insignificant unproved properties are combined and amortized on a group basis based on factors such as geographic location, lease terms, success rates and other factors to provide for full amortization upon lease expiration or abandonment.
Significant unproved properties are assessed individually for impairment and, when events or circumstances indicate that the carrying value of property may not be recovered, a valuation allowance is provided if an impairment is indicated. The Company periodically reviews significant unproved properties for impairments; numerous factors are considered, including, but not limited to, availability of funds for future exploration and development activities, current exploration and development plans, favorable or unfavorable exploration activity on the property or the adjacent property, geologists’ evaluation of the property, the current and projected political and regulatory climate, contractual conditions and the remaining lease term for the properties. If an impairment is indicated, the Company will first determine whether a comparable transaction for similar properties or implied acreage valuation derived from market participants is available and will adjust the carrying amount of the unproved property to its fair value using the market approach. In situations where the market approach is not observable and unproved reserves are available, undiscounted future net cash flows used in the impairment analysis are determined based on management’s risk-adjusted estimates of unproved reserves, future commodity prices and future costs to produce the reserves. If undiscounted future net cash flows are less than the carrying value of the property, the future net cash flows are discounted and compared to the carrying value for determining the amount of the impairment loss to record. The Company utilizes the same assumptions and methodology discussed above for cash flows associated with proved properties.
PROVED RESERVES
The Company estimates its proved oil and gas reserves according to the definition of proved reserves provided by the SEC’s Rule 4-10 (a) of Regulation S-X and the Financial Accounting Standards Board. Proved oil and gas reserves are those quantities of oil and gas 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Prices include consideration of price changes provided only by contractual arrangements and do not include adjustments based on expected future conditions. For reserves information, see the Supplemental Information on Oil and Gas Exploration and Production Activities under Item 8 of this Form 10-K.
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, development plans, reservoir performance, prices, economic conditions and government restrictions as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volume of proved reserves could have a negative impact on DD&A and could result in property impairments.
The most significant ongoing financial statement effect from a change in the Company’s oil and gas reserves or impairment of its proved properties would be to the DD&A rate. For example, a 5% increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $0.65/Boe, which would increase or decrease pre-tax income by approximately $350 million annually at current production rates.
FAIR VALUES
The Company estimates fair-value of long-lived assets for impairment testing, assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, pension plan assets and initial measurements of AROs.
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Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value, which may be determined using different methods of fair value measurements, largely based on the availability and quality of market information. The Company primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs.
FINANCIAL ASSETS AND LIABILITIES
The Company utilizes published prices or counterparty statements for valuing the majority of its financial assets and liabilities measured and reported at fair value. In addition to using market data, the Company makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For financial assets and liabilities carried at fair value, the Company measures fair value using the following methods:
■The Company values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as using quoted prices in active markets for the assets or liabilities (Level 1).
■OTC bilateral financial commodity contracts, international exchange contracts, options and physical commodity forward purchase and sale contracts are generally classified as using observable inputs other than quoted prices for the assets or liabilities (Level 2) and are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace.
■The Company values commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are generally unobservable in the marketplace or are observable but have been adjusted based upon various assumptions and the fair value is designated as using unobservable inputs (Level 3) within the valuation hierarchy.
■The Company values debt using market-observable information for debt instruments that are traded on secondary markets. For debt instruments that are not traded, the fair value is determined by interpolating the value based on debt with similar terms and credit risk.
NON-FINANCIAL ASSETS
The Company uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When the Company is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows and the expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment. The results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions.
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
The Company incurs environmental liabilities and expenditures with respect to both current operations and remediation of existing conditions from alleged past practices at Third-Party, Currently Operated, and Closed or Non-operated Sites, which categories may include NPL Sites. Those environmental liabilities and related charges and expenses for estimated remediation costs from alleged past practices are recorded when environmental remediation efforts are probable and the costs can be reasonably estimated. The Company discloses such remediation liabilities on a consolidated basis. In determining the environmental remediation liability and the range of reasonably possible additional losses, the Company refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. These environmental remediation liabilities are based on management’s estimate of the most likely cost to be incurred using the most cost-effective technology reasonably expected to achieve the remedial objective. The Company periodically reviews these environmental remediation liabilities and adjusts them as new information becomes available. The Company generally records reimbursements or recoveries of
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environmental remediation costs in income when received, or when receipt of recovery is highly probable.
Many factors could affect future remediation costs incurred by the Company and result in adjustments to environmental remediation liabilities and the range of reasonably possible additional losses. The most significant are: (i) cost estimates for remedial activities may vary from the initial estimate; (ii) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (iii) a regulatory agency may ultimately reject or modify proposed remedial plans; (iv) improved or alternative remediation technologies may change remediation costs; (v) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (vi) changes in allocation or cost-sharing arrangements may occur.
Certain sites involve multiple parties with various cost-sharing arrangements, which generally fall into the following three categories: (i) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among the Company and other alleged potentially responsible parties; (ii) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (iii) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, the affected subsidiary evaluates the financial viability of other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to such subsidiary of their failure to participate when estimating its ultimate share of liability. The Company records environmental remediation liabilities at their expected net cost of remedial activities. Based on these factors, except as otherwise disclosed in Note 11 - Environmental Liabilities and Expenditures in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K, the Company believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.
In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at CERCLA NPL sites, the Company’s environmental remediation liabilities include estimates of the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, the Company reviews and adjusts its environmental remediation liabilities accordingly.
If the Company were to adjust the balance of their environmental remediation liabilities based on the factors described above, the amount of the increase or decrease would be recognized in earnings. For example, if the balance were increased or reduced by 10%, the Company would record a pre-tax decrease or increase, respectively, to income of approximately $190 million.
INCOME TAXES
The Company files various U.S. federal, state and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). See Note 9 - Income Taxes in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.
LOSS CONTINGENCIES
The Company is involved in the normal course of business, in lawsuits, claims and other legal proceedings and audits. The Company accrues reserves as appropriate for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, the Company discloses, in aggregate on a consolidated basis, exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. The Company reviews such loss contingencies on an ongoing basis.
Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings or other factors. See Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional information.
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| SAFE HARBOR DISCUSSION REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA | ||
Portions of this report contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to: any projections of earnings, revenue or other financial items or future financial position or sources of financing; any statements of the plans, strategies and objectives of management for future operations or business strategy; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing. Words such as “estimate,” “project,” “predict,” “will,” “would,” “should,” “could,” “may,” “might,” “anticipate,” “plan,” “intend,” “believe,” “expect,” “aim,” “goal,” “target,” “objective,” “commit,” “advance,” “guidance,” “priority,” “focus,” “assumption,” “likely” or similar expressions that convey the prospective nature of events or outcomes are generally indicative of forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report unless an earlier date is specified. Unless legally required, the Company does not undertake any obligation to update, modify or withdraw any forward-looking statement as a result of new information, future events or otherwise.
Actual outcomes or results may differ from anticipated results, sometimes materially. Forward-looking and other statements regarding the Company’s sustainability efforts and aspirations are not an indication that these statements are necessarily material to investors or require disclosure in Occidental’s filings with the SEC. In addition, historical, current and forward-looking sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and definitions, assumptions, data sources and estimates or measurements that are subject to change in the future, including through rulemaking or guidance. Factors that could cause results to differ from those projected or assumed in any forward-looking statement include, but are not limited to: general economic conditions, including slowdowns and recessions, domestically or internationally; the Company’s indebtedness and other payment obligations, including the need to generate sufficient cash flows to fund operations; the Company’s ability to successfully monetize select assets and repay or refinance debt and the impact of changes in the Company’s credit ratings or future increases in interest rates; assumptions about energy markets; global and local commodity and commodity-futures pricing fluctuations and volatility; supply and demand considerations for, and the prices of, the Company’s products and services; actions by OPEC and non-OPEC oil producing countries; results from operations and competitive conditions; future impairments of the Company’s proved and unproved oil and gas properties or equity investments, or write-downs of productive assets, causing charges to earnings; unexpected changes in costs; government actions (including the effects of announced or future tariff increases and other geopolitical, trade, tariff, fiscal and regulatory uncertainties), war (including the Russia-Ukraine war and conflicts in the Middle East) and political conditions and events (such as in Latin America); inflation, its impact on markets and economic activity and related monetary policy actions by governments in response to inflation; availability of capital resources, levels of capital expenditures and contractual obligations; the regulatory approval environment, including the Company’s ability to timely obtain or maintain permits or other government approvals, including those necessary for drilling and/or development projects; the Company’s ability to successfully complete, or any material delay of, field developments, expansion projects, capital expenditures, efficiency projects, acquisitions or divestitures; risks associated with acquisitions, mergers and joint ventures, such as difficulties integrating businesses, uncertainty associated with financial projections or projected synergies, restructuring, increased costs and adverse tax consequences; uncertainties and liabilities associated with acquired and divested properties and businesses, including retained liabilities and indemnification obligations associated with the chemical business; uncertainties about the estimated quantities of oil, NGL and natural gas reserves; lower-than-expected production from development projects or acquisitions; the Company’s ability to realize the anticipated benefits from prior or future streamlining actions to reduce fixed costs, simplify or improve processes and improve the Company’s competitiveness; exploration, drilling and other operational risks; disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver the Company’s oil and natural gas and other processing and transportation considerations; volatility in the securities, capital or credit markets, including capital market disruptions and instability of financial institutions; HSE risks, costs and liability under existing or future federal, regional, state, provincial, tribal, local and international HSE laws, regulations and litigation (including related to climate change or remedial actions or assessments); legislative or regulatory changes, including changes relating to hydraulic fracturing or other oil and natural gas operations, retroactive royalty or production tax regimes, and deep-water and onshore drilling and permitting regulations; the Company’s ability to recognize intended benefits from its business strategies and initiatives, such as the OxyChem Transaction, the Company’s low-carbon ventures businesses and announced GHG emissions reduction targets or net-zero goals; changes in government grant or loan programs; potential liability resulting from pending or future litigation, government investigations and other proceedings; disruption or interruption of production or facility damage due to accidents, chemical releases, labor unrest, weather, power outages, natural disasters, cyber-attacks, terrorist acts or insurgent activity; the scope and duration of global or regional health pandemics or epidemics and actions taken by government authorities and other third parties in connection therewith; the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners and other parties; failure of risk management; the Company’s ability to retain and hire key personnel; supply, transportation and labor constraints; reorganization or restructuring of the Company’s operations; changes in state, federal or international tax rates, deductions, incentives or credits; and actions by third parties that are beyond the Company’s control.
Additional information concerning these and other factors that may cause the Company’s results of operations and financial position to differ from expectations can be found in Item 1A, “Risk Factors” and elsewhere in this Form 10-K, as well as in the Company’s other filings with the SEC, including the Company’s Quarterly Reports on Form 10-Q and Current Reports on Form 8-K.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
| COMMODITY PRICE RISK | ||
GENERAL
The Company’s results are sensitive to fluctuations in oil, NGL and natural gas prices. Price changes at global prices and levels of production affect the Company’s budgeted 2026 pre-tax cash by approximately $240 million for a $1 per barrel change in WTI price and approximately $25 million for a $1 per barrel change in Brent price. If domestic natural gas prices varied by $0.50 per Mcf, it would have an estimated annual effect on the Company’s budgeted 2026 pre-tax cash of approximately $120 million. These price-change sensitivities include the impact of PSC and similar contract volume changes on income. If production levels differ from the Company’s 2026 budgeted production, the sensitivity of the Company’s results to prices also will change. Marketing results are sensitive to price changes of oil, natural gas and, to a lesser degree, NGL, sulfur and CO2. A $0.25 change in the Midland-to-Gulf-Coast oil spreads impacts budgeted 2026 pre-tax cash by approximately $55 million.
RISK MANAGEMENT
The Company conducts its risk management activities for marketing and trading under the controls and governance of its risk policies. The controls under these policies are implemented and enforced by regulatory compliance and market and credit risk groups which monitor risks by providing independent and separate evaluations and checks. Controls for these activities include limits on value at risk, credit and asset hedges as well as segregation of duties, delegation of authority, price verifications and review of various key performance indicators.
FAIR VALUE OF MARKETING DERIVATIVE CONTRACTS
The Company carries derivative contracts it enters into in connection with its marketing activities at fair value. Fair values for these contracts are derived from Level 1 and Level 2 sources. The fair values in future maturity periods are insignificant.
The following table shows the fair value of the Company’s derivatives (excluding collateral), segregated by maturity periods and by methodology of fair value estimation:
| Maturity Periods | |||||||||||||||||
Source of Fair Value Assets (Liabilities) millions | 2026 | 2027 and 2028 | 2029 and 2030 | 2031 and thereafter | Total | ||||||||||||
Prices actively quoted | $ | 9 | $ | — | $ | — | $ | — | $ | 9 | |||||||
Prices provided by other external sources | 26 | 1 | — | — | 27 | ||||||||||||
| Total | $ | 35 | $ | 1 | $ | — | $ | — | $ | 36 | |||||||
QUANTITATIVE INFORMATION
The Company uses value at risk to estimate the potential effects of changes in fair values of commodity contracts used in trading activities. This measure determines the maximum potential negative one day change in fair value with a 95% level of confidence. Additionally, the Company uses complementary trading limits including position and tenor limits and maintains liquid positions as a result of which market risk typically can be neutralized or mitigated on short notice. As a result of these controls, the Company believes that the market risk of its trading activities is not reasonably likely to have a material adverse effect on its performance.
52 | OXY 2025 FORM 10-K | ||||
| table of contents | QUANTITATIVE AND QUALITATIVE DISCLOSURES | ||||||
| INTEREST RATE RISK | ||
GENERAL
As of December 31, 2025, the Company had fixed rate debt with a fair value of $19.4 billion outstanding. A 25-basis point change in Treasury rates would change the fair value of the fixed rate debt approximately $300 million.
As of December 31, 2025, the Company had variable rate debt with a notional value of $1.3 billion outstanding. A 25-basis point increase in SOFR interest rates would increase gross interest expense $3.0 million per year.
The table below provides information about the Company’s long-term debt obligations as of December 31, 2025. Debt amounts represent principal payments by maturity date.
| millions except percentages | U.S. Dollar Fixed-Rate Debt | U.S. Dollar Variable-Rate Debt | Total (a) | ||||||||
| 2026 | $ | 295 | $ | 1,280 | $ | 1,575 | |||||
| 2027 | 1,503 | — | 1,503 | ||||||||
| 2028 | 906 | — | 906 | ||||||||
| 2029 | 1,853 | — | 1,853 | ||||||||
| 2030 | 2,449 | 68 | 2,517 | ||||||||
| Thereafter | 12,073 | — | 12,073 | ||||||||
| Total | $ | 19,079 | $ | 1,348 | $ | 20,427 | |||||
| Weighted-average interest rate | 6.10 | % | 5.42 | % | 6.05 | % | |||||
| Fair Value | $ | 19,424 | $ | 1,354 | $ | 20,778 | |||||
(a)Excluded unamortized debt premiums, net of $1.1 billion and debt issuance costs of $84 million. See Note 5 Long-Term Debt for information regarding debt activity at the date of filing.
| FOREIGN CURRENCY RISK | ||
The Company’s international operations have limited currency risk. The Company manages its exposure primarily by balancing monetary assets and liabilities and limiting cash positions in foreign currencies to levels necessary for operating purposes. A vast majority of international oil sales are denominated in United States dollars. Additionally, all of the Company’s consolidated international oil and gas subsidiaries have the United States dollar as the functional currency. The effect of exchange rates on transactions in foreign currencies is included in periodic income.
| CREDIT RISK | ||
The majority of the Company’s counterparty credit risk is related to the physical delivery of energy commodities to its customers and any inability of these customers to meet their settlement commitments. The Company manages credit risk by selecting counterparties that it believes to be financially strong, by entering into netting arrangements with counterparties and by requiring collateral or other credit risk mitigants, as appropriate. The Company actively evaluates the creditworthiness of its counterparties, assigns appropriate credit limits and monitors credit exposures against those assigned limits. The Company also enters into futures contracts through regulated exchanges with select clearinghouses and brokers, which are subject to minimal credit risk, if any.
As of December 31, 2025, the substantial majority of the credit exposures were with investment grade counterparties. The Company believes its exposure to credit-related losses as of December 31, 2025 was not material and losses associated with credit risk have been insignificant for all years presented.
OXY 2025 FORM 10-K | 53 | ||||
| table of contents | FINANCIAL STATEMENTS INDEX | ||||||
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| INDEX TO CONSOLIDATED FINANCIAL STATEMENTS | PAGE | ||||
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements | 55 | ||||
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting | 57 | ||||
Consolidated Balance Sheets | 58 | ||||
Consolidated Statements of Operations | 60 | ||||
Consolidated Statements of Comprehensive Income | 61 | ||||
Consolidated Statements of Equity | 62 | ||||
Consolidated Statements of Cash Flows | 63 | ||||
Notes to Consolidated Financial Statements | 65 | ||||
Note 1 - Summary of Significant Accounting Policies | 65 | ||||
Note 2 - Revenue | 73 | ||||
Note 3 - Investments and Related-Party Transactions | 76 | ||||
Note 4 - Acquisitions, Divestitures and Other Transactions | 77 | ||||
Note 5 - Long-term Debt | 82 | ||||
Note 6 - Lease Commitments | 85 | ||||
Note 7 - Derivatives | 86 | ||||
Note 8 - Fair Value Measurements | 87 | ||||
Note 9 - Income Taxes | 88 | ||||
Note 10 - Retirement and Postretirement Benefit Plans | 93 | ||||
Note 11 - Environmental Liabilities and Expenditures | 97 | ||||
Note 12 - Lawsuits, Claims, Commitments and Contingencies | 99 | ||||
Note 13 - Stockholders’ Equity | 101 | ||||
Note 14 - Stock-Based Incentive Plans | 103 | ||||
Note 15 - Industry Segments and Geographic Areas | 106 | ||||
Supplemental Quarterly Financial Data (Unaudited) | 109 | ||||
Supplemental Oil and Gas Information (Unaudited) | 110 | ||||
54 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS REPORT | ||||||
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Occidental Petroleum Corporation:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 18, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Assessment of the estimated proved oil and gas reserves on the determination of depletion expense related to proved oil and gas properties.
As discussed in Note 1 to the consolidated financial statements, the Company determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. Under this method, capitalized costs are amortized over estimated proved reserves. For the year ended December 31, 2025, the Company recorded depreciation and depletion expense related to proved oil and gas properties of $7.1 billion.
We identified the assessment of the estimated proved oil and gas reserves on the determination of depreciation and depletion expense related to proved oil and gas properties as a critical audit matter. Complex auditor judgment was required to assess the Company’s estimate of proved oil and gas reserves, which is a key input for the determination of depreciation and depletion expense. Estimating proved oil and gas reserves requires the expertise of professional petroleum reservoir engineers. The key assumptions included estimated future production quantities and estimated operating and capital costs.
OXY 2025 FORM 10-K | 55 | ||||
| table of contents | FINANCIAL STATEMENTS REPORT | ||||||
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depreciation and depletion process, including the estimation of proved oil and gas reserves. We analyzed and assessed the determination of depreciation and depletion expense for compliance with industry and regulatory standards. We assessed compliance of the methodology used by the Company’s engineering and technical staff to estimate proved oil and gas reserves with industry and regulatory standards. We read the findings of the independent reservoir engineering specialist’s review of the methods and procedures used by the Company in estimating the proved reserves for compliance with industry and regulatory standards. To assess the Company’s ability to accurately estimate future production quantities, we compared the future production quantity assumptions used by the Company in prior periods to the actual production amounts. We compared the estimated future production quantities used by the Company in the current period to historical production rates. We evaluated the operating and capital cost assumptions used by the Company by comparing them to historical costs incurred. We evaluated the professional qualifications and the knowledge, skills, and ability of the Company’s internal reserve engineers and the independent reservoir engineering specialists engaged by the Company.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 18, 2026
56 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS REPORT | ||||||
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Occidental Petroleum Corporation:
Opinion on Internal Control Over Financial Reporting
We have audited Occidental Petroleum Corporation and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 18, 2026 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Assessment of and Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Houston, Texas
February 18, 2026
OXY 2025 FORM 10-K | 57 | ||||
| table of contents | FINANCIAL STATEMENTS | ||||||
| Consolidated Balance Sheets | Occidental Petroleum Corporation and Subsidiaries | ||||
| December 31, | ||||||||
| millions | 2025 | 2024 | ||||||
| ASSETS | ||||||||
| CURRENT ASSETS | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Trade receivables | ||||||||
| Joint interest receivables | ||||||||
| Inventories | ||||||||
| Assets held for sale | ||||||||
| Other current assets | ||||||||
| Total current assets | ||||||||
| PROPERTY, PLANT AND EQUIPMENT | ||||||||
| Oil and gas | ||||||||
| Midstream and marketing | ||||||||
| Corporate | ||||||||
| Accumulated depreciation, depletion and amortization | ( | ( | ||||||
| Total property, plant and equipment, net | ||||||||
| NON-CURRENT ASSETS | ||||||||
| Operating lease assets | ||||||||
| Investments in unconsolidated entities | ||||||||
| Non-current assets held for sale | ||||||||
| Other long-term assets | ||||||||
| Total non-current assets | ||||||||
| TOTAL ASSETS | $ | $ | ||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
58 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS | ||||||
| Consolidated Balance Sheets | Occidental Petroleum Corporation and Subsidiaries | ||||
| December 31, | ||||||||
| millions except share and per-share amounts | 2025 | 2024 | ||||||
| LIABILITIES AND EQUITY | ||||||||
| CURRENT LIABILITIES | ||||||||
| Current maturities of long-term debt | $ | $ | ||||||
| Accounts payable | ||||||||
| Accrued liabilities | ||||||||
| Liabilities held for sale | ||||||||
| Total current liabilities | ||||||||
| LONG-TERM DEBT, NET | ||||||||
| DEFERRED CREDITS AND OTHER LIABILITIES | ||||||||
| Deferred income taxes, net | ||||||||
| Asset retirement obligations | ||||||||
| Non-current liabilities held for sale | ||||||||
| Other deferred credits and liabilities | ||||||||
| Total deferred credits and other liabilities | ||||||||
| EQUITY | ||||||||
Preferred stock, at $ | ||||||||
Common stock, $ | ||||||||
Treasury stock: 2025 — | ( | ( | ||||||
| Additional paid-in capital | ||||||||
| Retained earnings | ||||||||
Accumulated other comprehensive income | ||||||||
| Total stockholders’ equity | ||||||||
| Noncontrolling interest | ||||||||
Total equity | ||||||||
| TOTAL LIABILITIES AND EQUITY | $ | $ | ||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
OXY 2025 FORM 10-K | 59 | ||||
| table of contents | FINANCIAL STATEMENTS | ||||||
| Consolidated Statements of Operations | Occidental Petroleum Corporation and Subsidiaries | ||||
| Years Ended December 31, | |||||||||||
| millions except per-share amounts | 2025 | 2024 | 2023 | ||||||||
| REVENUES AND OTHER INCOME | |||||||||||
| Net sales | $ | $ | $ | ||||||||
| Interest, dividends and other income | |||||||||||
| Gains (losses) on sales of assets and other, net | ( | ||||||||||
| Total | |||||||||||
| COSTS AND OTHER DEDUCTIONS | |||||||||||
Oil and gas lease operating expense | |||||||||||
| Transportation and gathering expense | |||||||||||
| Purchased commodities and midstream cost of sales | |||||||||||
| Selling, general and administrative expense | |||||||||||
| Other operating and non-operating expense | |||||||||||
| Taxes other than on income | |||||||||||
| Depreciation, depletion and amortization | |||||||||||
| Asset impairments and other charges | |||||||||||
Acquisition-related costs | |||||||||||
| Exploration expense | |||||||||||
| Interest and debt expense, net | |||||||||||
| Total | |||||||||||
Income before income taxes and other items | |||||||||||
| OTHER ITEMS | |||||||||||
Income from equity investments and other | |||||||||||
| Total | |||||||||||
Income from continuing operations before income taxes | |||||||||||
Income tax expense | ( | ( | ( | ||||||||
Income from continuing operations | |||||||||||
| Income from discontinued operations, net of tax | |||||||||||
NET INCOME | |||||||||||
| Less: Net income attributable to noncontrolling interest | ( | ( | |||||||||
Less: Preferred stock dividends and redemption premiums | ( | ( | ( | ||||||||
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ | $ | $ | ||||||||
| PER COMMON SHARE | |||||||||||
Income from continuing operations—basic | $ | $ | $ | ||||||||
| Discontinued operations—basic | |||||||||||
Net income attributable to common stockholders—basic | $ | $ | $ | ||||||||
Income from continuing operations—diluted | $ | $ | $ | ||||||||
| Discontinued operations—diluted | |||||||||||
Net income attributable to common stockholders—diluted | $ | $ | $ | ||||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
60 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS | ||||||
Consolidated Statements of Comprehensive Income | Occidental Petroleum Corporation and Subsidiaries | ||||
| Years Ended December 31, | |||||||||||
| millions | 2025 | 2024 | 2023 | ||||||||
Net income | $ | $ | $ | ||||||||
| Other comprehensive income (loss) items: | |||||||||||
| Gains (losses) on derivatives | ( | ( | |||||||||
| Pension and postretirement gains (losses) | ( | ||||||||||
| Other | ( | ||||||||||
| Other comprehensive income (loss), net of tax | ( | ||||||||||
Comprehensive income | |||||||||||
| Less: Comprehensive income attributable to noncontrolling interest | ( | ( | |||||||||
Comprehensive income attributable to preferred and common stockholders | $ | $ | $ | ||||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
OXY 2025 FORM 10-K | 61 | ||||
| table of contents | FINANCIAL STATEMENTS | ||||||
Consolidated Statements of Equity | Occidental Petroleum Corporation and Subsidiaries | ||||
| Equity Attributable to Common Stock | ||||||||||||||||||||||||||
| Preferred Stock | Common Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total Equity | |||||||||||||||||||
| Balance, December 31, 2022 | $ | $ | $ | ( | $ | $ | $ | $ | $ | |||||||||||||||||
| Net income | — | — | — | — | — | — | ||||||||||||||||||||
| Other comprehensive income, net of tax | — | — | — | — | — | — | ||||||||||||||||||||
Dividends on common stock, $ | — | — | — | — | ( | — | — | ( | ||||||||||||||||||
Dividends on preferred stock, $ | — | — | — | — | ( | — | — | ( | ||||||||||||||||||
| Preferred stock redemption – face value | ( | — | — | — | — | — | — | ( | ||||||||||||||||||
| Preferred stock redemption – premium | — | — | — | — | ( | — | — | ( | ||||||||||||||||||
| Preferred stock redemption – amortization of carrying value | — | — | — | ( | — | — | ||||||||||||||||||||
| Shareholder warrants exercised | — | — | — | — | — | |||||||||||||||||||||
| Options exercised | — | — | — | — | — | — | ||||||||||||||||||||
| Issuance of common stock and other, net | — | — | — | — | — | |||||||||||||||||||||
| Purchases of treasury stock | — | — | ( | — | — | — | — | ( | ||||||||||||||||||
| Noncontrolling interest contributions, net | — | — | — | — | — | — | ||||||||||||||||||||
| Balance, December 31, 2023 | $ | $ | $ | ( | $ | $ | $ | $ | $ | |||||||||||||||||
| Net income | — | — | — | — | — | |||||||||||||||||||||
| Other comprehensive income, net of tax | — | — | — | — | — | ( | — | ( | ||||||||||||||||||
Dividends on common stock, $ | — | — | — | — | ( | — | — | ( | ||||||||||||||||||
Dividends on preferred stock, $ | — | — | — | — | ( | — | — | ( | ||||||||||||||||||
| Shareholder warrants exercised | — | — | — | — | — | |||||||||||||||||||||
| Issuance of common stock and other, net | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases of treasury stock | — | — | ( | — | — | — | — | ( | ||||||||||||||||||
| Common stock issued for CrownRock acquisition | — | — | — | — | — | |||||||||||||||||||||
| Noncontrolling interest contributions, net | — | — | — | — | — | — | ||||||||||||||||||||
Balance, December 31, 2024 | $ | $ | $ | ( | $ | $ | $ | $ | $ | |||||||||||||||||
| Net income | — | — | — | — | — | |||||||||||||||||||||
| Other comprehensive loss, net of tax | — | — | — | — | — | — | ||||||||||||||||||||
Dividends on common stock, $ | — | — | — | — | ( | — | — | ( | ||||||||||||||||||
Dividends on preferred stock, $ | — | — | — | — | ( | — | — | ( | ||||||||||||||||||
| Shareholder warrants exercised | — | — | — | — | — | |||||||||||||||||||||
| Issuance of common stock and other, net of cancellations | — | — | — | — | — | |||||||||||||||||||||
| Noncontrolling interest contributions, net | — | — | — | — | — | — | ||||||||||||||||||||
Balance, December 31, 2025 | $ | $ | $ | ( | $ | $ | $ | $ | $ | |||||||||||||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
62 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS | ||||||
| Consolidated Statements of Cash Flows | Occidental Petroleum Corporation and Subsidiaries | ||||
| Years Ended December 31, | |||||||||||
| millions | 2025 | 2024 | 2023 | ||||||||
| CASH FLOW FROM OPERATING ACTIVITIES | |||||||||||
| Net income | $ | $ | $ | ||||||||
| Adjustments to reconcile net income to net cash from operating activities: | |||||||||||
| Discontinued operations, net | ( | ( | ( | ||||||||
| Depreciation, depletion and amortization of assets | |||||||||||
| Deferred income tax provision (benefit) | ( | ||||||||||
| Other noncash charges to income | |||||||||||
| Asset impairments | |||||||||||
| Losses (gains) on sales of assets and other, net | ( | ( | |||||||||
| Undistributed losses (earnings) from equity investments | ( | ||||||||||
| Dry hole expense | |||||||||||
| Changes in operating assets and liabilities: | |||||||||||
| (Increase) decrease in trade receivables | ( | ||||||||||
| (Increase) decrease in inventories | ( | ( | |||||||||
| (Increase) decrease in joint interest receivables and other current assets | ( | ( | |||||||||
| Decrease in accounts payable and accrued liabilities | ( | ( | ( | ||||||||
| Increase (decrease) in current domestic and foreign income taxes | ( | ||||||||||
| Operating cash flow from continuing operations | |||||||||||
| Operating cash flow from discontinued operations | |||||||||||
| Net cash provided by operating activities | |||||||||||
| CASH FLOW FROM INVESTING ACTIVITIES | |||||||||||
| Capital expenditures | ( | ( | ( | ||||||||
| Change in capital accrual | ( | ||||||||||
| Purchases of assets, businesses and equity investments, net | ( | ( | ( | ||||||||
| Proceeds from sale of assets and equity investments, net | |||||||||||
| Equity investments and other, net | ( | ( | ( | ||||||||
| Investing cash flow from continuing operations | ( | ( | ( | ||||||||
| Investing cash flow from discontinued operations | ( | ( | ( | ||||||||
| Net cash used by investing activities | ( | ( | ( | ||||||||
| CASH FLOW FROM FINANCING ACTIVITIES | |||||||||||
| Draws on receivables securitization facility | |||||||||||
| Payment of receivables securitization facility | ( | ||||||||||
| Proceeds from long-term debt, net | ( | ||||||||||
| Payments of long-term debt, net | ( | ( | ( | ||||||||
| Redemption of preferred stock | ( | ||||||||||
| Purchases of treasury stock | ( | ( | |||||||||
| Cash dividends paid on common and preferred stock | ( | ( | ( | ||||||||
| Proceeds from issuance of common stock | |||||||||||
| Contributions from noncontrolling interest | |||||||||||
| Deferred payments for purchases of assets and businesses | ( | ( | |||||||||
| Other financing, net | ( | ( | ( | ||||||||
| Financing cash flow from continuing operations | ( | ( | |||||||||
| Financing cash flow from discontinued operations | ( | ( | ( | ||||||||
| Net cash provided (used) by financing activities | ( | ( | |||||||||
| Increase (decrease) in cash, cash equivalents, restricted cash and restricted cash equivalents | ( | ||||||||||
| Cash, cash equivalents, restricted cash and restricted cash equivalents — beginning of year | |||||||||||
| Cash, cash equivalents, restricted cash and restricted cash equivalents — end of year | $ | $ | $ | ||||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
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| Consolidated Statements of Cash Flows | Occidental Petroleum Corporation and Subsidiaries | ||||
| Years Ended December 31, | |||||||||||
| millions | 2025 | 2024 | 2023 | ||||||||
| CASH, CASH EQUIVALENTS, RESTRICTED CASH AND RESTRICTED CASH EQUIVALENTS BALANCES FROM: | |||||||||||
| Continuing operations - beginning of year | $ | $ | $ | ||||||||
Discontinued operations - beginning of year (a) | |||||||||||
Less: discontinued operations - end of year (a) | |||||||||||
| Continuing operations - end of year | |||||||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
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| Notes to Consolidated Financial Statements | Occidental Petroleum Corporation and Subsidiaries | ||||
| NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||
NATURE OF OPERATIONS
The Company conducts its operations through various subsidiaries and affiliates. The Company’s principal business consists of two reporting segments: oil and gas and midstream and marketing. The oil and gas segment explores for, develops and produces oil (which includes condensate), NGL and natural gas.
The midstream and marketing segment purchases, markets, gathers, processes, transports and stores oil (which includes condensate), NGL, natural gas, CO2 and power. It also optimizes its transportation and storage capacity, and invests in entities that conduct similar activities, such as WES. The midstream and marketing segment also includes OLCV. OLCV seeks to leverage the Company’s legacy of carbon management experience to develop CCUS projects, including the commercialization of DAC technology, and invests in other low-carbon technologies intended to reduce GHG emissions from the Company’s operations and strategically partner with other industries to help reduce their emissions.
PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements have been prepared in conformity with GAAP and include the accounts of the Company, its subsidiaries, its undivided interests in oil and gas exploration and production ventures, and variable interest entities for which the Company was the primary beneficiary. The Company accounts for its share of oil and gas exploration and production ventures by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets, statements of operations and statements of cash flows.
INVESTMENTS IN UNCONSOLIDATED ENTITIES
WES INVESTMENT
WES is a publicly traded limited partnership with its limited partner units traded on the NYSE under the ticker symbol “WES.” As of December 31, 2025, the Company owned all of the 2.2 % non-voting general partner interest, 40.6 % of the WES limited partner units, and a 2 % non-voting limited partner interest in WES Operating, a subsidiary of WES. As of December 31, 2025, the Company’s combined share of net income from WES and its subsidiaries was 43.1 %. In February 2026, in connection with certain contract amendments, the Company transferred 15.3 million units to WES; after this transfer the combined share of net income in WES and its subsidiaries is 40.9 %. See Note 3 - Investment and Related-Party Transactions for further information.
NONCONTROLLING INTEREST
The Company and BlackRock formed a joint venture for the continued development of the first commercial scale direct air capture facility. The joint venture is a VIE and the Company consolidates the VIE as it is the primary beneficiary. BlackRock’s investment is accounted for as an NCI. Each party has committed to make additional investments towards the completion of the direct air capture facility. As of December 31, 2025, BlackRock has invested $500 million of its total commitment of $550 million. In addition, the Company has entered into agreements with the joint venture related to project management, operations and maintenance and carbon removal offtake. The Company may incur additional payments to the joint venture if certain construction and operational thresholds are not met.
The Company may call the NCI on June 30, 2035 or earlier if the plant does not achieve commercial operations or ceases and permanently discontinues operations. Dividends from the joint venture will be distributed preferentially to the NCI up to a return threshold, then preferentially to the Company thereafter. The NCI receives preferential distributions in liquidation.
Because distributions from the joint venture will not be consistent over time, or with the initial investments or ownership interest, the Company has determined that the appropriate methodology for attributing income and loss from the joint venture is the hypothetical liquidation at book value method. Under this method, the amounts of income and loss attributed
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DISCONTINUED OPERATIONS
In October 2025, the Company announced entry into a purchase and sale agreement with Berkshire Hathaway (the Purchase Agreement) to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion, subject to customary purchase price adjustments. The OxyChem Transaction closed on January 2, 2026.
An Occidental subsidiary will retain environmental liabilities relating to legacy sites. Additionally, under the Purchase Agreement, there are post-closing indemnification obligations for (i) legacy environmental liabilities and (ii) pre-closing liabilities of OxyChem, including pre-closing environmental liabilities, in each case, subject to certain limitations and procedures.
Certain Occidental subsidiaries entered into other definitive agreements with OxyChem following the close of the transaction, including, among others, (i) a Transition Services Agreement, pursuant to which the Company will provide certain transition services for a period of time, and (ii) a Remediation Management Agreement, pursuant to which an Occidental subsidiary will manage certain remedial projects. Occidental also entered into a guaranty in favor of Berkshire Hathaway, pursuant to which Occidental guarantees the indemnification obligations of its subsidiaries under the Purchase Agreement.
As a result of our agreement to sell OxyChem, the following changes in our basis of presentation have occurred:
■In accordance with ASC 205, Discontinued Operations, intersegment sales from our oil and gas and midstream and marketing segments to the chemical segment are no longer eliminated as intercompany transactions. All periods presented have been retrospectively adjusted to reflect this change.
■Beginning October 1, 2025, in accordance with ASC 360, Property, Plant, and Equipment (PP&E), depreciation and amortization were no longer recorded for the chemical segment’s PP&E and right of use lease assets.
Unless otherwise indicated, information presented in the Notes to Consolidated Financial Statements relates only to the Company’s continuing operations. Additional information related to discontinued operations is included in Note 4 - Acquisitions, Divestitures and Other Transactions and in some instances, where appropriate, is included as a separate disclosure within the individual Notes to Consolidated Financial Statements.
RISKS AND UNCERTAINTIES
The process of preparing Consolidated Financial Statements in conformity with GAAP requires the Company’s management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of the Company’s financial statements. The Company establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets is dependent upon the Company generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.
The accompanying Consolidated Financial Statements include assets of approximately $7.8 billion as of December 31, 2025 and net sales of approximately $4.2 billion in 2025 relating to the Company’s operations in countries outside North America. The Company is exposed to various risks, because certain of its international operations are located in countries which could be affected by political or civil instability, OPEC production restrictions, equipment import restrictions and sanctions. Exposure to such risks may increase if a greater percentage of the Company’s future oil and gas production or revenue comes from international sources. The Company attempts to conduct its affairs so as to mitigate its exposure to such risks and would seek compensation in the event of nationalization.
RECEIVABLES AND OTHER CURRENT ASSETS
Trade receivables, net of $2.6 billion and $2.8 billion as of December 31, 2025 and 2024, respectively, represent rights to payment for which the Company had satisfied its obligations under a contract with a customer and its right to payment was conditioned only on the passage of time. The allowance for doubtful accounts was insignificant as of December 31, 2025 and 2024.
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INVENTORIES
Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Oil, NGL and natural gas inventories are valued at the lower of cost or market.
Commodity inventory primarily represents oil, which is carried at the lower of weighted-average cost or net realizable value. Inventories consisted of the following as of December 31:
| millions | 2025 | 2024 | ||||||
| Materials and supplies | $ | $ | ||||||
| Commodity inventory | ||||||||
| Total | $ | $ | ||||||
PROPERTY, PLANT AND EQUIPMENT
OIL AND GAS
The carrying value of the Company’s PP&E represents the cost incurred to acquire or develop the asset, including any AROs and capitalized interest, net of accumulated DD&A and any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. AROs and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.
The Company uses the successful efforts method to account for its oil and gas properties. Under this method, the Company capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Balance — beginning of year | $ | $ | $ | ||||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | |||||||||||
Reclassifications to property, plant and equipment based on the determination of proved reserves | ( | ( | ( | ||||||||
Capitalized exploratory well costs charged to expense | ( | ( | ( | ||||||||
| Balance — end of year | $ | $ | $ | ||||||||
The Company expenses annual lease rentals, the costs of injectants used in production and geological and geophysical costs as incurred.
The Company determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. It amortizes leasehold costs over total proved reserves and capitalized development and successful exploration costs over proved developed reserves.
Proved oil and gas reserves are those quantities of oil and gas 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 prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved reserves include PUD reserves. PUD reserves are supported by a management-approved, detailed, field-level development plan where sufficient capital has been committed to develop those reserves. Only PUD reserves which are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the PUD reserves are expected to be developed beyond the five years and are tied to approved long-term development projects.
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The Company performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to significant and prolonged declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include estimates of future production, product prices, contractual prices, estimates of risk-adjusted oil and gas proved and unproved reserves and estimates of future operating and development costs. It is reasonably possible that prolonged declines in commodity prices, reduced capital spending in response to lower prices, or increases in operating costs could result in additional impairments. See Note 8 - Fair Value Measurements and below for further discussion of asset impairments.
Net capitalized costs attributable to unproved properties were $7.7 billion and $10.2 billion as of December 31, 2025 and 2024, respectively. The unproved amounts are not subject to DD&A until they are classified as proved properties. Individually insignificant unproved properties are combined and amortized on a group basis based on factors such as geographic location, lease terms, success rates and other factors to provide for full amortization upon lease expiration or abandonment.
Significant unproved properties are assessed individually for impairment and, when events or circumstances indicate that the carrying value of property may not be recovered, a valuation allowance is provided if an impairment is indicated. The Company periodically reviews significant unproved properties for impairments. When assessing for impairments, several factors are considered, including, but not limited to, availability of funds for future exploration and development activities, current exploration and development plans, favorable or unfavorable exploration activity on the property or the adjacent property, geologists’ evaluation of the property, the current and projected political and regulatory climate, contractual conditions and the remaining lease term for the properties. If an impairment is indicated, the Company will first determine whether a comparable transaction for similar properties or implied acreage valuation derived from market participants is available and will adjust the carrying amount of the unproved property to its fair value using the market approach. In situations where the market approach is not observable and unproved reserves are available, undiscounted future net cash flows used in the impairment analysis are determined based on management’s risk-adjusted estimates of unproved reserves, future commodity prices and future costs to produce the reserves. If undiscounted future net cash flows are less than the carrying value of the unproved property, the future net cash flows are discounted and compared to the carrying value for determining the amount of the impairment loss to record. The Company utilizes the same methodology discussed above for cash flows associated with proved properties.
MIDSTREAM AND MARKETING
The Company’s midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, which range from 3 years to 40 years, using the straight-line method.
The Company performs impairment tests on its midstream and marketing assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.
IMPAIRMENTS AND OTHER CHARGES
In 2024, the Company recorded a pre-tax impairment of $334 million related to certain wells in the Gulf of America whose future net cash inflows did not indicate that the asset value is recoverable.
In 2023, the Company recorded a pre-tax impairment of $180 million related to undeveloped acreage in the northern non-core area of the Powder River Basin where the Company has decided not to pursue future exploration and appraisal activities. In 2023, impairment expense also included $29 million related to an equity method investment in Black Butte Coal Company.
INTANGIBLES AND GOODWILL
As of December 31, 2025, the Company had $954 million of other intangible assets primarily related to OLCV included in the midstream and marketing segment other long-term assets. These assets are amortized between 9 and 25 years on a straight-line basis. The Company performs impairment tests on its finite-lived intangible assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.
As of December 31, 2025, the Company had $668 million of goodwill related to its ownership in Carbon Engineering included in the midstream and marketing segment other long-term assets. Goodwill is subject to annual impairment testing
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every April. The Company’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is likely impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill, the Company will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, future acquisitions or future divestitures.
FAIR VALUE MEASUREMENTS
The Company has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 – using quoted prices in active markets for the assets or liabilities; Level 2 – using observable inputs other than quoted prices for the assets or liabilities; and Level 3 – using unobservable inputs. Transfers between levels, if any, are reported at the end of each reporting period.
FAIR VALUES - RECURRING
The Company primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. The Company utilizes the mid-point between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, the Company makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For assets and liabilities carried at fair value, the Company measures fair value using the following methods:
■The Company values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1.
■OTC bilateral financial commodity contracts, foreign exchange contracts, interest rate swaps, warrants, options and physical commodity forward purchase and sale contracts are generally classified as Level 2 and are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace.
■The Company values commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are generally unobservable in the marketplace or are observable but have been adjusted based upon various assumptions and the fair value is designated as Level 3 within the valuation hierarchy.
■The Company values debt using market-observable information for debt instruments that are traded on secondary markets. For debt instruments that are not traded, the fair value is determined by interpolating the value based on debt with similar terms and credit risk.
NON-FINANCIAL ASSETS
The Company uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When the Company is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows. The expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions.
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ACCRUED LIABILITIES - CURRENT
Accrued liabilities-current consisted of the following line items as of December 31, 2025 and 2024:
| millions | 2025 | 2024 | ||||||
| Payroll and related expenses | $ | $ | ||||||
| Taxes other than on income | ||||||||
| Accrued interest payable | ||||||||
| Dividends payable | ||||||||
| Asset retirement obligations | ||||||||
| Income tax payable | ||||||||
| Carbon Engineering acquisition payable | ||||||||
| Other | ||||||||
| Accrued liabilities - current | $ | $ | ||||||
ACCRUED LIABILITIES - NON-CURRENT
Accrued liabilities non-current consisted of the following line items as of December 31, 2025 and 2024:
| millions | 2025 | 2024 | ||||||
Long term tax liabilities (a) | ||||||||
| Pension and postretirement obligations | ||||||||
| Other | ||||||||
| Accrued liabilities - non-current | $ | $ | ||||||
(a) See Note 12 - Lawsuits, Claims, Commitments and Contingencies for additional information.
(b) See Note 11 - Environmental Liabilities and Expenditures for additional information.
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
The Company incurs environmental liabilities and expenditures with respect to both current operations and remediation of existing conditions from alleged past practices at Third-Party, Currently Operated, and Closed or Non-operated Sites, which categories may include NPL sites. Environmental liabilities for estimated remediation costs from alleged past practices and related charges and expenses are recorded when environmental remediation efforts are probable and the costs can be reasonably estimated. Environmental expenditures related to current operations are expensed or capitalized as appropriate. The Company discloses such remediation liabilities on a consolidated basis. In determining the environmental remediation liability and the range of reasonably possible additional losses, the Company refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. These environmental remediation liabilities are based on management’s estimate of the most likely cost to be incurred using the most cost-effective technology reasonably expected to achieve the remedial objective. The Company periodically reviews these environmental remediation liabilities and adjusts them as new information becomes available. The Company generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable.
Many factors could affect future remediation costs incurred by the Company and result in adjustments to environmental remediation liabilities and the range of reasonably possible additional losses. The most significant are: (i) cost estimates for remedial activities may vary from the initial estimate; (ii) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (iii) a regulatory agency may ultimately reject or modify remedial plans proposed by the Company; (iv) improved or alternative remediation technologies may change remediation costs; (v) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (vi) changes in allocation or cost-sharing arrangements may occur.
Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (i) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among the Company and other alleged potentially responsible parties; (ii) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (iii) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, the Company evaluates the financial viability of other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences of their failure to participate when estimating its
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ultimate share of liability. The Company records its environmental remediation liabilities at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.
In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at CERCLA NPL sites, the Company’s environmental remediation liabilities include management’s estimates of the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, the Company reviews and adjusts its environmental remediation liabilities accordingly.
ASSET RETIREMENT OBLIGATIONS
The Company recognizes the fair value of AROs in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, the Company capitalizes the cost by increasing the related PP&E balances. If the estimated future cost of the AROs changes, the Company records an adjustment to both the AROs and PP&E. Over time, the liability is increased, expense is recognized for accretion and the capitalized cost is depreciated over the useful life of the asset. Adjustments to AROs for oil and gas properties where the field has reached cessation of production are recorded as gain (loss) on ARO settlements and are included in gain (loss) on the sale of assets and other, net in the Consolidated Statements of Operations.
The Company’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties.
At a certain number of its facilities, the Company has identified conditional AROs that are related mainly to plant decommissioning. The Company does not know or cannot estimate when it may settle these obligations. Therefore, the Company cannot reasonably estimate the fair value of these liabilities. The Company will recognize these conditional AROs in the periods in which sufficient information becomes available to reasonably estimate their fair values.
The following table summarizes the activity of AROs for the years ended December 31:
| millions | 2025 | 2024 | ||||||
| Beginning balance | $ | $ | ||||||
| Liabilities incurred – capitalized to PP&E | ||||||||
| Liabilities settled and paid | ( | ( | ||||||
| Accretion expense | ||||||||
| Acquisitions, divestitures and other, net | ( | |||||||
| Revisions to previous estimates | ||||||||
| Ending balance | $ | $ | ||||||
DERIVATIVE INSTRUMENTS
STOCK-BASED INCENTIVE PLANS
The Company has established the Plans that are more fully described in Note 14 - Stock-Based Incentive Plans. A summary of the Company’s accounting policy for awards issued under the Plans is as follows.
For cash- and stock-settled RSUs and CROCEI awards, compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout on the grant date. The fair value of stock options is estimated using a Black-Scholes model. For TSRI awards, compensation value is initially measured on the grant date using the fair value derived from a Monte Carlo valuation model. Compensation expense for all awards is recognized on a straight-line basis over the requisite service periods, which is generally over the awards’ respective vesting or performance periods. The stock-settled awards are expensed using the initially measured compensation value. Liabilities resulting from cash settled awards and accrued dividends are remeasured at each reporting period. Dividends accrued on unvested awards are adjusted quarterly for any changes in the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable.
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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS
The Company recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans, which are more fully described in Note 10 - Retirement and Postretirement Benefit Plans, in its financial statements using a December 31 measurement date.
The Company’s defined benefit pension and postretirement benefit plan obligations are actuarially determined based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. The Company estimates the rate of return on assets with regard to current market factors but within the context of historical returns. The Company funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.
Pension and any postretirement plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common and collective trusts are valued at the fund units’ NAV provided by the issuer, which represents the quoted price in a non-active market. Short-term investment funds are valued at the fund units’ NAV provided by the issuer.
SUPPLEMENTAL CASH FLOW INFORMATION
The following table represents production, property and other tax payments and interest paid related to continuing operations during the year ended December 31, 2025, 2024 and 2023, respectively:
| millions | 2025 | 2024 | 2023 | ||||||||
| Production, property and other tax payments | $ | $ | $ | ||||||||
Interest paid (a) | $ | $ | $ | ||||||||
(a) Net of capitalized interest of $179 million, $156 million and $82 million, for the years 2025, 2024 and 2023, respectively.
See Note 9 - Income Taxes for information on income taxes paid. During the year ended December 31, 2024, the Company issued 29.6 million shares as a portion of the purchase price for the CrownRock Acquisition, see Note 4 -Acquisitions, Divestitures, and Other Transactions for additional details.
CASH EQUIVALENTS AND RESTRICTED CASH EQUIVALENTS
The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents. The cash equivalents and restricted cash equivalents balance as of December 31, 2025 included investments in government money market funds in which the carrying value approximates fair value.
The following table provides a reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents as reported at the end of the period in the Consolidated Statements of Cash Flows for the year ended December 31, 2025 and 2024:
| millions | 2025 | 2024 | ||||||
| Cash and cash equivalents | $ | $ | ||||||
| Cash and cash equivalents included in assets held for sale | ||||||||
| Restricted cash and restricted cash equivalents | ||||||||
| Restricted cash and restricted cash equivalents included in long-term receivables and other assets, net | ||||||||
| Cash, cash equivalents, restricted cash and restricted cash equivalents | $ | $ | ||||||
FOREIGN CURRENCY TRANSACTIONS
The functional currency applicable to all of the Company’s international oil and gas operations is the U.S. dollar since cash flows are denominated principally in U.S. dollars. In the Company’s other operations, the Company’s use of non-United States dollar functional currencies was not material for all years presented. The effect of exchange rates on transactions in foreign currencies is included in periodic income. The Company reports the exchange rate differences arising from translating foreign-currency-denominated balance sheet accounts to the United States dollar as of the reporting date in OCI. Exchange-rate gains and losses for continuing operations were not material for all years presented.
INCOME TAXES
The Company files various U.S. federal, state and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state and foreign income taxes are provided on temporary
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LOSS CONTINGENCIES
The Company is involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. The Company is also involved in proceedings under CERCLA and similar federal, state, local and international environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties, injunctive relief, and government oversight costs. Usually the Company is among many companies in these environmental proceedings and has to date been successful in sharing response costs with other financially sound companies. Further, some lawsuits, claims and legal proceedings involve acquired or disposed assets with respect to which a third party or the Company retains liability or indemnifies the other party for conditions that existed prior to the transaction.
The following table summarizes the activity of the environmental, litigation, tax and other reserves from continuing operations for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Balance - beginning of year | $ | $ | $ | ||||||||
| Charged to costs and expenses | |||||||||||
| Charged to other accounts | |||||||||||
| Payments | ( | ( | ( | ||||||||
Balance - end of year (a) | $ | $ | $ | ||||||||
(a) Of these amounts, $140 million, $109 million and $113 million in 2025, 2024 and 2023, respectively, were classified as current.
RECENT ACCOUNTING PRONOUNCEMENTS
In November 2024, FASB issued new guidance to provide more detailed information about expenses. Issuers are to disclose disaggregated expenses of certain captions in tabular form. The rule becomes effective for annual periods beginning after December 15, 2026. The Company is currently evaluating the impact of adopting this guidance on the consolidated financial statements.
| NOTE 2 - REVENUE | ||
Revenue from customers is recognized when obligations under the terms of a contract are satisfied; this generally occurs with the delivery of oil, NGL, gas or services such as transportation. Revenue from customers is measured as the amount of consideration the Company expects to receive in exchange for the delivery of goods or services. Contracts may last from one month to one year or more and may have renewal terms that extend indefinitely at the option of either party. Price is typically based on market indexes. Volumes fluctuate due to production and, in certain cases, customer demand and transportation availability.
The Company does not incur significant costs to obtain contracts. Incidental items that are immaterial in the context of the contract are recognized as expenses. The Company does not typically receive payment in advance of satisfying its obligations under the terms of its sales contracts with customers; therefore, liabilities related to such payment are immaterial to the Company. The Company does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations.
OXY 2025 FORM 10-K | 73 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
OIL AND GAS SEGMENT
Revenue from oil and gas production is recognized when production is delivered and control passes to the customer. Revenues from the production of oil and gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net revenue interest.
MIDSTREAM AND MARKETING SEGMENT
Revenue from pipeline and gas processing is recognized upon the completion of the transportation or processing service. Revenue from power sales is recognized upon delivery. Net marketing revenue is recognized upon completion of contract terms that are a prerequisite to payment and upon title transfer for physical deliveries. Unless the normal purchases and sales exception has been elected, net marketing revenue is classified as a derivative, reported on a net basis and recorded at fair value. Changes in fair value are reflected in net sales and excluded from revenue from customers in the table below.
DISAGGREGATION OF REVENUE FROM CONTRACTS WITH CUSTOMERS
The following table reconciles revenue from customers to total net sales for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Revenue from customers | $ | $ | $ | ||||||||
| All other revenues | ( | ( | |||||||||
| Net sales | $ | $ | $ | ||||||||
74 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The table below presents the Company’s revenue from customers by segment, product and geographical area. The oil and gas segment typically sells its oil, NGL and natural gas at the lease or concession area. Excluding net marketing revenue, midstream and marketing segment revenues are shown by the location of sale.
| millions | United States | International | Eliminations | Total | ||||||||||
| Year ended December 31, 2025 | ||||||||||||||
| Oil and gas | ||||||||||||||
| Oil | $ | $ | $ | $ | ||||||||||
| NGL | ||||||||||||||
| Gas | ||||||||||||||
| Other | ||||||||||||||
| Segment total | $ | $ | $ | $ | ||||||||||
| Midstream and marketing | $ | $ | $ | $ | ||||||||||
| Eliminations | $ | $ | $ | ( | $ | ( | ||||||||
| Consolidated | $ | $ | $ | ( | $ | |||||||||
| Year ended December 31, 2024 | ||||||||||||||
| Oil and gas | ||||||||||||||
| Oil | $ | $ | $ | $ | ||||||||||
| NGL | ||||||||||||||
| Gas | ||||||||||||||
| Other | ||||||||||||||
| Segment total | $ | $ | $ | $ | ||||||||||
| Midstream and marketing | $ | $ | $ | $ | ||||||||||
| Eliminations | $ | $ | $ | ( | $ | ( | ||||||||
| Consolidated | $ | $ | $ | ( | $ | |||||||||
| Year ended December 31, 2023 | ||||||||||||||
| Oil and gas | ||||||||||||||
| Oil | $ | $ | $ | $ | ||||||||||
| NGL | ||||||||||||||
| Gas | ||||||||||||||
| Other | ||||||||||||||
| Segment total | $ | $ | $ | $ | ||||||||||
| Midstream and marketing | $ | $ | $ | $ | ||||||||||
| Eliminations | $ | $ | $ | ( | $ | ( | ||||||||
| Consolidated | $ | $ | $ | ( | $ | |||||||||
OXY 2025 FORM 10-K | 75 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 3 - INVESTMENTS AND RELATED-PARTY TRANSACTIONS | ||
INVESTMENTS IN UNCONSOLIDATED ENTITIES
The following table represents significant investments in unconsolidated entities as of December 31, 2025:
| millions | % Economic Interest | Carrying amount | ||||||||||||
| WES | % | $ | ||||||||||||
| NET Power | % | |||||||||||||
DEL(a) | % | |||||||||||||
| Other | various | |||||||||||||
| Total Investments in unconsolidated entities | $ | |||||||||||||
The following table represents cumulative undistributed earnings and investments in excess of equity as of December 31, 2025 and 2024:
| millions | 2025 | 2024 | ||||||
| Cumulative undistributed earnings | $ | $ | ||||||
| Investments in excess of equity | ||||||||
| Investment in excess of equity allocated to PP&E and equity investments | $ | $ | ||||||
| Investment in excess of equity allocated to intangibles and other assets | $ | $ | ||||||
| Total investments in excess of equity | $ | $ | ||||||
Dividends received from equity investments were $705 million, $682 million and $571 million to the Company in 2025, 2024 and 2023, respectively.
In 2025, the Company recorded its share of NET Power’s impairment losses of $401 million, bringing book value of its investment to zero. In the fourth quarter of 2025, WES acquired Aris Water Solutions, Inc. with a mix of stock and cash, and the Company recognized a gain of $301 million from its pro-rata ownership reduction in WES. In 2024 and 2023, the Company sold 19.5 million and 5.1 million of its limited partner units in WES, respectively, resulting in gains on sale of $489 million and $51 million, respectively.
The following table presents the summarized financial information of its equity-method investments combined for the years ended and as of December 31, 2025, 2024 and 2023:
| millions | 2025 | 2024 | 2023 | ||||||||
| Summarized Results of Operations | |||||||||||
| Revenues and other income | $ | $ | $ | ||||||||
| Costs and expenses | |||||||||||
| Net income | $ | ( | $ | $ | |||||||
| Summarized Balance Sheet | |||||||||||
| Current assets | $ | $ | $ | ||||||||
| Non-current assets | $ | $ | $ | ||||||||
| Current liabilities | $ | $ | $ | ||||||||
| Long-term debt | $ | $ | $ | ||||||||
| Other non-current liabilities | $ | $ | $ | ||||||||
Equity | $ | $ | $ | ||||||||
76 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
RELATED-PARTY TRANSACTIONS
The Company sells oil, NGL, natural gas and power to and purchases oil and NGL from its equity method investees and other related parties. The Company is charged service fees primarily related to gathering, processing and treatment of oil, NGL and natural gas by certain of its equity investees and other related parties. Berkshire Hathaway is a related party of the Company due to its ownership of Occidental’s common stock. The Company has, from time to time, contracted with Berkshire Hathaway for the provision of electricity and insurance. On January 2, 2026, the Company completed the sale of OxyChem to Berkshire Hathaway. As a result, OxyChem’s results of operations, cash flows and the related retained liabilities and indemnification obligations are reported as discontinued operations in the Company’s Consolidated Statements of Operations and Cash Flows for all periods presented, with its assets and liabilities reclassified as held for sale in the Company’s Consolidated Balance Sheets. For more information, refer to Note 4 - Acquisition, Divestitures and Other Transactions. The Company entered into the following related-party transactions and had the following amounts due from or to its related parties for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
Sales (a) | $ | $ | $ | ||||||||
Purchases (b) | $ | $ | $ | ||||||||
Services (c) | $ | $ | $ | ||||||||
| Advances and amounts due from related parties | $ | $ | $ | ||||||||
| Amounts due to related parties | $ | $ | $ | ||||||||
(a)In 2025, 2024 and 2023, sales of Company-produced oil and NGL to WES accounted for 53 %, 58 % and 63 % of related party sales, respectively.
(b)In 2025, 2024 and 2023, purchases of gas and NGL marketed on behalf of WES accounted for all of the related party purchases.
(c)In 2025, 2024 and 2023, services primarily related to fees charged by WES to gather, process and treat the Company produced oil, NGL and natural gas.
| NOTE 4 - ACQUISITIONS, DIVESTITURES AND OTHER TRANSACTIONS | ||
ACQUISITIONS, DIVESTITURES AND OTHER TRANSACTIONS
2025
During 2025, the Company sold non-core assets for $2.3 billion which included working interests in the Permian Basin for proceeds of approximately $800 million, non-operated proved and unproved royalty and mineral interests in the DJ Basin for proceeds of approximately $840 million and certain gas gathering assets in the Permian Basin for approximately $580 million. The differences in the assets’ net book values and adjusted purchase prices were treated as a normal retirements, and as a result no gains or losses were recognized.
2024
In December 2023, the Company entered into an agreement to purchase CrownRock for total consideration of $12.4 billion, consisting of $9.4 billion of cash consideration (inclusive of certain working capital and other customary purchase price adjustments), 29.6 million shares of Occidental common stock, and the assumption of $1.2 billion of existing debt of CrownRock. The acquisition closed on August 1, 2024, adding to the Company’s oil and gas portfolio in the Permian Basin.
OXY 2025 FORM 10-K | 77 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The CrownRock Acquisition qualified as a business combination and was accounted for using the acquisition method of accounting. The following table summarizes the cash and common stock components of the purchase price:
| in millions of dollars and shares (except per-share price) | Total | ||||
Cash portion of purchase price | $ | ||||
| Closing Adjustments | |||||
| Net Working Capital and Other Purchase Price Adjustments | |||||
| Pre-closing dividends declared by the Company | |||||
| Total Cash Purchase Price | $ | ||||
| Total shares of Occidental common stock issued | |||||
| Occidental common stock share price | $ | ||||
Stock portion of purchase price | $ | ||||
Total purchase price | $ | ||||
The following table sets forth the allocation of the acquisition consideration. The Company finalized the purchase price allocation during the 12-month period following the acquisition date. Measurement period adjustments recorded were immaterial and did not result in a material impact to the statements of operations.
| in millions | August 1, 2024 | ||||
| Fair value of assets acquired: | |||||
| Cash and cash equivalents | $ | ||||
| Trade receivables, net | |||||
| Other current assets | |||||
| Property, plant and equipment, oil and gas | |||||
| Amount attributable to assets acquired | $ | ||||
| Fair value of liabilities acquired: | |||||
| Current maturities of long-term debt | $ | ||||
| Accounts payable | |||||
| Accrued liabilities | |||||
| Long-term debt | |||||
| Asset retirement obligations | |||||
| Amount attributable to liabilities acquired | $ | ||||
| Fair value of net assets acquired: | $ | ||||
The aggregate purchase price noted above was allocated to the major categories of assets and liabilities acquired based upon their preliminary estimated fair values at the date of the acquisition. The valuation of certain assets, primarily property, was based on preliminary appraisals.
Unproved oil and gas properties were valued using a market approach based on comparable transactions for similar properties.
Proved oil and gas properties were valued using an income approach, which are considered Level 3 fair value estimates and include significant assumptions of future production and timing of production, commodity price assumptions, and operating and capital cost estimates, discounted using an 8.5 % weighted average cost of capital. Taxes were based on current statutory rates. Future production and timing of production were based on internal reserves estimates and internal economic models for specific proved oil and gas assets. Price assumptions were based on a combination of market information and published industry resources adjusted for historical differentials. Price assumptions ranged from approximately $75 per barrel of oil increasing to approximately $97 per barrel of oil for the 15-year period, with an unweighted arithmetic average price of $84.79 for WTI indexed assets for the same period. Natural gas prices ranged from approximately $2.80 per Mcf to $5.10 per Mcf for the 15-year period, with an unweighted arithmetic average price of $4.34 for NYMEX based assets for the same period. Both oil and natural gas commodity prices were held flat after 2038 and were adjusted for location and quality differentials. Operating and capital cost estimates were based on current observable costs and were further escalated 2 % in every period. The weighted average cost of capital was calculated based on industry peers and best approximates the cost of capital an external market participant would expect to obtain.
78 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The following summarizes the unaudited pro forma condensed financial information of the Company as if the CrownRock Acquisition had occurred on January 1, 2023 for the years ended December 31:
| millions, except per-share amounts | 2024 | 2023 | ||||||||||||
| Revenues | $ | $ | ||||||||||||
| Net income attributable to common stockholders | $ | $ | ||||||||||||
| Net income attributable to common stockholders per share—basic | $ | $ | ||||||||||||
| Net income attributable to common stockholders per share—diluted | $ | $ | ||||||||||||
During the third quarter of 2024, the Company sold non-core assets in the Powder River Basin with near- to intermediate-term lease expirations and certain Delaware Basin assets in Texas and New Mexico for combined net proceeds of $769 million, subject to customary purchase price adjustments. The Company recognized a pre-tax loss of $479 million on the asset sales. In addition, the Company sold 19.5 million of its limited partner units in WES for proceeds of $697 million resulting in a pre-tax gain of $489 million; see Note 3 - Investments and Related-Party Transactions.
2023
In August 2023, the Company entered into an agreement with Carbon Engineering Ltd., its equity method investee, to purchase the remaining 68 % interest not already owned by the Company or its affiliates for total cash consideration of approximately $1.1 billion, resulting in Carbon Engineering becoming a wholly owned subsidiary of the Company. The transaction qualified as a business combination and was accounted for using the acquisition method of accounting. Because the Company acquired control of Carbon Engineering in the 2023 purchase, the Company remeasured its previously held 32 % equity interest at its acquisition-date fair value and recognized the resulting gain of $283 million in accordance with GAAP. The purchase price was payable in three approximately equal annual payments, with the first payment made at closing. This transaction closed on November 3, 2023, and the Company made the first payment of $349 million. The second payment of $318 million was made in the fourth quarter of 2024, and the last payment was made in the fourth quarter of 2025.
Throughout 2023, the Company entered into non-monetary exchange agreements, primarily in the Permian Basin. These exchanges were recorded as acquisitions and divestitures at a total combined fair value of $120 million. The difference in the assets’ net book value was treated as a recovery of cost and normal retirement, which resulted in no gain or loss being recognized.
In September 2023, the Company sold 5.1 million limited partner units of WES for proceeds of approximately $128 million, resulting in a gain of $51 million; see Note 3 - Investments and Related-Party Transactions.
In September 2023, the Company sold certain non-core proved and unproved properties in the Permian Basin for $202 million and recorded a gain on sale of assets of $142 million.
DISCONTINUED OPERATIONS
OxyChem
In October 2025, the Company announced a purchase and sale agreement with Berkshire Hathaway to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion. The sale was completed on January 2, 2026, resulting in an estimated gain of $3.2 billion, net of taxes and subject to post-closing adjustments. The OxyChem Transaction is subject to customary adjustments for cash, indebtedness, and changes in working capital relative to a predetermined target. For information related to the presentation of financials for discontinued operations, see Note 1 - Summary of Significant Accounting Policies.
The OxyChem Transaction marks a strategic change in the Company’s operations. Refer to Note 5 Long-Term Debt for the Company’s use of the after-tax sale proceeds.
Andes
As previously disclosed, on April 5, 2024, Andes and the Company entities named in the pending actions related to the Andes Arbitration executed a confidential final settlement in which the parties agreed to dismiss all pending legal actions. The settlement resulted in a gain of $182 million, net of taxes, in discontinued operations.
OXY 2025 FORM 10-K | 79 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The following table presents the amounts reported in discontinued operations, net of income taxes, for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Revenues and other income | |||||||||||
| Net Sales | $ | $ | $ | ||||||||
| Interest, dividends and other income | ( | ( | |||||||||
| Gains on sales of assets and others, net | |||||||||||
| Total revenues and other income | |||||||||||
| Costs and other deductions | |||||||||||
| Chemical cost of sales | |||||||||||
| Selling, general and administrative expense | |||||||||||
| Other operating and non-operating expense | ( | ||||||||||
| Depreciation, depletion and amortization | |||||||||||
| Asset impairments and other charges | |||||||||||
| Acquisition-related costs | |||||||||||
| Other expense, net | ( | ||||||||||
| Total costs and other deductions | |||||||||||
| Income before income taxes and other items | |||||||||||
| Income from equity investments and other | |||||||||||
| Income before income taxes | |||||||||||
| Income tax expense | ( | ( | ( | ||||||||
| Income from discontinued operations, net of tax | $ | $ | $ | ||||||||
The following table presents a reconciliation of major classes of assets and liabilities classified as held for sale as of December 31:
| millions | 2025 | 2024 | ||||||
| Assets | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Trade receivables, net | ||||||||
| Inventories | ||||||||
| Other current assets | ||||||||
| Total current assets held for sale | ||||||||
| Investments in unconsolidated entities | ||||||||
| Property, plant and equipment, net | ||||||||
| Operating lease assets | ||||||||
| Other long-term assets | ||||||||
| Total non-current assets held for sale | ||||||||
| Total assets held for sale | $ | $ | ||||||
| Liabilities | ||||||||
| Current maturities of long-term debt | $ | $ | ||||||
| Accounts payable | ||||||||
| Accrued liabilities | ||||||||
| Total current liabilities held for sale | ||||||||
| Long-term debt, net | ( | |||||||
| Asset retirement obligations | ||||||||
| Other deferred credits and liabilities | ||||||||
| Total non-current liabilities held for sale | ||||||||
| Total liabilities held for sale | $ | $ | ||||||
80 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The following table summarizes the activity of the environmental and litigation reserves related to the retained liabilities and indemnification obligations associated with the chemical business for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Balance - beginning of year | $ | $ | $ | ||||||||
| Charged to costs and expenses | |||||||||||
| Charged to other accounts | |||||||||||
| Payments | ( | ( | ( | ||||||||
Balance - end of year (a) | $ | $ | $ | ||||||||
(a) Of these amounts, $116 million, $117 million and $102 million in 2025, 2024 and 2023, respectively, were classified as current.
OXY 2025 FORM 10-K | 81 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 5 - LONG-TERM DEBT | ||
As of December 31, 2025 and 2024, the Company’s debt consisted of the following:
| millions | 2025 | 2024 | ||||||
-year term loan due 2026 ( | ||||||||
Variable rate bonds due 2030 ( | ||||||||
| Zero Coupon senior notes due 2036 | ||||||||
| (continued on next page) | ||||||||
82 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| millions (continued) | 2025 | 2024 | ||||||
| Total borrowings at face value | $ | $ | ||||||
| Adjustments to book value: | ||||||||
| Unamortized premium, net | ||||||||
| Debt issuance costs | ( | ( | ||||||
| Net book value of debt | $ | $ | ||||||
| Total debt and finance leases | $ | $ | ||||||
Less current maturities of finance leases | ( | ( | ||||||
| Less current maturities of long-term debt | ( | ( | ||||||
| Long-term debt, net | $ | $ | ||||||
DEBT ACTIVITY AND DEBT MATURITIES
The following table summarizes the Company’s debt activity in 2025:
| millions | Borrowings at face value | ||||
| Total borrowings at face value as of December 31, 2024 | $ | ||||
| Repayments | |||||
| ( | |||||
| ( | |||||
| ( | |||||
| ( | |||||
| Zero Coupon senior notes due 2036 | ( | ||||
-year term loan due 2026 | ( | ||||
| Other | ( | ||||
| Total repayments | $ | ( | |||
| Total borrowings at face value as of December 31, 2025 | $ | ||||
Subsequent to December 31, 2025, but before the date of this filing, the Company used proceeds from the OxyChem Transaction to pay or satisfy and discharge the remaining balance of the term loan of $1.3 billion, additional current maturities of $270 million, and long-term maturities of $3.8 billion. As of the date of this filing, the principal debt outstanding was approximately $15 billion, of which $24 million is due in 2026, $48 million in 2027, $14 million in 2028, $367 million in 2029 and $14.6 billion due in 2030 and thereafter.
The Company terminated its receivables securitization facility on September 26, 2025.
FAIR VALUE OF DEBT
The Company estimates the fair value of fixed-rate debt based on the quoted market prices for those instruments or on quoted market yields for similarly rated debt instruments, taking into account such instruments’ maturities. The estimated fair values of the Company’s debt as of December 31, 2025 and 2024, the majority of which were classified as Level 1, were approximately $20.8 billion and $24.0 billion, respectively. The Company’s exposure to changes in interest rates relates primarily to its variable-rate, long-term debt obligations. As of December 31, 2025 and 2024, variable-rate debt constituted approximately 6.5 % and 11 %, respectively, of the Company’s total debt.
OXY 2025 FORM 10-K | 83 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
DEBT RATINGS
As of December 31, 2025, the Company’s long-term debt was rated Baa3 by Moody’s Investors Service, BBB- by Fitch Ratings and BB+ by Standard and Poor’s. Any downgrade in credit ratings could impact the Company’s ability to access capital markets and increase its cost of capital. In addition, Occidental or its subsidiaries may be requested, elect to provide or in some cases be required to provide collateral in the form of cash, letters of credit, surety bonds or other acceptable support as financial assurance of their performance and payment obligations under certain contractual arrangements such as pipeline transportation contracts, oil and gas purchase contracts and certain derivative instruments; certain permits, including with respect to carbon capture, utilization and storage activities; and environmental remediation matters.
As of the date of this filing, the Company had provided required financial assurances through a combination of cash, letters of credit and surety bonds and had not issued any letters of credit under the RCF or other committed facilities.
REVOLVING CREDIT FACILITY
In February 2024, the Company entered into a Third Amended and Restated Credit Agreement for the RCF extending its maturity date to June 30, 2028. In May 2024, the Company amended the RCF to add an additional $150 million commitment, increasing the borrowing capacity to $4.15 billion. No amounts were drawn under the facility as of December 31, 2025.
Borrowings under the RCF bear interest at SOFR benchmark rates, plus a margin based on the Company’s senior debt ratings. The facility has similar terms to other debt agreements and does not contain material adverse change clauses or debt ratings triggers that could restrict the Company’s ability to borrow, or that would permit lenders to terminate their commitments or accelerate debt repayment. The facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. As of the date of this filing, the Company had no drawn amounts under the RCF. In 2025, the Company paid average annual facility fees of 0.20 % on the total commitment amount.
84 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 6 - LEASE COMMITMENTS | ||
Lease assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Lease assets include the discounted value of future lease payments, upfront payments and costs incurred to execute the lease and are amortized on a straight-line basis over the lease term. The Company assesses the likelihood of exercising renewal, termination and purchase options to determine the lease term. The Company uses its incremental borrowing rate at commencement date to determine the present value of lease payments. The Company separates lease and non-lease components for drilling rigs and vessels. The Company does not separate lease and non-lease components for the remainder of asset classes as the non-lease portions are not significant.
The Company has operating leases from continuing operations for drilling rigs of $273 million, office space of $251 million, vessels of $191 million, compressors of $130 million and $110 million of other assets. Operating leases related to discontinued operations of $211 million are included in liabilities held for sale.
The Company’s finance leases from continuing operations include compressors of $428 million, assets related to DAC operations of $292 million, office space of $208 million and $71 million of other assets. Finance leases related to discontinued operations of $47 million are included in liabilities held for sale. Property, plant and equipment included $972 million of finance lease assets as of December 31, 2025.
The following summarizes maturities of lease liabilities related to continuing operations as of December 31, 2025:
| millions | Operating Leases (a) | Finance Leases (b) | Total | ||||||||
| 2026 | $ | $ | $ | ||||||||
| 2027 | |||||||||||
| 2028 | |||||||||||
| 2029 | |||||||||||
| 2030 | |||||||||||
| Thereafter | |||||||||||
| Total lease payments | |||||||||||
| Less: Discount | ( | ( | ( | ||||||||
| Total lease liabilities | $ | $ | $ | ||||||||
(a)The weighted-average remaining lease term is 3.5 years and the weighted-average discount rate is 4.94 %.
(b)The weighted-average remaining lease term is 5 years and the weighted-average discount rate is 5.07 %.
The following tables present the Company’s total lease cost and other information for operating and finance lease liabilities related to continuing operations for the years ended December 31:
| millions | 2025 | 2024 | ||||||
| Lease Cost | ||||||||
| Finance lease cost: | ||||||||
| Amortization of right-of-use assets | $ | $ | ||||||
| Interest on lease liabilities | ||||||||
| Operating lease cost | ||||||||
| Short-term lease cost | ||||||||
| Total lease cost | $ | $ | ||||||
| millions | 2025 | 2024 | ||||||
Cash payments related to leases | ||||||||
| Operating cash flows from finance leases | $ | $ | ||||||
| Operating cash flows from operating leases | $ | $ | ||||||
| Investing cash flows from operating leases | $ | $ | ||||||
| Financing cash flows from finance leases | $ | $ | ||||||
Changes in Right-of-Use assets | ||||||||
| Right-of-use assets obtained in relation to new finance lease liabilities | $ | $ | ||||||
| Right-of-use assets obtained in relation to new operating lease liabilities | $ | $ | ||||||
OXY 2025 FORM 10-K | 85 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 7 - DERIVATIVES | ||
OBJECTIVE AND STRATEGY
The Company uses a variety of derivative financial instruments and physical contracts to manage its exposure to commodity price fluctuations and transportation commitments and to fix margins on the future sale of stored commodity volumes. Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. The Company may occasionally use a variety of derivative financial instruments to manage its exposure to foreign currency fluctuations and interest rate risks. The Company also enters into derivative financial instruments for trading purposes. The Company may elect normal purchases and normal sales exclusions when physically delivered commodities are purchased from a vendor or sold to a customer. See Note 1 - Summary of Significant Accounting Policies for the Company’s accounting policy on derivatives.
DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
As of December 31, 2025, the Company’s derivatives not designated as hedges consisted of marketing derivatives. These instruments are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings through mark‑to‑market adjustments until the underlying physical commodity is delivered or the financial instrument is settled.
MARKETING DERIVATIVES
The Company’s marketing derivative instruments not designated as hedges are short-duration physical and financial forward contracts. A substantial majority of the Company’s physically settled derivative contracts are index-based and carry no mark-to-market valuation in earnings. As of December 31, 2025, the weighted-average settlement prices of these forward contracts were $59.59 per barrel and $2.53 per Mcf for crude oil and natural gas, respectively. The weighted-average settlement prices were $71.07 per barrel and $3.50 per Mcf for crude oil and natural gas, respectively, as of December 31, 2024. Net gains and losses associated with marketing derivative instruments not designated as hedging instruments are recognized in net sales. Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities.
The following table summarizes net short volumes associated with the outstanding marketing commodity derivatives as of December 31:
| 2025 | 2024 | |||||||
| Oil commodity contracts | ||||||||
| Volume (MMbbl) | ( | ( | ||||||
| Natural gas commodity contracts | ||||||||
| Volume (Bcf) | ( | ( | ||||||
FAIR VALUE OF DERIVATIVES
The Company has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 – using quoted prices in active markets for the assets or liabilities; Level 2 – using observable inputs other than quoted prices for the assets or liabilities; and Level 3 – using unobservable inputs. Transfers between levels, if any, are reported at the end of each reporting period. The following table presents the fair values of the Company’s outstanding derivatives. Fair values are presented at gross amounts below, including when derivatives are subject to netting arrangements, and are presented on a net basis in the Consolidated Balance Sheets.
86 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| millions | Fair Value Measurements Using | Total Fair Value | |||||||||||||||
| Balance Sheet Classification | Level 1 | Level 2 | Level 3 | Netting (a) | |||||||||||||
| December 31, 2025 | |||||||||||||||||
| Marketing Derivatives | |||||||||||||||||
| Other current assets | $ | $ | $ | $ | ( | $ | |||||||||||
| Other long-term assets | |||||||||||||||||
| Accrued liabilities | ( | ( | ( | ||||||||||||||
| Deferred credits and other liabilities - other | |||||||||||||||||
| December 31, 2024 | |||||||||||||||||
| Marketing Derivatives | |||||||||||||||||
| Other current assets | $ | $ | $ | $ | ( | $ | |||||||||||
| Other long-term assets | ( | ||||||||||||||||
| Accrued liabilities | ( | ( | ( | ||||||||||||||
| Deferred credits and other liabilities - other | ( | ( | |||||||||||||||
(a)These amounts do not include collateral. The Company netted $29 million of collateral received from brokers against derivative assets and $23 million of collateral deposited with brokers against derivatives liabilities as of December 31, 2025. As of December 31, 2024, the Company netted $12 million of collateral received from brokers against derivative assets and $9 million collateral deposited with brokers against derivative liabilities.
GAINS AND LOSSES ON DERIVATIVES
The following table presents gains and (losses) related to the Company’s derivative instruments in the Consolidated Statements of Operations for the years ended December 31:
| millions | ||||||||||||||||||||
| Income Statement Classification | 2025 | 2024 | 2023 | |||||||||||||||||
| Marketing Derivatives | ||||||||||||||||||||
Net sales (a) | $ | $ | ( | $ | ( | |||||||||||||||
(a)Included derivative and non-derivative marketing activity.
CREDIT RISK
The majority of the Company’s counterparty credit risk is related to the physical delivery of energy commodities to its customers and any inability to meet their settlement commitments. The Company manages credit risk by selecting counterparties that it believes to be financially strong, by entering into netting arrangements with counterparties and by requiring collateral or other credit risk mitigants, as appropriate. The Company actively evaluates the creditworthiness of its counterparties, assigns appropriate credit limits and monitors credit exposures against those assigned limits. The Company also enters into futures contracts through regulated exchanges with select clearinghouses and brokers, which are subject to minimal credit risk, if any.
| NOTE 8 - FAIR VALUE MEASUREMENTS | ||
FAIR VALUES – NONRECURRING
There were no significant non-recurring fair value measurements in 2025.
In 2024, the Company recorded a pre-tax impairment of $334 million related to certain wells in the Gulf of America whose future net cash inflows did not indicate that the asset value is recoverable.
In 2023, the Company recorded a pre-tax impairment of $180 million related to undeveloped acreage in the northern non-core area of the Powder River Basin where the Company has decided not to pursue future exploration and appraisal activities. Impairment expense also included a $29 million impairment related to an equity method investment in Black Butte Coal Company.
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| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
FINANCIAL INSTRUMENTS FAIR VALUE
The carrying amounts of cash, cash equivalents, restricted cash, restricted cash equivalents and other financial instruments, other than fixed-rate debt, approximate fair value. See Note 5 - Long-Term Debt for the fair value of long-term debt.
| NOTE 9 - INCOME TAXES | ||
RECENT TAX LEGISLATION
The OBBBA was enacted on July 4, 2025 and introduced provisions expected to benefit the Company including accelerated depreciation for newly acquired and constructed assets, favorable adjustments to interest expense limitation, immediate deduction of research and development costs, and increased tax credit values for qualified CO2 projects. In accordance with ASC 740, the financial statement impact of the OBBBA was recognized beginning in the third quarter of 2025. These provisions are expected to significantly reduce the Company’s 2025 cash tax liability.
The OECD Pillar Two initiative proposes to apply a 15% global minimum tax on multinational entities, applied on a jurisdiction-by-jurisdiction basis. Several countries, including European Union member states, Canada and Oman, have enacted or are in the process of enacting legislation aligned with all or portions of Pillar Two. The Company continues to monitor and assess the impact of new OECD Pillar Two administrative guidance and Pillar Two compliant legislation proposed or enacted in the jurisdictions in which the Company operates. Based on developments to date, the Company does not anticipate any significant impact on the Company’s results of operations or cash flows from the enactment of Pillar Two legislation.
The following summarizes domestic and foreign components of income from continuing operations before domestic and foreign income taxes for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Domestic | $ | $ | $ | ||||||||
| Foreign | |||||||||||
Total income from continuing operations before income taxes | $ | $ | $ | ||||||||
The following summarizes components of income tax (expense) benefit on continuing operations for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Current | |||||||||||
| Federal | $ | ( | $ | ( | $ | ( | |||||
| State and local | ( | ( | |||||||||
| Foreign | ( | ( | ( | ||||||||
| Total current tax expense | $ | ( | $ | ( | $ | ( | |||||
| Deferred | |||||||||||
| Federal | ( | ( | |||||||||
| State and local | ( | ||||||||||
| Foreign | ( | ||||||||||
| Total deferred tax (expense) benefit | $ | ( | $ | $ | ( | ||||||
| Total income tax expense | |||||||||||
| Federal | ( | ( | ( | ||||||||
| State and local | ( | ( | ( | ||||||||
| Foreign | ( | ( | ( | ||||||||
| Total income tax expense | $ | ( | $ | ( | $ | ( | |||||
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| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The following summarizes income taxes paid (net of refunds received) on continuing operations for the years ended December 31:
| millions | 2025 | 2024 | 2023 | ||||||||
| Federal | $ | $ | $ | ||||||||
| State | |||||||||||
| Foreign | |||||||||||
| Algeria | |||||||||||
| Oman | |||||||||||
| Qatar | |||||||||||
| All other foreign | |||||||||||
| Total foreign | |||||||||||
| Income taxes paid, net of refunds received | $ | $ | $ | ||||||||
OXY 2025 FORM 10-K | 89 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The following reconciliation of the U.S. federal statutory income tax rate to the Company’s worldwide effective tax rate on income from continuing operations for the years ended December 31 is stated as both a percentage and amount of income from continuing operations before income taxes as required by the adoption of Accounting Standards Update 2023-09 in the fourth quarter of 2025:
| millions except percentages | 2025 | 2024 | 2023 | |||||||||||||||||
| Percentage | Amount | Percentage | Amount | Percentage | Amount | |||||||||||||||
| U.S. federal statutory tax rate | % | $ | % | $ | % | $ | ||||||||||||||
State and local income tax, net of federal income tax effect (a) | ||||||||||||||||||||
| Foreign tax effects | ||||||||||||||||||||
| Algeria | ||||||||||||||||||||
| Tax rate differential | ||||||||||||||||||||
| Change in tax law or rate | ||||||||||||||||||||
| Nontaxable or nondeductible items | ||||||||||||||||||||
| Others | ( | |||||||||||||||||||
| Canada | ||||||||||||||||||||
| Others | ( | ( | ( | ( | ( | |||||||||||||||
| Oman | ||||||||||||||||||||
| Tax rate differential | ||||||||||||||||||||
| Others | ( | |||||||||||||||||||
| Qatar | ||||||||||||||||||||
| Tax rate differential | ||||||||||||||||||||
| Others | ( | ( | ||||||||||||||||||
| United Arab Emirates | ||||||||||||||||||||
| Tax rate differential | ( | ( | ( | ( | ( | ( | ||||||||||||||
| Other foreign jurisdictions | ( | ( | ||||||||||||||||||
| Effect of changes in tax laws or rates enacted in the current period | ||||||||||||||||||||
| Effect of cross-border tax laws | ||||||||||||||||||||
| Tax credits | ( | ( | ( | ( | ( | |||||||||||||||
| Changes in valuation allowance | ||||||||||||||||||||
| Nontaxable or nondeductible items | ||||||||||||||||||||
| Changes in unrecognized tax benefits | ||||||||||||||||||||
| Other adjustments | ( | ( | ( | ( | ( | |||||||||||||||
| Worldwide effective tax rate | % | $ | % | $ | % | $ | ||||||||||||||
(a) Texas and New Mexico contributed to the majority of the tax effect in this category.
The Company’s worldwide effective tax rate in 2025, 2024 and 2023 was higher than the U.S. statutory rate of 21%, primarily driven by the Company’s jurisdictional mix of income from continuing operations, where international income is subject to tax at statutory rates as high as 55%.
The reclassification of OxyChem, which is primarily domestic, to discontinued operations increased this impact. The effective tax rate for discontinued operations was 47 %, 26 % and 23 % for 2025, 2024 and 2023, respectively. The increase in the 2025 discontinued operations effective tax rate relative to 2024 and 2023 is the result of a one-time charge associated with the OxyChem Transaction.
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| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The following summarized the tax effects of temporary differences resulting in deferred income taxes as of December 31:
| millions | 2025 | 2024 | ||||||
| Deferred tax liabilities | ||||||||
| Property, plant and equipment differences | $ | ( | $ | ( | ||||
| Equity investments, partnerships and international subsidiaries | ( | ( | ||||||
| Gross long-term deferred tax liabilities | $ | ( | $ | ( | ||||
| Deferred tax assets | ||||||||
| Environmental reserves | ||||||||
| Postretirement benefit accruals | ||||||||
| Deferred compensation and benefits | ||||||||
| Asset retirement obligations | ||||||||
| Foreign tax credit carryforwards | ||||||||
Business credit carryforwards | ||||||||
| Net operating loss carryforward | ||||||||
| Interest expense carryforward | ||||||||
| All other | ||||||||
| Gross long-term deferred tax assets | ||||||||
| Valuation allowance | ( | ( | ||||||
| Net long-term deferred tax assets | $ | $ | ||||||
| Total deferred income tax liability, net | $ | ( | $ | ( | ||||
| Less: foreign deferred tax asset in long-term receivables and other assets, net | ( | ( | ||||||
Total deferred income tax liability (a) | $ | ( | $ | ( | ||||
(a) The deferred income tax assets and liabilities associated with discontinued operations were not classified as held for sale because they will be realized upon the sale of OxyChem.
Total deferred tax assets, after valuation allowances, were $2.6 billion and $2.4 billion as of December 31, 2025 and 2024, respectively. The Company expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The total deferred tax liabilities were $8.2 billion and $7.7 billion as of December 31, 2025 and 2024, respectively.
As of December 31, 2025, the Company had foreign tax credit carryforwards of $713 million and state tax credit carryforwards of $39 million. The Company had recorded a valuation allowance for $713 million of the foreign tax credit carryforwards and $32 million of the state tax credit carryforwards.
As of December 31, 2025, the Company had tax-effected foreign net operating loss carryforwards of $971 million, state net operating loss carryforwards of $121 million, and federal net operating loss carryforwards of $3 million. The carryforward balances have varying carryforward periods through 2045, excluding certain attributes for which there is an indefinite carryforward period. A valuation allowance was recorded for $890 million of the tax-effected foreign net operating loss carryforwards and $85 million of the tax-effected state net operating loss carryforwards. The Company had an additional valuation allowance of $46 million against other foreign deferred tax assets.
The Company had a tax-effected state interest expense carryforward of $11 million with no valuation allowance as of December 31, 2025.
In prior years, a deferred tax liability had not been recognized for temporary differences related to unremitted earnings of certain consolidated international subsidiaries. As of December 31, 2025, in connection with the OxyChem Transaction, the Company reversed its indefinite reinvestment assertion for unremitted earnings of its foreign operations. The reversal resulted in the recognition of a deferred tax liability of $101 million related to such earnings, presented as part of discontinued operations.
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| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| millions | 2025 | 2024 | 2023 | ||||||||
| Balance as of January 1 | $ | $ | $ | ||||||||
| Increases related to prior-year positions | |||||||||||
| Increases related to current-year positions | |||||||||||
| Settlements | |||||||||||
| Reductions for tax positions of prior years | ( | ( | |||||||||
| Balance as of December 31 | $ | $ | $ | ||||||||
The December 31, 2025 balance of unrecognized tax benefits of $1.9 billion included potential tax benefits of $1.9 billion of which, if recognized, $1.4 billion would affect the effective tax rate on income. Also included were benefits of $45 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain. Unrecognized tax benefits are included in deferred credits and other liabilities - other. The Company records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes. In 2025, the Company recorded interest related to liabilities for unrecognized tax benefits of $188 million, for a cumulative accrued interest related to liabilities for unrecognized tax benefits of $951 million as of December 31, 2025, which is not included in the table above. There were no
The Company recognized $54 million and $30 million in federal and state income tax receivables as of December 31, 2025 and 2024, respectively, which were recorded in other current assets. In addition, the Company recognized $470 million and $247 million in 2025 and 2024, respectively, of long-term income tax receivables, which were recorded in long-term receivables and other assets, net.
The Company is subject to audit by various tax authorities in varying periods. See Note 12 - Lawsuits, Claims, Commitments and Contingencies for a discussion of these matters.
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| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 10 - RETIREMENT AND POSTRETIREMENT BENEFIT PLANS | ||
The Company has various defined contribution and defined benefit plans for its salaried, domestic union and nonunion hourly and certain foreign national employees. In addition, the Company also provides medical and other benefits for certain active, retired and disabled employees and their eligible dependents.
DEFINED CONTRIBUTION PLANS
All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by the Company based on plan-specific criteria, such as base pay, level and employee contributions. Certain salaried employees participate in a supplemental retirement plan that restores benefits lost due to government limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $451 million and $387 million as of December 31, 2025 and 2024, respectively. In 2025, 2024 and 2023 the Company expensed $274 million, $252 million and $221 million, respectively, under the provisions of these defined contribution and supplemental retirement plans.
DEFINED BENEFIT PLANS
Participation in defined benefit plans is limited. Pension costs for the Company’s defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.
POSTRETIREMENT AND OTHER BENEFIT PLANS
The Company provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. The Company generally funds the benefits as they are paid during the year. In 2025, 2024 and 2023, these benefit costs, including the postretirement costs, were $240 million, $205 million and $175 million, respectively.
OBLIGATIONS AND FUNDED STATUS
The following tables show the amounts recognized in the Company’s Consolidated Balance Sheets related to its pension and postretirement benefit plans as of December 31:
| Pension Benefits | Postretirement Benefits | |||||||||||||
| millions | 2025 | 2024 | 2025 | 2024 | ||||||||||
| Amounts recognized in the Consolidated Balance Sheet: | ||||||||||||||
Other long-term assets | $ | $ | $ | $ | ||||||||||
| Accrued liabilities | ( | ( | ( | ( | ||||||||||
| Deferred credits and other liabilities | ( | ( | ( | ( | ||||||||||
| $ | ( | $ | ( | $ | ( | $ | ( | |||||||
| Accumulated other comprehensive loss included the following after-tax balances: | ||||||||||||||
| Net (gain) loss | $ | ( | $ | ( | $ | ( | $ | ( | ||||||
| Prior service credit | ( | ( | ||||||||||||
| $ | ( | $ | ( | $ | ( | $ | ( | |||||||
OXY 2025 FORM 10-K | 93 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The following tables show the funding status, obligations and plan asset fair values of the Company related to its pension and postretirement benefit plans for the years ended December 31:
| Pension Benefits | Postretirement Benefits | |||||||||||||
| millions | 2025 | 2024 | 2025 | 2024 | ||||||||||
| Changes in the benefit obligation: | ||||||||||||||
| Benefit obligation — beginning of year | $ | $ | $ | $ | ||||||||||
| Service cost — benefits earned during the period | ||||||||||||||
| Interest cost on projected benefit obligation | ||||||||||||||
Actuarial (gain) loss | ( | ( | ||||||||||||
| Benefits paid | ( | ( | ( | ( | ||||||||||
| Plan amendments | ( | |||||||||||||
| Other | ( | |||||||||||||
| Benefit obligation — end of year | $ | $ | $ | $ | ||||||||||
| Changes in plan assets: | ||||||||||||||
| Fair value of plan assets — beginning of year | $ | $ | $ | $ | ||||||||||
| Actual return on plan assets | ||||||||||||||
| Employer contributions | ||||||||||||||
| Benefits paid | ( | ( | ( | ( | ||||||||||
| Other | ||||||||||||||
| Fair value of plan assets — end of year | $ | $ | $ | $ | ||||||||||
| Unfunded status: | $ | ( | $ | ( | $ | ( | $ | ( | ||||||
Actuarial losses related to postretirement benefits are primarily due to changes in health care trend rates and expected increases in premiums related to certain provisions in the Inflation Reduction Act. Other actuarial gains and losses are primarily driven by discount rate movement. The decrease in postretirement obligation in 2025 due to plan amendments is related to changes in Medicare advantaged prescription drug plans to introduce an annual deductible and remove certain benefits.
The following table sets forth details of the obligations and assets of the Company’s defined benefit pension plans as of December 31:
| Accumulated Benefit Obligation in Excess of Plan Assets | Plan Assets in Excess of Accumulated Benefit Obligation | |||||||||||||
| millions | 2025 | 2024 | 2025 | 2024 | ||||||||||
| Projected benefit obligation | $ | $ | $ | $ | ||||||||||
| Accumulated benefit obligation | $ | $ | $ | $ | ||||||||||
| Fair value of plan assets | $ | $ | $ | $ | ||||||||||
94 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
COMPONENTS OF NET PERIODIC BENEFIT COSTS
The following table sets forth the components of net periodic benefit costs for the years ended December 31:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||
| millions | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||||||||||||||
| Net periodic benefit costs: | ||||||||||||||||||||
| Service cost — benefits earned during the period | $ | $ | $ | $ | $ | $ | ||||||||||||||
| Interest cost on projected benefit obligation | ||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | |||||||||||||||||
Recognized actuarial loss (gain) | ( | ( | ( | |||||||||||||||||
| Recognized prior service credit | ( | ( | ( | |||||||||||||||||
Gain (loss) due to settlement | ||||||||||||||||||||
| Net periodic benefit costs | $ | $ | $ | $ | $ | $ | ||||||||||||||
The service cost component of net periodic benefit costs is included in selling, general and administrative expense, oil and gas operating expense, midstream costs and exploration expense on the Company’s Consolidated Statements of Operations. All other components of net periodic benefit costs are included in other operating and non-operating expense. As a result of the OxyChem Transaction, pension and postretirement net periodic benefit costs of approximately $9 million, $1 million and $2 million were reclassified to discontinued operations in the income statement for fiscal years 2025, 2024 and 2023 respectively.
ADDITIONAL INFORMATION
The following table sets forth the weighted-average assumptions used to determine the Company’s benefit obligation and net periodic benefit cost for domestic plans for the years ended December 31:
| Pension Benefits | Postretirement Benefits | |||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||
| Benefit Obligation Assumptions: | ||||||||||||||
| Discount rate | % | % | % | % | ||||||||||
| Rate of increase in compensation levels | % | % | ||||||||||||
| Net Periodic Benefit Cost Assumptions: | ||||||||||||||
| Discount rate | % | % | % | % | ||||||||||
| Rate of increase in compensation levels | % | % | ||||||||||||
| Assumed long-term rate of return on assets | % | % | ||||||||||||
For domestic pension plans and postretirement benefit plans, the Company based the discount rate on a AA-AAA Universe yield curve in 2025 and 2024. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end. Assumed rates of compensation increases for active participants in certain plans vary by age group.
The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and health care cost trend rates. Health care cost trend rates for Medicare advantaged prescription drug plans are 44 % in 2025, 45 % in 2026, 10 % in 2027, 6.5 % in 2028, then grading down to 4.5 % in 2036 and beyond. Health care cost trend rates used for non-medicare advantaged prescription drug plans are 6.2 % in 2025, 7.0 % in 2026, then grading down to 4.5 % in 2036 and beyond. Increases in health care trend rates for Medicare advantaged prescription drug plans in 2025 and 2026 are due to increases in premiums related to certain provisions in the Inflation Reduction Act.
The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan assets and liabilities.
FAIR VALUE OF PENSION PLAN ASSETS
Qualified defined benefit plan assets are monitored by the Company’s Pension and Retirement Trust and Investment Committee in its role as a fiduciary. The Investment Committee selects and employs various external professional investment management firms to manage specific investments across the spectrum of asset classes. The Investment Committee employs a liability driven investment approach that uses a diversified blend of investments (equity securities,
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| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
fixed-income securities, and alternative investments) along a glide path to optimize the long-term return of plan assets relative to plan liabilities, at a prudent level of risk. Equity investments are diversified across U.S. and non-U.S. stocks, as well as differing styles and market capitalizations. Investment performance is measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.
The fair values of the Company’s pension plan assets by asset category as of December 31, 2025 and 2024 were as follows:
| millions | Level 1 | Level 2 | Level 3 | Total | ||||||||||
| December 31, 2025 | ||||||||||||||
| Asset Class: | ||||||||||||||
| Government securities | $ | $ | $ | $ | ||||||||||
Corporate bonds (a) | ||||||||||||||
Equity securities (b) | ||||||||||||||
| Other | ||||||||||||||
| Investments measured at fair value | $ | $ | $ | $ | ||||||||||
Investments measured at net asset value (c) | — | — | — | |||||||||||
| Total pension plan assets | $ | $ | $ | $ | ||||||||||
| December 31, 2024 | ||||||||||||||
| Asset Class: | ||||||||||||||
| Government securities | $ | $ | $ | $ | ||||||||||
Corporate bonds (a) | ||||||||||||||
Equity securities (b) | ||||||||||||||
| Other | ||||||||||||||
| Investments measured at fair value | $ | $ | $ | $ | ||||||||||
Investments measured at net asset value (c) | — | — | — | |||||||||||
| Total pension plan assets | $ | $ | $ | $ | ||||||||||
(a)This category represents investment grade bonds of U.S. and non-U.S. issuers from diverse industries.
(b)This category represents direct investments in mutual funds and common and preferred stocks from diverse U.S. and non-U.S. industries.
(c)Certain investments measured at fair value using the NAV per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.
Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows for the years ended December 31:
| millions | Pension Benefits | Postretirement Benefits | ||||||||||||
| 2026 | $ | $ | ||||||||||||
| 2027 | ||||||||||||||
| 2028 | ||||||||||||||
| 2029 | ||||||||||||||
| 2030 | ||||||||||||||
| 2031 - 2035 | ||||||||||||||
The Company expects to contribute approximately $33 million to its defined benefit pension plans during 2026.
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| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 11 - ENVIRONMENTAL LIABILITIES AND EXPENDITURES | ||
The Company is subject to numerous international, federal, state, and local, laws and regulations related to improving or maintaining environmental quality. The laws that require or address environmental remediation, including CERCLA and similar laws, may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. The Company participates in or actively monitors a range of remedial activities and government or private proceedings under these laws with respect to alleged past practices at Third-Party, Currently Operated, and Closed or Non-operated Sites, each of which may include NPL Sites. Remedial activities may include one or more of the following: investigation involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and maintenance of remedial systems. The environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, natural resource damages, punitive damages, civil penalties, injunctive relief and government oversight costs.
As discussed in Note 4 - Acquisitions, Divestitures and Other Transactions, certain Occidental subsidiaries remain responsible for environmental remediation at legacy sites and the indemnification of legacy environmental liabilities and pre-closing liabilities of OxyChem, which are not classified as held for sale. Expenses related to OxyChem and the retained liabilities and indemnification obligations associated with the chemical business are reported as discontinued operations for all periods presented, reflecting the OxyChem Transaction.
ENVIRONMENTAL REMEDIATION
As of December 31, 2025, the Company participated in or monitored remedial activities or proceedings at 152 sites. The following table presents the current and non-current environmental remediation liabilities of the Company separated by those related to ongoing operations and discontinued operations as of December 31, 2025 and 2024.
| millions | as of December 31, 2025 | as of December 31, 2024 | ||||||||||||||||||
| Ongoing Operations | Discontinued Operations | Total | Ongoing Operations | Discontinued Operations | Total | |||||||||||||||
| Current Portion: | ||||||||||||||||||||
| $ | $ | $ | $ | $ | $ | |||||||||||||||
| Non-Current Portion: | ||||||||||||||||||||
| Deferred credit and other liabilities | ||||||||||||||||||||
| Total current and non-current | $ | $ | $ | $ | $ | $ | ||||||||||||||
The estimates of environmental remediation liabilities in the table above vary over time depending on factors such as acquisitions or divestitures, identification of additional sites, remedy selection and implementation and changes in applicable laws or regulations, among other factors. Environmental remediation expenses primarily relate to existing conditions from alleged past practices.
Environmental remediation expenses related to ongoing operations were $18 million in 2025, $20 million in 2024 and $46 million in 2023. For discontinued operations, remediation expenses were $64 million56 million in 2024 and $33 million in 2023.
Based on current estimates, the Company expects to expend funds corresponding to approximately 30 % of the year-end consolidated remediation balance over the next to four years with the remainder over the subsequent 10 or more years.
Environmental remediation sites for ongoing operations and discontinued operations are grouped into NPL Sites and the following three categories of non-NPL Sites — Third-Party Sites, Currently Operated Sites and Closed or Non-operated Sites.
| 2025 | 2024 | |||||||||||||
| millions, except number of sites | Number of Sites | Remediation Balance | Number of Sites | Remediation Balance | ||||||||||
| NPL Sites | $ | $ | ||||||||||||
| Third-Party Sites | ||||||||||||||
| Currently Operated Sites | ||||||||||||||
| Closed or Non-operated Sites | ||||||||||||||
| Total | $ | $ | ||||||||||||
OXY 2025 FORM 10-K | 97 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
As of December 31, 2025, environmental remediation liabilities exceeded $10 million each at 14 of the 152 sites described above, and 88 of the sites had liabilities less than $1 million each. Of the 152 sites above, 69 relate to ongoing operations with a combined remediation balance of approximately $196 million.
The DASS in Newark, New Jersey accounted for the majority of the liabilities associated with the category of NPL Sites.
Of the 69 Third-Party Sites, eight locations — a former copper mining and smelting operation in Tennessee, a chrome site in New Jersey, a former oil field and a landfill in California, active chemical plants in Kansas and Louisiana, a landfill in New York and an active refinery in Louisiana where the Company reimburses the current owner for certain remediation activities — accounted for approximately two thirds of the liabilities associated with this category.
Oil and gas operations in Colorado, which are collectively managed as one Currently Operated Site, accounted for approximately two thirds of the liabilities associated with this category.
The Company believes its range of reasonably possible additional losses beyond those amounts currently recorded for environmental remediation for the 152 environmental sites in the table above could be up to $1.9 billion.
DIAMOND ALKALI SUPERFUND SITE
The EPA has organized the DASS into four OUs for evaluating, selecting and implementing remediation under CERCLA. The Company’s current activities in each OU are summarized below.
OU1 – The Former Diamond Alkali Plant at 80-120 Lister Avenue in Newark: Maxus and its affiliates implemented an interim remedy of OU1 pursuant to a 1990 Consent Decree, for which maintenance and monitoring are currently being performed. In January 2025, the EPA issued a ROD for the final remedy of OU1 that provides for optimized containment for which it estimated a cost of $16 million.
OU2 – The Lower 8.3 Miles of the Lower Passaic River: In March 2016, the EPA issued a ROD outlining the remedial actions required for OU2. During the third quarter of 2016, and following Maxus’s bankruptcy filing, the EPA issued an AOC for the design of the remedy selected in the ROD. In May 2024, the EPA approved the remedial design for OU2. In June 2024, the EPA confirmed that the work required by the AOC had been fully completed in accordance with its terms. The EPA has estimated the cost to remediate OU2 to be approximately $1.4 billion.
OU3 – Newark Bay Study Area, including Newark Bay and portions of the Hackensack River, Arthur Kill, and Kill van Kull: Maxus and its affiliates initiated a remedial investigation and feasibility study of OU3 pursuant to a 2004 AOC which was amended in 2010. The Company is currently performing feasibility study activities in OU3.
OU4 – The 17 -mile Lower Passaic River Study Area, comprising OU2 and the Upper 9 Miles of the Lower Passaic River: In September 2021, the EPA issued a ROD selecting an interim remedy for the portion of OU4 that excludes OU2 and is located upstream from the Lister Avenue Plant site. In March 2023, the EPA issued a Unilateral Administrative Order directing the design of the EPA’s selected interim remedy for OU4. The EPA has estimated the cost to remediate OU4 to be approximately $440 million.
Natural Resource Trustees – In addition to the activities of the EPA and other parties involved in the OUs described above, federal and state natural resource trustees are assessing natural resources in the Lower Passaic River and Greater Newark Bay to evaluate potential claims for natural resource damages.
Legal matters related to the DASS (Alden Leeds)
In December 2022, the EPA and the DOJ filed a proposed Consent Decree in the Alden Leeds litigation, seeking court approval to settle with 85 parties for a total of $150 million for cleanup costs associated with OU2 and OU4. In January 2024, the DOJ filed a proposed Amended Consent Decree that excluded three companies from the original settlement, among other changes, and subsequently filed a motion to approve the Amended Consent Decree. In December 2024, the U.S. District Court for the District of New Jersey (District Court) approved the Amended Consent Decree. In its order approving the Amended Consent Decree, the District Court accepted the EPA’s revised determination that the Company was responsible for approximately 85 % of the cleanup costs for OU2 and OU4. The Company filed an appeal against the District Court’s ruling on the grounds that the decision was flawed for several reasons, including the failure to consider the impact of recent Supreme Court decisions that restrict EPA authority and limit judicial deference to EPA actions. The Notice of Appeal was filed in February 2025, and all briefs have been filed as of January 2026.
As a result of the District Court’s approval of the Amended Consent Decree, the non-current environmental remediation liability related to OU2 and OU4 was increased by $925 million in the fourth quarter of 2024. This charge was included in asset impairments and other charges in the Consolidated Statements of Operations and represented the additional share of the total estimated remediation costs which may be incurred because of the assignment by the District Court of 85 % of the responsibility for OU2 and OU4. These costs have not been discounted as the timing and amount of the payments are not fixed or reliably determinable. It is expected that the cash outlay for remediation costs will be expended over to twenty years , or more.
The Alden Leeds settlement does not address the liability of entities that were excluded from the settlement, including for OU2, OU3, OU4 or natural resource damages, or the liability of any settling party with respect to OU3 or natural resource damages.
98 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
While the remedies for OU2 and OU4 are expected to take ten to twenty years to complete, the EPA may seek to require the Company to perform a substantial majority or all of the remediation work and provide additional financial assurance. It is uncertain when or to what extent the EPA may take action to compel further remediation in OU2 or OU4, or the amount of financial assurance that could be required.
In June 2018, the Company filed a complaint under CERCLA in the District Court against numerous potentially responsible parties seeking contribution and cost recovery of amounts incurred or to be incurred to comply with the AOC and the OU2 ROD, or to perform other remediation activities related to the DASS (2018 Contribution Action). Because costs are being incurred to implement the OU4 Unilateral Administrative Order, a cost recovery action under CERCLA was brought in March 2023 in the District Court against multiple parties (2023 Cost Recovery Action). Both the 2018 Contribution Action and the 2023 Cost Recovery Action were stayed pending the outcome of the Alden Leeds litigation. The Company does not know when the Court will lift the stay in those matters. If not reversed on appeal, the approved Amended Consent Decree could bar the Company from pursuing contribution against the settling parties for remediation costs incurred or that may be incurred in the future to design and implement the remedies in OU2 and OU4, including claims asserted in the 2018 Contribution Action.
Other information
For the DASS, a reserve has been accrued relating to the estimated allocable share of the costs to perform the maintenance and monitoring required in the OU1 Consent Decree, as well as the remedial investigation and feasibility study required in OU3 (Newark Bay). Subject to and without waiver of any rights, including appeal, a reserve has also been accrued for design and implementation of remedies selected in the OU2 ROD and AOC, and the OU4 ROD and OU4 Unilateral Administrative Order, based on the December 2024 Order of the District Court approving the Amended Consent Decree described above, which Order is currently being appealed.
The accrued environmental remediation reserve does not account for the possibility of additional remediation costs or natural resource damages for the DASS that are not considered reasonably estimable. The ultimate liability at the DASS may be greater or less than both the reserved amount and any reasonably possible additional losses, and will depend on final design plans, future actions by the EPA and natural resource trustees, as well as the resolution of the allocable share with other potentially responsible parties, among other factors.
The estimated costs currently recorded for remediation at the DASS and the range of reasonably possible additional losses beyond the amounts currently recognized are evaluated periodically. Due to the complexity and scope of the remediation efforts, the estimated costs may fluctuate over time as new information becomes available.
| NOTE 12 - LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES | ||
LEGAL MATTERS
The Company is involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. The Company is also involved in proceedings under CERCLA and similar federal, regional, state, provincial, tribal, local and international environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, natural resource damages, punitive damages, civil penalties, injunctive relief and government oversight costs, as described in Note 11 - Environmental Liabilities and Expenditures. Usually the Company is among many companies in these environmental proceedings and has to date been successful in sharing remediation costs with other financially sound companies. Further, some lawsuits, claims and legal proceedings involve acquired or disposed assets with respect to which a third party or the Company retains liability or indemnifies the other party for conditions that existed prior to the transaction.
In accordance with applicable accounting guidance, the Company accrues reserves for outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Other than reserves for the environmental remediation discussed above and tax matters discussed below, reserves for matters that satisfied these criteria as of December 31, 2025 and 2024 were not material to the Company’s Consolidated Balance Sheets.
If unfavorable outcomes of these matters were to occur, future results of operations or cash flows for any particular quarterly or annual period could be materially adversely affected. The Company’s estimates are based on information known about the legal matters and its experience in contesting, litigating and settling similar matters. The Company will reassess the probability and estimability of contingent losses as new information becomes available.
OXY 2025 FORM 10-K | 99 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
TAX MATTERS AND OTHER DISPUTES
During the course of its operations, the Company is subject to audit by tax authorities for varying periods in various federal, state, local and international tax jurisdictions. Tax years through 2021 for U.S. federal income tax purposes have been audited by the IRS pursuant to its Compliance Assurance Program and subsequent taxable years are currently under review. Tax years through 2018 have been audited for state income tax purposes. There are no outstanding significant audit matters in international jurisdictions. During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law.
The IRS is currently reviewing the legal entity reorganization transaction as part of the Company’s 2022 federal tax audit. Following the acquisition of Anadarko and related divestitures, the Company reorganized its legal entities to better align with the nature of its business activities. This reorganization resulted in the Company making an adjustment to the tax basis in a portion of its operating assets, reducing deferred tax liabilities and recording a $2.7 billion tax benefit in 2022.
For Anadarko, its taxable years through 2014 and tax year 2016 for U.S. federal tax purposes have been audited and closed by the IRS. Tax years 2015 and 2017 through 2019 have been audited by the IRS but remain open pending the outcome of the Tronox U.S. Tax Court litigation discussed below. Tax years through 2018 have been audited for state income tax purposes. There are no outstanding significant audit matters in international jurisdictions. As stated above, during the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law.
Other than the dispute discussed below, the Company believes that the resolution of these outstanding tax disputes would not have a material adverse effect on its consolidated financial position or results of operations.
Anadarko received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox Adversary Proceeding settlement payment in 2015. In September 2018, Anadarko received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting Anadarko’s refund claim. Anadarko disagreed and, in November 2018, filed a petition with the U.S. Tax Court to dispute the disallowance. Trial was held in May 2023. The parties filed post-trial briefs throughout 2023 and 2024. Closing arguments were held in May 2024. The Tax Court may issue an opinion at any time. If the Tax Court opines that all or a portion of the original $5.2 billion deduction is not deductible, a computation phase will commence where the parties will compute the tax amount to be included in the Tax Court’s decision. Once the parties submit their computation, the Tax Court judge will formally enter the decision reflecting the computed tax amount. To pursue an appeal of the Tax Court’s decision, any tax due as a result of the Tax Court’s decision must be fully bonded or paid within 90 days of the decision’s entry. If Anadarko does not pursue an appeal, the IRS will assess any resulting tax deficiency, including interest, and issue a notice demanding payment thereof.
In accordance with ASC 740’s guidance on the accounting for uncertain tax positions, the Company has recorded no tax benefit on the tentative cash tax refund of $881 million. Additionally, the Company has recorded no tax benefit on approximately $500 million of additional cash tax benefits realized from the utilization of tax attributes generated as a result of the deduction of the $5.2 billion Tronox Adversary Proceeding settlement payment in 2015. If the payment is ultimately determined not to be deductible, the Company would be required to repay the tentative refund received, plus other cash benefits received related to the $5.2 billion deduction, plus interest, which as of December 31, 2025 totaled approximately $2.3 billion. As a result, should the Company not ultimately prevail on the issue, there would be no additional tax expense recorded relative to this position for financial statement purposes other than future interest. However, in that event, as of December 31, 2025, the Company would be required to repay approximately $1.4 billion in federal and state taxes and accrued interest of $0.9 billion. A liability for the taxes and interest is included in deferred credits and other liabilities - other.
INDEMNITIES TO THIRD PARTIES
The Company has indemnified various parties against specified liabilities those parties might incur in the future in connection with purchases and other transactions that they have entered into with the Company. These indemnities usually are contingent upon the other party incurring liabilities that reach specified thresholds. The Company reserves for indemnity claims when a payment for such claims is probable and estimable. As discussed in Note 4 - Acquisitions, Divestitures and Other Transactions, The Company is providing indemnification to Berkshire Hathaway for retained liabilities in the OxyChem Transaction.
PURCHASE OBLIGATIONS AND COMMITMENTS
The Company has entered into agreements providing for future payments, primarily to secure terminal, pipeline and processing capacity, CO2, drilling rigs and services, electrical power, non-lease components and steam. The Company has certain other commitments under contracts, guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent liabilities. The amounts that will be paid for such outstanding off-balance sheet purchase obligations as of December 31, 2025 are $3.0 billion in 2026, $4.7 2.6 2.3 billion in 2031 and thereafter.
100 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 13 - STOCKHOLDERS’ EQUITY | ||
The following table presents Occidental’s common share activity, including exercises of warrants, and other transactions in Occidental’s common stock in 2025:
| Period | Exercise of Common Stock Warrants | (a) | Other | (b) | Common Stock Outstanding | (c) | ||||||||||||||
| December 31, 2024 | ||||||||||||||||||||
| First Quarter 2025 | ||||||||||||||||||||
| Second Quarter 2025 | ||||||||||||||||||||
| Third Quarter 2025 | ||||||||||||||||||||
| Fourth Quarter 2025 | ||||||||||||||||||||
| Total 2025 | ||||||||||||||||||||
(a)$930 million of cash was received in 2025 from the exercise of common stock warrants.
(b)Consists of issuances under the 2015 long-term incentive plan, the OPC savings plan and the dividend reinvestment plan.
(c)As of December 31, 2025, the Company had 30.4 million of outstanding warrants with a strike price of $22 per share and 83.9 million of warrants with a strike price of $59.59 per share.
TREASURY STOCK
As of December 31, 2025, 2024 and 2023, treasury stock shares numbered 228.3 million, 228.3 million and 228.1 million, respectively.
PREFERRED STOCK
In 2019, Occidental issued 100,000 shares of Occidental series A preferred stock, with a face value of $100,000 per share and a liquidation preference of $105,000 per share plus unpaid accrued dividends to Berkshire Hathaway. Prior to August 2029, a mandatory redemption provision obligates Occidental to redeem preferred stock at a 10 % premium to face value on a dollar-for-dollar basis for every dollar distributed to common shareholders (either via common stock dividends or share repurchases) above $4.00 per share, on a trailing 12-month basis. Preferred redemptions can settle between 30 and 60 days from the date Berkshire Hathaway is notified of the redemption obligation and accrued unpaid dividends are paid up to but not including the redemption date. Occidental cannot voluntarily redeem preferred stock before August 2029. After August 2029, Occidental can voluntarily redeem preferred stock at a 5 % premium to face value.
Dividends on the preferred stock accrue on the face value at a rate per annum of 8 %, but will be paid only when, as and if declared by the Company’s Board of Directors. At any time, when such dividends have not been paid in full, the unpaid amounts will accrue dividends, compounded quarterly, at a rate per annum of 9 %. Following the payment in full of any accrued but unpaid dividends, the dividend rate will remain at 9 % per annum. If preferred dividends are not paid in full, Occidental is prohibited from paying dividends on common stock. Occidental paid $679 million in preferred stock dividends in 2025.
Occidental did not redeem preferred stock in 2025. To the extent Occidental’s trailing 12-month distributions to common shareholders is above $4.00 per share, Occidental is required to match any common shareholder distributions with preferred stock redemptions. As of the date of this filing, approximately $8.5 billion face value of the preferred stock remains outstanding.
BERKSHIRE WARRANT
In connection with the preferred stock issuance, Occidental also issued the Berkshire Warrant. The Berkshire Warrant is exercisable at the holder’s option, in whole or in part, until the first anniversary of the date on which no shares of preferred stock remain outstanding, at which time the Berkshire Warrant expires. The holder of the Berkshire Warrant and the preferred stock may redeem the preferred stock as payment for the exercise price of the Warrant in lieu of cash payment upon exercise. As of December 31, 2025, the Berkshire Warrant would result in the issuance of 83.9 million shares of Occidental common stock, if exercised in full for its current strike price of $59.59 per share of Occidental common stock.
COMMON STOCK WARRANTS
Occidental issued approximately 116 million Common Stock Warrants on August 3, 2020 to holders of record of outstanding shares of Occidental’s common stock as of the close of business on July 6, 2020. The Common Stock Warrants have an exercise price of $22.00 per share and will expire on August 3, 2027. As of December 31, 2025, Occidental had 30.4 million outstanding warrants.
OXY 2025 FORM 10-K | 101 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
EARNINGS PER SHARE
Occidental’s instruments containing rights to nonforfeitable dividends granted in stock-based awards are considered participating securities prior to vesting and, therefore, have been deducted from earnings in computing basic and diluted EPS under the two-class method.
Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the weighted-average number of common shares outstanding during each period, including vested but unissued shares and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options, warrants and unvested stock awards.
The following table presents the calculation of basic and diluted EPS for the years ended December 31:
| millions except per share amounts | 2025 | 2024 | 2023 | ||||||||
Income from continuing operations | $ | $ | $ | ||||||||
| Income from discontinued operations, net of tax | |||||||||||
Net income | $ | $ | $ | ||||||||
| Less: Net income attributable to noncontrolling interest | ( | ( | |||||||||
| Less: Preferred stock dividends | ( | ( | ( | ||||||||
Net income attributable to common stock | $ | $ | $ | ||||||||
| Less: Incremental fair value for warrants inducement | ( | ||||||||||
| Less: Net income allocated to participating securities | ( | ( | ( | ||||||||
Net income, net of participating securities | $ | $ | $ | ||||||||
| Weighted-average number of basic shares | |||||||||||
Basic earnings per common share | $ | $ | $ | ||||||||
| Net income attributable to common stock | $ | $ | $ | ||||||||
| Less: Incremental fair value for warrants inducement | ( | ||||||||||
| Less: Net income allocated to participating securities | ( | ( | ( | ||||||||
Net income, net of participating securities | $ | $ | $ | ||||||||
| Weighted-average number of basic shares | |||||||||||
| Dilutive securities | |||||||||||
| Total diluted weighted-average common shares | |||||||||||
Diluted earnings per common share | $ | $ | $ | ||||||||
For the year ended December 31, 2025, there were 84.2 no
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Accumulated OCI (loss) consisted of the following after-tax amounts as of December 31, 2025 and 2024:
| millions | 2025 | 2024 | ||||||
| Foreign currency translation adjustments | $ | ( | $ | ( | ||||
| Derivatives | ||||||||
Pension and postretirement adjustments (a) | ||||||||
| Total | $ | $ | ||||||
(a)See Note 10 - Retirement and Postretirement Benefit Plans for further information.
102 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 14 - STOCK-BASED INCENTIVE PLANS | ||
Occidental issues stock-based awards to employees in accordance with the terms of the Plans. An aggregate of 188 million shares of Occidental common stock were authorized for issuance and approximately 14.4 million shares had been reserved for issuance for employee awards through December 31, 2025. As of December 31, 2025, approximately 68.8 million shares were available for grants of future awards. The 2015 Long-Term Incentive Plan requires each share covered by an award (other than options) to be counted as if three shares were issued in determining the number of shares that are available for future awards. Accordingly, the number of shares available for future awards may be less than 68.8 million depending on the type of award granted, and shares available for future awards may increase by the number of shares that are forfeited, canceled, or correspond to the portion of any stock-based awards settled in cash, including awards that were issued under a previous plan that remain outstanding. Current outstanding awards include RSUs, stock options, CROCEI awards and TSRI awards.
During 2025, non-employee directors were granted awards for 60,040 shares of common stock. Compensation expense for these awards was measured using the closing quoted market price of Occidental’s common stock on the grant date and was fully recognized at that time.
The Company incurred expenses of $234 million, $213 million and $203 million related to stock-based incentive plans in the years ended December 31, 2025, 2024 and 2023, respectively. The income tax benefit associated with this expense was $49 million, $45 million and $43 million in the years ended December 31, 2025, 2024 and 2023, respectively.
As of December 31, 2025, unrecognized compensation expense for all unvested stock-based incentive awards was $319 million. This expense is expected to be recognized over a weighted-average period of 1.8 years. The Company accounts for forfeitures as they occur.
RESTRICTED STOCK UNITS
Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs may be settled in stock or may be cash settled liabilities. These awards vest from to three years following the grant date. For certain RSUs, dividend equivalents are paid during the vesting period.
CASH-SETTLED RSU LIABILITY AWARDS
The weighted-average, grant-date fair values of cash-settled RSUs granted in 2025, 2024 and 2023 were $46.44 , $58.87 and $60.43 per share, respectively. Cash-settled RSUs resulted in payments of $8 million, $8 million and $9 million, during the years ended December 31, 2025, 2024 and 2023, respectively.
STOCK-SETTLED RSU EQUITY AWARDS
The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2025, 2024 and 2023 were $48.85 , $61.34 and $59.85 , respectively. The fair value of RSUs settled in shares during the years ended December 31, 2025, 2024 and 2023 was $171 million, $240 million and $254 million, respectively.
A summary of changes in the Company’s unvested cash- and stock-settled RSUs for 2025 is presented below:
| Cash-Settled | Stock-Settled | |||||||||||||
| thousands, except fair values | RSUs | RSUs | ||||||||||||
| Unvested as of January 1 | $ | $ | ||||||||||||
| Granted | $ | $ | ||||||||||||
| Vested | ( | $ | ( | $ | ||||||||||
| Forfeitures | ( | $ | ( | $ | ||||||||||
| Unvested as of December 31 | $ | $ | ||||||||||||
TOTAL SHAREHOLDER RETURN INCENTIVE AWARDS
Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date. Payout is based upon the Company’s absolute total shareholder return and performance relative to its peers. TSRIs have payouts that range from 0 % to 200 % of the target award and settle in stock once certified. Dividend equivalents for TSRIs are accumulated and paid upon certification of the award. The fair value of TSRIs settled in shares during the years ended December 31, 2025, 2024 and 2023 was $33 million, $68 million and $45 million, respectively.
OXY 2025 FORM 10-K | 103 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The fair values of TSRIs are initially determined on the grant date using a Monte Carlo simulation model based on the Company’s assumptions, noted in the following table, and the volatility from corresponding peer group companies. The expected life is based on the Term. The risk-free interest rate is the implied yield available on zero coupon Treasury notes at the time of grant with a remaining term equal to the Term. The dividend yield is the expected annual dividend yield over the Term, expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by the employees who receive the awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by the Company.
The grant-date assumptions used in the Monte Carlo simulation models for the estimated payout level of TSRIs were as follows:
| TSRIs | |||||||||||
| 2025 | 2024 | 2023 | |||||||||
| Assumptions used: | |||||||||||
| Risk-free interest rate | |||||||||||
| Volatility factor | |||||||||||
Expected life, years | |||||||||||
| Grant-date fair value of underlying Occidental common stock | $ | $ | $ | ||||||||
A summary of changes in the Company’s unvested TSRIs in 2025 is presented below:
| TSRIs | ||||||||||||||
| thousands, except fair values | Awards | Weighted-Average Grant-Date Fair Value of Occidental Stock | ||||||||||||
| Unvested as of January 1 | $ | |||||||||||||
| Granted | $ | |||||||||||||
Vested (a) | ( | $ | ||||||||||||
| Forfeitures | ( | $ | ||||||||||||
| Unvested as of December 31 | $ | |||||||||||||
(a)Presented at the target payouts. In 2025, the weighted-average payout at vesting was 176 % of the target, resulting in the issuance of approximately 683,358 shares of Occidental common stock.
STOCK OPTIONS
Certain employees are granted options that vest over three years , expire on the tenth anniversary of the grant date, and settle in stock. Exercise prices of the options were equal to the quoted market value of Occidental’s stock on the grant date. There were no options granted in 2025.
A summary of the Company’s outstanding stock options as of December 31, 2025 and changes during the year ended December 31, 2025 is presented below:
| Vested | Unvested | |||||||||||||
| thousands, except fair values | Options | Weighted Average Strike Price | Options | Weighted Average Strike Price | ||||||||||
| January 1 | $ | $ | ||||||||||||
| Vested | $ | ( | $ | |||||||||||
| December 31 | $ | $ | ||||||||||||
There were no 9 million. As of December 31, 2025, the weighted average remaining life of fully vested options was 4.5 years.
CASH RETURN ON CAPITAL EMPLOYED INCENTIVE AWARDS
Certain executives are awarded CROCEI awards that vest at the end of a three-year period if performance targets based on CROCE are met. These awards are settled in stock upon certification of the performance target, with payouts that range from 0 % to 200 % of the target award. Dividend equivalents are accumulated and paid upon certification of the award.
104 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
The value of shares that vested in 2025, 2024 and 2023 were $15 million, $25 million and $25 million, respectively. A summary of changes in the Company’s unvested CROCEI in 2025 is presented below:
| CROCEI | |||||||||||
| thousands, except fair values | Awards | Weighted-Average Grant-Date Fair Value of Occidental Stock | |||||||||
| Unvested as of January 1 | $ | ||||||||||
| Granted | $ | ||||||||||
Vested (a) | ( | $ | |||||||||
| Forfeited | ( | ||||||||||
| Unvested as of December 31 | $ | ||||||||||
(a) Presented at the target payouts. In 2025, the weighted-average payout at vesting was 200 % of the target, resulting in the issuance of approximately 312,000 shares of Occidental common stock.
OXY 2025 FORM 10-K | 105 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
| NOTE 15 - INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS | ||
The Company conducts its operations through two
In October 2025, the Company announced entry into a purchase and sale agreement with Berkshire Hathaway to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion. The sale was completed on January 2, 2026, with final proceeds subject to post-closing adjustments. The Company reassessed its operating segments. Accordingly, the chemical segment results are presented separately as discontinued operations and corporate costs directly attributable to the chemical segment are included under discontinued operations. See Note 4 - Acquisitions, Divestitures and Other Transactions for related disclosure.
The Company’s President and CEO is ultimately responsible for allocating resources and assessing the performance of each operating segment and is the Company’s CODM. The CEO may be assisted in this function by other members of the Company’s executive management including, but not limited to, the Chief Financial Officer and Chief Operating Officer. While other executives are responsible for the performance of their individual areas, the CEO is solely responsible for allocating resources across the Company as a whole.
For both reporting segments, the CODM utilizes segment income (loss) from continuing operations before income taxes to measure performance, as well as allocate resources (including financial or capital resources) for each segment, predominantly in the annual budget and forecasting process.
The following table reconciles segment income from continuing operations before taxes to net income attributable to common shares:
| Years Ended December 31, | |||||||||||
| millions | 2025 | 2024 | 2023 | ||||||||
| Segment income from continuing operations before taxes | |||||||||||
| Oil and gas segment | $ | $ | $ | ||||||||
| Midstream and marketing segment | ( | ||||||||||
| Corporate and eliminations | ( | ( | ( | ||||||||
| Interest and debt expense, net | ( | ( | ( | ||||||||
Income from continuing operations before income taxes | $ | $ | $ | ||||||||
Income tax expense | ( | ( | ( | ||||||||
Income from continuing operations | $ | $ | $ | ||||||||
| Discontinued operations, net of tax | |||||||||||
| Net income | $ | $ | $ | ||||||||
| Less: Net income attributable to noncontrolling interest | ( | ( | |||||||||
Less: Preferred stock dividends and redemption premiums | ( | ( | ( | ||||||||
| Net income attributable to common stockholders | $ | $ | $ | ||||||||
The following tables include a summary of significant revenue and expense line items for each segment. Items within “Significant segment expenses” align with the significant segment-level information that is regularly provided to the CODM as required by the adoption of ASU 2023-07 in the fourth quarter of 2024. Intersegment expenses are included within the amounts shown.
106 | OXY 2025 FORM 10-K | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
OIL AND GAS SEGMENT
Other segment expenses include asset impairments and other charges, selling, general and administrative expense and exploration expense:
| Years Ended December 31, | |||||||||||
| millions | 2025 | 2024 | 2023 | ||||||||
| Revenues and other income | |||||||||||
| Net sales | $ | $ | $ | ||||||||
| Gains (losses) on sale of assets and other income | ( | ( | |||||||||
| Total | $ | $ | $ | ||||||||
| Significant segment expenses | |||||||||||
Oil and gas lease operating expense | |||||||||||
| Transportation and gathering expense | |||||||||||
| Other operating and non-operating expense | |||||||||||
| Taxes other than on income | |||||||||||
| Depreciation, depletion and amortization | |||||||||||
| Other segment expenses | |||||||||||
| Total | $ | $ | $ | ||||||||
| Segment income before other items | $ | $ | $ | ||||||||
| Losses from equity investments and other | ( | ( | ( | ||||||||
| Segment income from continuing operations before taxes | $ | $ | $ | ||||||||
MIDSTREAM AND MARKETING SEGMENT
Other segment expenses include asset impairments and other charges, transportation expense, taxes other than on income, and selling, general and administrative expense:
| Years Ended December 31, | |||||||||||
| millions | 2025 | 2024 | 2023 | ||||||||
| Revenues and other income | |||||||||||
| Net sales | $ | $ | $ | ||||||||
| Gains on sale of assets and other income | |||||||||||
| Total | $ | $ | $ | ||||||||
| Significant segment expenses | |||||||||||
| Purchased commodities and midstream cost of sales | |||||||||||
| Other operating and non-operating expense | |||||||||||
| Depreciation, depletion and amortization | |||||||||||
| Other segment expenses | |||||||||||
| Total | $ | $ | $ | ||||||||
| Segment income (losses) before other items | $ | $ | ( | $ | ( | ||||||
Income from equity investments and other | |||||||||||
| Segment income (losses) from continuing operations before taxes | $ | $ | $ | ( | |||||||
OXY 2025 FORM 10-K | 107 | ||||
| table of contents | FINANCIAL STATEMENTS FOOTNOTES | ||||||
SEGMENT INVESTMENTS AND EXPENDITURES
The following table includes segment-level balance sheet information:
| millions | Oil and gas | Midstream and marketing | Corporate and eliminations | Assets held for sale | Total | ||||||||||||
| Year ended December 31, 2025 | |||||||||||||||||
| PP&E Additions | $ | $ | $ | $ | — | $ | |||||||||||
| Investments in unconsolidated entities | $ | $ | $ | — | $ | — | $ | ||||||||||
| Total Assets | $ | $ | $ | $ | $ | ||||||||||||
| Year ended December 31, 2024 | |||||||||||||||||
| PP&E Additions | $ | $ | $ | $ | $ | ||||||||||||
| Investments in unconsolidated entities | $ | $ | $ | $ | $ | ||||||||||||
| Total Assets | $ | $ | $ | $ | $ | ||||||||||||
GEOGRAPHIC AREAS
| millions | 2025 | 2024 | 2023 | ||||||||
| United States | $ | $ | $ | ||||||||
| International | |||||||||||
| UAE | |||||||||||
| Oman | |||||||||||
| Algeria | |||||||||||
| Qatar | |||||||||||
| Other International | |||||||||||
| Total International | |||||||||||
| Total | $ | $ | $ | ||||||||
108 | OXY 2025 FORM 10-K | ||||
| table of contents | Supplemental Quarterly Financial Data (Unaudited) | ||||||
| Supplemental Quarterly Financial Data (Unaudited) | Occidental Petroleum Corporation and Subsidiaries | ||||
| millions except per-share amounts | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||
| 2025 | ||||||||||||||
| Segment net sales | ||||||||||||||
| Oil and gas | $ | 5,683 | $ | 5,009 | $ | 5,404 | $ | 4,806 | ||||||
| Midstream and marketing | 173 | 390 | 265 | 451 | ||||||||||
| Eliminations | (152) | (141) | (150) | (145) | ||||||||||
| Net sales | $ | 5,704 | $ | 5,258 | $ | 5,519 | $ | 5,112 | ||||||
| Segment earnings | ||||||||||||||
| Oil and gas | $ | 1,697 | $ | 934 | $ | 1,300 | $ | 655 | ||||||
| Midstream and marketing | (72) | 39 | 81 | 204 | ||||||||||
| Total segment earnings | $ | 1,625 | $ | 973 | $ | 1,381 | $ | 859 | ||||||
| Unallocated corporate items | ||||||||||||||
| Interest expense, net | (310) | (271) | (266) | (232) | ||||||||||
| Income tax benefit | (347) | (222) | (279) | (173) | ||||||||||
| Other | (138) | (142) | (130) | (221) | ||||||||||
| Income from continuing operations | $ | 830 | $ | 338 | $ | 706 | $ | 233 | ||||||
| Discontinued operations, net of taxes | 115 | 130 | 136 | (119) | ||||||||||
| Net Income | $ | 945 | $ | 468 | $ | 842 | $ | 114 | ||||||
| Less: Net income attributable to noncontrolling interests | (9) | (10) | (12) | (12) | ||||||||||
| Less: Preferred stock dividend | (170) | (170) | (169) | (170) | ||||||||||
| Net income (loss) attributable to common stockholders | $ | 766 | $ | 288 | $ | 661 | $ | (68) | ||||||
| Basic income (loss) per common share | $ | 0.81 | $ | 0.27 | $ | 0.67 | $ | (0.07) | ||||||
| Diluted income (loss) per common share | $ | 0.77 | $ | 0.26 | $ | 0.65 | $ | (0.07) | ||||||
| Dividends per common share | $ | 0.24 | $ | 0.24 | $ | 0.24 | $ | 0.24 | ||||||
| 2024 | ||||||||||||||
| Segment net sales | ||||||||||||||
| Oil and gas | $ | 4,915 | $ | 5,469 | $ | 5,697 | $ | 5,624 | ||||||
| Midstream and marketing | 78 | 257 | 399 | 152 | ||||||||||
| Eliminations | (146) | (146) | (141) | (139) | ||||||||||
| Net sales | $ | 4,847 | $ | 5,580 | $ | 5,955 | $ | 5,637 | ||||||
| Segment earnings | ||||||||||||||
| Oil and gas | $ | 1,238 | $ | 1,639 | $ | 1,165 | $ | 1,172 | ||||||
| Midstream and marketing | (38) | 110 | 614 | (123) | ||||||||||
| Total segment earnings | $ | 1,200 | $ | 1,749 | $ | 1,779 | $ | 1,049 | ||||||
| Unallocated corporate items | ||||||||||||||
| Interest expense, net | (290) | (258) | (305) | (316) | ||||||||||
| Income tax expense | (248) | (402) | (391) | (117) | ||||||||||
| Other | (155) | (143) | (183) | (103) | ||||||||||
| Income from continuing operations | $ | 507 | $ | 946 | $ | 900 | $ | 513 | ||||||
| Discontinued operations, net of taxes | 381 | 224 | 240 | (633) | ||||||||||
| Net Income (loss) | $ | 888 | $ | 1,170 | $ | 1,140 | $ | (120) | ||||||
| Less: Net income attributable to noncontrolling interests | — | (8) | (7) | (7) | ||||||||||
| Less: Preferred stock dividend | (170) | (170) | (169) | (170) | ||||||||||
| Net income (loss) attributable to common stockholders | $ | 718 | $ | 992 | $ | 964 | $ | (297) | ||||||
| Basic earnings (loss) per common share | $ | 0.81 | $ | 1.10 | $ | 1.03 | $ | (0.32) | ||||||
| Diluted earnings (loss) per common share | $ | 0.75 | $ | 1.03 | $ | 0.98 | $ | (0.30) | ||||||
| Dividends per common share | $ | 0.22 | $ | 0.22 | $ | 0.22 | $ | 0.22 | ||||||
OXY 2025 FORM 10-K | 109 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
Supplemental Oil and Gas Information
OIL AND GAS RESERVES
The following tables set forth the Company’s net interests in quantities of proved developed and undeveloped reserves of oil, NGL and natural gas and changes in such quantities. Proved oil, NGL and natural gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGL and natural gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs. The following table shows the pricing used in the reserve analysis for the periods presented:
| 2025 | 2024 | 2023 | |||||||||
| Average WTI Oil ($/Bbl) | $ | 65.34 | $ | 75.48 | $ | 78.22 | |||||
| Average Brent Oil ($/Bbl) | $ | 68.42 | $ | 79.65 | $ | 82.80 | |||||
| Average Henry Hub Natural Gas ($/MMbtu) | $ | 3.39 | $ | 2.13 | $ | 2.64 | |||||
| Average Mt. Belvieu NGL ($/Bbl) | $ | 31.79 | $ | 33.04 | $ | 29.94 | |||||
Reserves are stated net of applicable royalties. Estimated reserves include the Company’s economic interests under PSCs and other similar economic arrangements. In addition, discussions of oil and gas production or volumes, in general, refer to sales volumes unless the context requires or it is indicated otherwise.
Prices for oil, NGL and natural gas fluctuate widely. Historically, the markets for oil, NGL and natural gas and refined products have been volatile and may continue to be volatile in the future. Prolonged declines in oil, NGL and natural gas prices would reduce the Company’s operating results and cash flows and could impact its future rate of growth and the recoverability of the carrying value of its assets.
110 | OXY 2025 FORM 10-K | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
OIL RESERVES
| MMbbl | United States | International | Total | |||||||||||||||||
| PROVED DEVELOPED AND UNDEVELOPED RESERVES | ||||||||||||||||||||
| Balance as of December 31, 2022 | 1,639 | 274 | 1,913 | |||||||||||||||||
| Revisions of previous estimates | 77 | 91 | 168 | |||||||||||||||||
| Improved recovery | 7 | 11 | 18 | |||||||||||||||||
| Extensions and discoveries | 59 | 3 | 62 | |||||||||||||||||
| Purchases of proved reserves | 14 | — | 14 | |||||||||||||||||
| Sales of proved reserves | (1) | — | (1) | |||||||||||||||||
| Production | (195) | (39) | (234) | |||||||||||||||||
| Balance as of December 31, 2023 | 1,600 | 340 | 1,940 | |||||||||||||||||
| Revisions of previous estimates | 47 | (7) | 40 | |||||||||||||||||
| Improved recovery | 38 | 6 | 44 | |||||||||||||||||
| Extensions and discoveries | 132 | 2 | 134 | |||||||||||||||||
| Purchases of proved reserves | 254 | — | 254 | |||||||||||||||||
| Sales of proved reserves | (30) | — | (30) | |||||||||||||||||
| Production | (209) | (38) | (247) | |||||||||||||||||
| Balance as of December 31, 2024 | 1,832 | 303 | 2,135 | |||||||||||||||||
Revisions of previous estimates(a) | 36 | 69 | 105 | |||||||||||||||||
| Improved recovery | 49 | 6 | 55 | |||||||||||||||||
| Extensions and discoveries | 149 | — | 149 | |||||||||||||||||
| Purchases of proved reserves | 4 | — | 4 | |||||||||||||||||
| Sales of proved reserves | (20) | — | (20) | |||||||||||||||||
| Production | (226) | (40) | (266) | |||||||||||||||||
| Balance as of December 31, 2025 | 1,824 | 338 | 2,162 | |||||||||||||||||
| PROVED DEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2022 | 1,208 | 200 | 1,408 | |||||||||||||||||
| December 31, 2023 | 1,140 | 258 | 1,398 | |||||||||||||||||
| December 31, 2024 | 1,243 | 249 | 1,492 | |||||||||||||||||
| December 31, 2025 | 1,258 | 279 | 1,537 | |||||||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2022 | 431 | 74 | 505 | |||||||||||||||||
| December 31, 2023 | 460 | 82 | 542 | |||||||||||||||||
| December 31, 2024 | 589 | 54 | 643 | |||||||||||||||||
| December 31, 2025 | 566 | 59 | 625 | |||||||||||||||||
(a)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 53 MMbbl were related to additions associated with infill development projects, mainly in the Permian Basin (28 MMbbl) and the DJ Basin (16 MMbbl). Further positive revisions were associated with changes in economic conditions (73 MMbbl), primarily in the Permian Basin (70 MMbbl), and the Oman contract extension (61 MMbbl). The positive revisions were partially offset by negative price revisions of 57 MMbbl primarily associated with the Permian Basin (61 MMbbl), which were partially offset by positive price revisions of 5 MMbbl on international PSCs. Further negative revisions were associated with updates based on reservoir performance (19 MMbbl) primarily related to the Permian Basin (57 MMbbl), which were partially offset by positive reservoir performance updates in the DJ Basin (18 MMbbl) and GOA (17 MMbbl).
OXY 2025 FORM 10-K | 111 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
NGL RESERVES
| MMbbl | United States | International | Total | |||||||||||||||||
| PROVED DEVELOPED AND UNDEVELOPED RESERVES | ||||||||||||||||||||
| Balance as of December 31, 2022 | 654 | 192 | 846 | |||||||||||||||||
| Revisions of previous estimates | 183 | 2 | 185 | |||||||||||||||||
| Improved recovery | 2 | — | 2 | |||||||||||||||||
| Extensions and discoveries | 45 | — | 45 | |||||||||||||||||
| Purchases of proved reserves | 9 | — | 9 | |||||||||||||||||
| Sales of proved reserves | (1) | — | (1) | |||||||||||||||||
| Production | (90) | (13) | (103) | |||||||||||||||||
| Balance as of December 31, 2023 | 802 | 181 | 983 | |||||||||||||||||
| Revisions of previous estimates | 68 | 9 | 77 | |||||||||||||||||
| Improved recovery | 2 | — | 2 | |||||||||||||||||
| Extensions and discoveries | 100 | — | 100 | |||||||||||||||||
| Purchases of proved reserves | 200 | — | 200 | |||||||||||||||||
| Sales of proved reserves | (10) | — | (10) | |||||||||||||||||
| Production | (102) | (14) | (116) | |||||||||||||||||
| Balance as of December 31, 2024 | 1,060 | 176 | 1,236 | |||||||||||||||||
Revisions of previous estimates(a) | (53) | (2) | (55) | |||||||||||||||||
| Improved recovery | 3 | — | 3 | |||||||||||||||||
| Extensions and discoveries | 100 | — | 100 | |||||||||||||||||
| Purchases of proved reserves | 3 | — | 3 | |||||||||||||||||
| Sales of proved reserves | (18) | — | (18) | |||||||||||||||||
| Production | (105) | (14) | (119) | |||||||||||||||||
| Balance as of December 31, 2025 | 990 | 160 | 1,150 | |||||||||||||||||
| PROVED DEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2022 | 444 | 120 | 564 | |||||||||||||||||
| December 31, 2023 | 515 | 124 | 639 | |||||||||||||||||
| December 31, 2024 | 709 | 130 | 839 | |||||||||||||||||
| December 31, 2025 | 698 | 119 | 817 | |||||||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2021 | 210 | 72 | 282 | |||||||||||||||||
| December 31, 2023 | 287 | 57 | 344 | |||||||||||||||||
| December 31, 2024 | 351 | 46 | 397 | |||||||||||||||||
| December 31, 2025 | 292 | 41 | 333 | |||||||||||||||||
(a)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 28 MMbbl were related to additions associated with infill development projects, mainly in the Permian Basin (14 MMbbl) and the DJ Basin (13 MMbbl). Further positive revisions were associated with changes in economic conditions (34 MMbbl), primarily in the Permian Basin (30 MMbbl). The positive revisions were partially offset by negative revisions associated with updates based on reservoir performance (93 MMbbl) primarily related to the DJ Basin (78 MMbbl). Further negative revisions were associated with negative price revisions of 19 MMbbl primarily associated with the Permian Basin (21 MMbbl), which were partially offset by positive price revisions of 2 MMbbl in the DJ Basin, and negative revisions related to management changes in development plans (7 MMbbl).
112 | OXY 2025 FORM 10-K | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
NATURAL GAS RESERVES
| Bcf | United States | International | Total | |||||||||||||||||
| PROVED DEVELOPED AND UNDEVELOPED RESERVES | ||||||||||||||||||||
| Balance as of December 31, 2022 | 4,073 | 2,277 | 6,350 | |||||||||||||||||
| Revisions of previous estimates | 325 | (6) | 319 | |||||||||||||||||
| Improved recovery | 1 | 17 | 18 | |||||||||||||||||
| Extensions and discoveries | 268 | 5 | 273 | |||||||||||||||||
| Purchases of proved reserves | 50 | — | 50 | |||||||||||||||||
| Sales of proved reserves | (2) | — | (2) | |||||||||||||||||
| Production | (480) | (176) | (656) | |||||||||||||||||
| Balance as of December 31, 2023 | 4,235 | 2,117 | 6,352 | |||||||||||||||||
| Revisions of previous estimates | 215 | 100 | 315 | |||||||||||||||||
| Improved recovery | 2 | 6 | 8 | |||||||||||||||||
| Extensions and discoveries | 532 | 17 | 549 | |||||||||||||||||
| Purchases of proved reserves | 1,016 | — | 1,016 | |||||||||||||||||
| Sales of proved reserves | (58) | — | (58) | |||||||||||||||||
| Production | (548) | (191) | (739) | |||||||||||||||||
| Balance as of December 31, 2024 | 5,394 | 2,049 | 7,443 | |||||||||||||||||
Revisions of previous estimates(a) | 636 | 32 | 668 | |||||||||||||||||
| Improved recovery | 6 | 8 | 14 | |||||||||||||||||
| Extensions and discoveries | 543 | — | 543 | |||||||||||||||||
| Purchases of proved reserves | 19 | — | 19 | |||||||||||||||||
| Sales of proved reserves | (113) | — | (113) | |||||||||||||||||
| Production | (643) | (186) | (829) | |||||||||||||||||
| Balance as of December 31, 2025 | 5,842 | 1,903 | 7,745 | |||||||||||||||||
| PROVED DEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2022 | 2,761 | 1,597 | 4,358 | |||||||||||||||||
| December 31, 2023 | 2,770 | 1,507 | 4,277 | |||||||||||||||||
| December 31, 2024 | 3,564 | 1,593 | 5,157 | |||||||||||||||||
| December 31, 2025 | 4,168 | 1,469 | 5,637 | |||||||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2022 | 1,312 | 680 | 1,992 | |||||||||||||||||
| December 31, 2023 | 1,465 | 610 | 2,075 | |||||||||||||||||
| December 31, 2024 | 1,830 | 456 | 2,286 | |||||||||||||||||
| December 31, 2025 | 1,674 | 434 | 2,108 | |||||||||||||||||
(a)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 205 Bcf were related to additions associated with infill development projects, mainly in the DJ Basin (118 Bcf) and the Permian Basin (72 Bcf). Further positive revisions were associated with updates based on reservoir performance (401 Bcf), primarily due to positive performance revisions in the DJ Basin (337 Bcf) and international assets (34 Bcf), and with changes in economic conditions (147 Bcf), primarily in the Permian Basin (134 Bcf). The positive revisions were partially offset by negative price revisions of 56 Bcf primarily associated with the Permian Basin (72 Bcf), which were partially offset by positive price revisions of 11 Bcf in the DJ Basin and 6 Bcf on international PSCs.
OXY 2025 FORM 10-K | 113 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
TOTAL RESERVES
MMboe (a) | United States | International | Total | |||||||||||||||||
| PROVED DEVELOPED AND UNDEVELOPED RESERVES | ||||||||||||||||||||
| Balance as of December 31, 2022 | 2,972 | 845 | 3,817 | |||||||||||||||||
| Revisions of previous estimates | 314 | 92 | 406 | |||||||||||||||||
| Improved recovery | 9 | 14 | 23 | |||||||||||||||||
| Extensions and discoveries | 149 | 4 | 153 | |||||||||||||||||
| Purchases of proved reserves | 31 | — | 31 | |||||||||||||||||
| Sales of proved reserves | (2) | — | (2) | |||||||||||||||||
| Production | (365) | (81) | (446) | |||||||||||||||||
| Balance as of December 31, 2023 | 3,108 | 874 | 3,982 | |||||||||||||||||
| Revisions of previous estimates | 151 | 19 | 170 | |||||||||||||||||
| Improved recovery | 40 | 7 | 47 | |||||||||||||||||
| Extensions and discoveries | 321 | 5 | 326 | |||||||||||||||||
| Purchases of proved reserves | 623 | — | 623 | |||||||||||||||||
| Sales of proved reserves | (50) | — | (50) | |||||||||||||||||
| Production | (402) | (84) | (486) | |||||||||||||||||
| Balance as of December 31, 2024 | 3,791 | 821 | 4,612 | |||||||||||||||||
Revisions of previous estimates(b) | 89 | 72 | 161 | |||||||||||||||||
| Improved recovery | 53 | 7 | 60 | |||||||||||||||||
| Extensions and discoveries | 340 | — | 340 | |||||||||||||||||
| Purchases of proved reserves | 10 | — | 10 | |||||||||||||||||
| Sales of proved reserves | (57) | — | (57) | |||||||||||||||||
| Production | (438) | (85) | (523) | |||||||||||||||||
| Balance as of December 31, 2025 | 3,788 | 815 | 4,603 | |||||||||||||||||
| PROVED DEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2022 | 2,112 | 586 | 2,698 | |||||||||||||||||
| December 31, 2023 | 2,117 | 633 | 2,750 | |||||||||||||||||
| December 31, 2024 | 2,546 | 645 | 3,191 | |||||||||||||||||
| December 31, 2025 | 2,651 | 643 | 3,294 | |||||||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||||||
| December 31, 2022 | 860 | 259 | 1,119 | |||||||||||||||||
| December 31, 2023 | 991 | 241 | 1,232 | |||||||||||||||||
| December 31, 2024 | 1,245 | 176 | 1,421 | |||||||||||||||||
| December 31, 2025 | 1,137 | 172 | 1,309 | |||||||||||||||||
(a)Natural gas volumes have been converted to Boe based on an energy content of six Mcf of gas to one barrel of oil. Conversion to Boe does not necessarily result in price equivalency.
(b)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 115 MMboe were related to additions associated with infill development projects, mainly in the Permian Basin (54 MMboe) and the DJ Basin (49 MMboe). Further positive revisions were associated with changes in economic conditions of 131 MMboe, primarily in the Permian Basin (122 MMboe), and the Oman contract extension (61 MMboe). The positive revisions were partially offset by negative price revisions of 85 MMboe primarily associated with the Permian Basin (94 MMboe), which were partially offset by positive price revisions of 7 MMboe on international PSCs. Further negative revisions were associated with updates based on reservoir performance (45 MMboe) primarily related to the Permian Basin (66 MMboe), which were partially offset by positive reservoir performance updates in GOA (19 MMboe).
114 | OXY 2025 FORM 10-K | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
CAPITALIZED COSTS
Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows:
| millions | United States | International | Total | |||||||||||||||||
| December 31, 2025 | ||||||||||||||||||||
| Proved properties | $ | 98,402 | $ | 17,606 | $ | 116,008 | ||||||||||||||
Unproved properties | 10,713 | 176 | 10,889 | |||||||||||||||||
Total capitalized costs (a) | 109,115 | 17,782 | 126,897 | |||||||||||||||||
| Proved properties depreciation, depletion and amortization | (53,137) | (13,938) | (67,075) | |||||||||||||||||
| Unproved properties valuation | (3,217) | — | (3,217) | |||||||||||||||||
| Total Accumulated depreciation, depletion and amortization | (56,354) | (13,938) | (70,292) | |||||||||||||||||
| Net capitalized costs | $ | 52,761 | $ | 3,844 | $ | 56,605 | ||||||||||||||
| December 31, 2024 | ||||||||||||||||||||
| Proved properties | $ | 91,017 | $ | 17,072 | $ | 108,089 | ||||||||||||||
| Unproved properties | 13,626 | 159 | 13,785 | |||||||||||||||||
Total capitalized costs (a) | 104,643 | 17,231 | 121,874 | |||||||||||||||||
| Proved properties depreciation, depletion and amortization | (45,268) | (13,437) | (58,705) | |||||||||||||||||
| Unproved properties valuation | (3,598) | — | (3,598) | |||||||||||||||||
| Total Accumulated depreciation, depletion and amortization | (48,866) | (13,437) | (62,303) | |||||||||||||||||
| Net capitalized costs | $ | 55,777 | $ | 3,794 | $ | 59,571 | ||||||||||||||
| December 31, 2023 | ||||||||||||||||||||
| Proved properties | $ | 78,188 | $ | 16,582 | $ | 94,770 | ||||||||||||||
| Unproved properties | 14,298 | 146 | 14,444 | |||||||||||||||||
Total capitalized costs (a) | 92,486 | 16,728 | 109,214 | |||||||||||||||||
| Proved properties depreciation, depletion and amortization | (42,102) | (12,940) | (55,042) | |||||||||||||||||
| Unproved properties valuation | (4,233) | — | (4,233) | |||||||||||||||||
| Total Accumulated depreciation, depletion and amortization | (46,335) | (12,940) | (59,275) | |||||||||||||||||
| Net capitalized costs | $ | 46,151 | $ | 3,788 | $ | 49,939 | ||||||||||||||
(a)Included acquisition costs, development costs, capitalized interest and AROs.
OXY 2025 FORM 10-K | 115 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
COSTS INCURRED
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, were as follows:
| millions | United States | International | Total | |||||||||||||||||
| For the year ended December 31, 2025 | ||||||||||||||||||||
Property acquisition costs (a) | ||||||||||||||||||||
| Proved properties | $ | 205 | $ | — | $ | 205 | ||||||||||||||
| Unproved properties | 237 | 1 | 238 | |||||||||||||||||
| Exploration costs | 399 | 149 | 548 | |||||||||||||||||
| Development costs | 5,074 | 512 | 5,586 | |||||||||||||||||
| Costs incurred | $ | 5,915 | $ | 662 | $ | 6,577 | ||||||||||||||
| For the year ended December 31, 2024 | ||||||||||||||||||||
Property acquisition costs (a) | ||||||||||||||||||||
| Proved properties | $ | 8,963 | $ | 8 | $ | 8,971 | ||||||||||||||
| Unproved properties | 3,178 | — | 3,178 | |||||||||||||||||
| Exploration costs | 544 | 180 | 724 | |||||||||||||||||
| Development costs | 4,584 | 500 | 5,084 | |||||||||||||||||
| Costs incurred | $ | 17,269 | $ | 688 | $ | 17,957 | ||||||||||||||
| For the year ended December 31, 2023 | ||||||||||||||||||||
Property acquisition costs (a) | ||||||||||||||||||||
| Proved properties | $ | 112 | $ | 288 | $ | 400 | ||||||||||||||
| Unproved properties | 143 | — | 143 | |||||||||||||||||
| Exploration costs | 743 | 150 | 893 | |||||||||||||||||
| Development costs | 3,957 | 543 | 4,500 | |||||||||||||||||
| Costs incurred | $ | 4,955 | $ | 981 | $ | 5,936 | ||||||||||||||
(a)Included approximately $290 million, $30 million and $120 million in property acquisition costs related to non-monetary exchange transactions for the years ended December 31, 2025, 2024 and 2023, respectively.
116 | OXY 2025 FORM 10-K | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
RESULTS OF OPERATIONS
The Company’s oil and gas producing activities for continuing operations, which exclude items such as asset divestitures, corporate overhead and interest, were as follows:
| millions | United States | International | Total | |||||||||||||||||
| FOR THE YEAR ENDED DECEMBER 31, 2025 | ||||||||||||||||||||
| Revenues | $ | 17,460 | $ | 3,423 | $ | 20,883 | ||||||||||||||
| Lease operating costs | 3,665 | 1,016 | 4,681 | |||||||||||||||||
| Transportation costs | 1,569 | 60 | 1,629 | |||||||||||||||||
| Other operating expenses | 1,308 | 201 | 1,509 | |||||||||||||||||
| Depreciation, depletion and amortization | 6,599 | 516 | 7,115 | |||||||||||||||||
| Taxes other than on income | 991 | 18 | 1,009 | |||||||||||||||||
| Exploration expenses | 137 | 111 | 248 | |||||||||||||||||
Pretax income before impairments and other charges | 3,191 | 1,501 | 4,692 | |||||||||||||||||
| Asset impairments and other charges | 6 | — | 6 | |||||||||||||||||
Pretax income | 3,185 | 1,501 | 4,686 | |||||||||||||||||
Income tax expense (a) | 746 | 614 | 1,360 | |||||||||||||||||
| Results of operations | $ | 2,439 | $ | 887 | $ | 3,326 | ||||||||||||||
| FOR THE YEAR ENDED DECEMBER 31, 2024 | ||||||||||||||||||||
| Revenues | $ | 17,974 | $ | 3,693 | $ | 21,667 | ||||||||||||||
| Lease operating costs | 3,680 | 1,058 | 4,738 | |||||||||||||||||
| Transportation costs | 1,522 | 61 | 1,583 | |||||||||||||||||
| Other operating expenses | 1,088 | 268 | 1,356 | |||||||||||||||||
| Depreciation, depletion and amortization | 6,049 | 516 | 6,565 | |||||||||||||||||
| Taxes other than on income | 1,004 | 22 | 1,026 | |||||||||||||||||
| Exploration expenses | 119 | 156 | 275 | |||||||||||||||||
| Pretax income before impairments and other charges | 4,512 | 1,612 | 6,124 | |||||||||||||||||
| Asset impairments and other charges | 334 | — | 334 | |||||||||||||||||
| Pretax income | 4,178 | 1,612 | 5,790 | |||||||||||||||||
Income tax expense (a) | 885 | 599 | 1,484 | |||||||||||||||||
| Results of operations | $ | 3,293 | $ | 1,013 | $ | 4,306 | ||||||||||||||
| FOR THE YEAR ENDED DECEMBER 31, 2023 | ||||||||||||||||||||
| Revenues | $ | 17,494 | $ | 3,766 | $ | 21,260 | ||||||||||||||
| Lease operating costs | 3,669 | 1,008 | 4,677 | |||||||||||||||||
| Transportation costs | 1,367 | 60 | 1,427 | |||||||||||||||||
| Other operating expenses | 1,058 | 194 | 1,252 | |||||||||||||||||
| Depreciation, depletion and amortization | 5,559 | 553 | 6,112 | |||||||||||||||||
| Taxes other than on income | 959 | 117 | 1,076 | |||||||||||||||||
| Exploration expenses | 323 | 118 | 441 | |||||||||||||||||
| Pretax income before impairments and other charges | 4,559 | 1,716 | 6,275 | |||||||||||||||||
| Asset impairments and other charges | 209 | — | 209 | |||||||||||||||||
| Pretax income | 4,350 | 1,716 | 6,066 | |||||||||||||||||
Income tax expense (a) | 933 | 746 | 1,679 | |||||||||||||||||
| Results of operations | $ | 3,417 | $ | 970 | $ | 4,387 | ||||||||||||||
(a)U.S. federal income taxes reflect certain expenses related to oil and gas activities allocated for U.S. income tax purposes. These amounts are computed using the statutory rate in effect during the period.
OXY 2025 FORM 10-K | 117 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS
$/Boe (a) | United States | International | Total | |||||||||||||||||
| FOR THE YEAR ENDED DECEMBER 31, 2025 | ||||||||||||||||||||
Revenues (b) | $ | 39.80 | $ | 40.33 | $ | 39.89 | ||||||||||||||
| Lease operating costs | 8.35 | 11.97 | 8.94 | |||||||||||||||||
| Transportation costs | 3.58 | 0.71 | 3.11 | |||||||||||||||||
| Other operating expenses | 2.98 | 2.37 | 2.88 | |||||||||||||||||
| Depreciation, depletion and amortization | 15.05 | 6.07 | 13.59 | |||||||||||||||||
| Taxes other than on income | 2.26 | 0.21 | 1.93 | |||||||||||||||||
| Exploration expenses | 0.31 | 1.31 | 0.47 | |||||||||||||||||
Pretax income before impairments and other charges | 7.27 | 17.69 | 8.97 | |||||||||||||||||
| Asset impairments and other charges | 0.01 | — | 0.01 | |||||||||||||||||
Pretax income | 7.26 | 17.69 | 8.96 | |||||||||||||||||
Income tax expense (c) | 1.70 | 7.24 | 2.60 | |||||||||||||||||
| Results of operations | $ | 5.56 | $ | 10.45 | $ | 6.36 | ||||||||||||||
| FOR THE YEAR ENDED DECEMBER 31, 2024 | ||||||||||||||||||||
Revenues (b) | $ | 44.68 | $ | 44.11 | $ | 44.59 | ||||||||||||||
| Lease operating costs | 9.15 | 12.64 | 9.75 | |||||||||||||||||
| Transportation costs | 3.78 | 0.73 | 3.26 | |||||||||||||||||
| Other operating expenses | 2.70 | 3.20 | 2.79 | |||||||||||||||||
| Depreciation, depletion and amortization | 15.04 | 6.16 | 13.51 | |||||||||||||||||
| Taxes other than on income | 2.50 | 0.26 | 2.11 | |||||||||||||||||
| Exploration expenses | 0.30 | 1.87 | 0.57 | |||||||||||||||||
Pretax income before impairments and other charges | 11.21 | 19.25 | 12.60 | |||||||||||||||||
| Asset impairments and other charges | 0.83 | — | 0.69 | |||||||||||||||||
Pretax income | 10.38 | 19.25 | 11.91 | |||||||||||||||||
Income tax expense (c) | 2.20 | 7.15 | 3.05 | |||||||||||||||||
| Results of operations | $ | 8.18 | $ | 12.10 | $ | 8.86 | ||||||||||||||
| FOR THE YEAR ENDED DECEMBER 31, 2023 | ||||||||||||||||||||
Revenues (b) | $ | 47.91 | $ | 46.49 | $ | 47.66 | ||||||||||||||
| Lease operating costs | 10.05 | 12.45 | 10.48 | |||||||||||||||||
| Transportation costs | 3.74 | 0.74 | 3.20 | |||||||||||||||||
| Other operating expenses | 2.90 | 2.39 | 2.81 | |||||||||||||||||
| Depreciation, depletion and amortization | 15.22 | 6.83 | 13.70 | |||||||||||||||||
| Taxes other than on income | 2.63 | 1.44 | 2.41 | |||||||||||||||||
| Exploration expenses | 0.88 | 1.47 | 0.99 | |||||||||||||||||
Pretax income before impairments and other charges | 12.49 | 21.17 | 14.07 | |||||||||||||||||
| Asset impairments and other charges | 0.57 | — | 0.47 | |||||||||||||||||
Pretax income | 11.92 | 21.17 | 13.60 | |||||||||||||||||
Income tax expense (c) | 2.56 | 9.21 | 3.76 | |||||||||||||||||
| Results of operations | $ | 9.36 | $ | 11.96 | $ | 9.84 | ||||||||||||||
(a)Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil.
(b)Revenues are net of royalty payments.
(c)U.S. federal income taxes reflect certain expenses related to oil and gas activities allocated for U.S. income tax purposes. These amounts are computed using the statutory rate in effect during the period.
118 | OXY 2025 FORM 10-K | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
STANDARDIZED MEASURE, INCLUDING YEAR-TO-YEAR CHANGES THEREIN, OF DISCOUNTED FUTURE NET CASH FLOWS
For purposes of the following disclosures, future cash flows were computed by applying to the Company’s proved oil and gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2025, 2024 and 2023, respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities to develop and produce proved reserves at year end.
Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10% discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions as of December 31, 2025, 2024 and 2023. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
| millions | United States | International | Total | |||||||||||||||||
| Balance as of December 31, 2025 | ||||||||||||||||||||
| Future cash inflows | $ | 143,509 | $ | 29,026 | $ | 172,535 | ||||||||||||||
| Future costs | ||||||||||||||||||||
| Production costs and other operating | (65,765) | (11,462) | (77,227) | |||||||||||||||||
Development costs (a) | (21,439) | (3,646) | (25,085) | |||||||||||||||||
| Future income tax expense | (6,922) | (3,301) | (10,223) | |||||||||||||||||
| Future net cash flows | 49,383 | 10,617 | 60,000 | |||||||||||||||||
| 10% discount factor | (19,485) | (3,888) | (23,373) | |||||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 29,898 | $ | 6,729 | $ | 36,627 | ||||||||||||||
| Balance as of December 31, 2024 | ||||||||||||||||||||
| Future cash inflows | $ | 159,735 | $ | 31,110 | $ | 190,845 | ||||||||||||||
| Future costs | ||||||||||||||||||||
| Production costs and other operating | (69,335) | (11,652) | (80,987) | |||||||||||||||||
Development costs (a) | (22,149) | (2,507) | (24,656) | |||||||||||||||||
| Future income tax expense | (9,034) | (3,339) | (12,373) | |||||||||||||||||
| Future net cash flows | 59,217 | 13,612 | 72,829 | |||||||||||||||||
| 10% discount factor | (24,480) | (5,478) | (29,958) | |||||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 34,737 | $ | 8,134 | $ | 42,871 | ||||||||||||||
| Balance as of December 31, 2023 | ||||||||||||||||||||
| Future cash inflows | $ | 143,471 | $ | 35,020 | $ | 178,491 | ||||||||||||||
| Future costs | ||||||||||||||||||||
| Production costs and other operating | (58,864) | (10,921) | (69,785) | |||||||||||||||||
Development costs (a) | (19,404) | (3,706) | (23,110) | |||||||||||||||||
| Future income tax expense | (10,441) | (4,895) | (15,336) | |||||||||||||||||
| Future net cash flows | 54,762 | 15,498 | 70,260 | |||||||||||||||||
| 10% discount factor | (23,715) | (6,243) | (29,958) | |||||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 31,047 | $ | 9,255 | $ | 40,302 | ||||||||||||||
(a)Included ARO costs.
OXY 2025 FORM 10-K | 119 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
| millions | 2025 | 2024 | 2023 | |||||||||||||||||
| Balance as of January 1 | $ | 42,871 | $ | 40,302 | $ | 58,152 | ||||||||||||||
| Sales and transfers of oil and gas produced, net of production costs and other operating expenses | (13,803) | (14,577) | (14,318) | |||||||||||||||||
| Net change in prices received per barrel, net of production costs and other operating expenses | (5,968) | (4,903) | (23,774) | |||||||||||||||||
| Extensions, discoveries and improved recovery, net of future production and development costs | 4,776 | 3,949 | 2,910 | |||||||||||||||||
| Change in estimated future development costs | (1,587) | (122) | (3,430) | |||||||||||||||||
| Revisions of quantity estimates | 1,821 | 3,574 | 6,313 | |||||||||||||||||
| Previously estimated development costs incurred during the period | 3,495 | 3,440 | 2,584 | |||||||||||||||||
| Accretion of discount | 3,849 | 4,052 | 6,152 | |||||||||||||||||
| Net change in income taxes | 2,581 | 1,581 | 5,575 | |||||||||||||||||
| Purchases and sales of reserves in place, net | (78) | 8,050 | 404 | |||||||||||||||||
| Changes in production rates and other | (1,330) | (2,475) | (266) | |||||||||||||||||
| Net change | (6,244) | 2,569 | (17,850) | |||||||||||||||||
| Balance as of December 31 | $ | 36,627 | $ | 42,871 | $ | 40,302 | ||||||||||||||
120 | OXY 2025 FORM 10-K | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
NET PRODUCTIVE AND DRY— EXPLORATORY AND DEVELOPMENT WELLS COMPLETED
The following table sets forth, for each year in the three-year period ended December 31, 2025, the Company’s net productive and dry exploratory and development wells completed:
| United States | International | Total | ||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Oil | ||||||||||||||||||||
| Exploratory | 17 | 4 | 21 | |||||||||||||||||
| Development | 452 | 44 | 496 | |||||||||||||||||
| Gas | ||||||||||||||||||||
| Exploratory | — | — | — | |||||||||||||||||
| Development | 36 | 1 | 37 | |||||||||||||||||
| Dry | ||||||||||||||||||||
| Exploratory | — | 5 | 5 | |||||||||||||||||
| Development | — | — | — | |||||||||||||||||
| 2024 | ||||||||||||||||||||
| Oil | ||||||||||||||||||||
| Exploratory | 29 | 5 | 34 | |||||||||||||||||
| Development | 355 | 34 | 389 | |||||||||||||||||
| Gas | ||||||||||||||||||||
| Exploratory | 1 | 2 | 3 | |||||||||||||||||
| Development | 26 | 4 | 30 | |||||||||||||||||
| Dry | ||||||||||||||||||||
| Exploratory | 1 | 7 | 8 | |||||||||||||||||
| Development | — | — | — | |||||||||||||||||
| 2023 | ||||||||||||||||||||
| Oil | ||||||||||||||||||||
| Exploratory | 25 | 13 | 38 | |||||||||||||||||
| Development | 420 | 63 | 483 | |||||||||||||||||
| Gas | ||||||||||||||||||||
| Exploratory | 1 | 1 | 2 | |||||||||||||||||
| Development | 38 | 3 | 41 | |||||||||||||||||
| Dry | ||||||||||||||||||||
| Exploratory | 5 | 8 | 13 | |||||||||||||||||
| Development | 7 | — | 7 | |||||||||||||||||
PRODUCTIVE OIL AND GAS WELLS
The following table sets forth, as of December 31, 2025, the Company’s productive oil and gas wells (both producing and capable of production):
| United States | International | Total | ||||||||||||||||||
Gross (a) | Net (b) | Gross (a) | Net (b) | Gross (a) | Net (b) | |||||||||||||||
| Oil | 19,019 | 16,288 | 3,021 | 1,412 | 22,040 | 17,700 | ||||||||||||||
| Gas | 2,989 | 2,428 | 166 | 101 | 3,155 | 2,529 | ||||||||||||||
| Multiple completion wells included above | 1,722 | 1,412 | — | — | 1,722 | 1,412 | ||||||||||||||
(a)The total number of wells in which interests are owned.
(b)The sum of fractional interests.
OXY 2025 FORM 10-K | 121 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
PARTICIPATION IN WELLS BEING DRILLED OR PENDING COMPLETION
The following table sets forth, as of December 31, 2025, the Company’s participation in exploratory and development wells being drilled:
| United States | International | Total | ||||||||||||||||||
| Exploratory and development wells being drilled | ||||||||||||||||||||
| Gross | 120 | 9 | 129 | |||||||||||||||||
| Net | 93 | 7 | 100 | |||||||||||||||||
Exploratory and development wells pending completion (a) | ||||||||||||||||||||
| Gross | 181 | 1 | 182 | |||||||||||||||||
| Net | 130 | 1 | 131 | |||||||||||||||||
(a)Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future. There were 100 MMboe of PUD reserves primarily assigned to U.S. onshore development wells suspended or waiting on completion as of December 31, 2025. The Company expects to convert all of these PUD reserves to developed status within five years of their initial disclosure.
As of December 31, 2025, the Company was participating in 104 and 39 gross pressure-maintenance projects in the United States and internationally, respectively. In the United States, these projects primarily consisted of waterfloods and CO2 floods, and in the Middle East and North Africa, these projects consisted mostly of waterfloods.
OIL AND GAS ACREAGE
The following table sets forth, as of December 31, 2025, the Company’s holdings of developed and undeveloped oil and gas acreage:
| thousands | United States | International | Total | |||||||||||||||||
Developed (a) | ||||||||||||||||||||
Gross (b) | 5,595 | 1,287 | 6,882 | |||||||||||||||||
Net (c) | 3,781 | 485 | 4,266 | |||||||||||||||||
Undeveloped (d) | ||||||||||||||||||||
Gross (b) | 1,169 | 8,358 | 9,527 | |||||||||||||||||
Net (c) | 725 | 7,291 | 8,016 | |||||||||||||||||
Fee Mineral Ownership (e) | ||||||||||||||||||||
Gross (b) | 7,713 | — | 7,713 | |||||||||||||||||
Net (c) | 4,373 | — | 4,373 | |||||||||||||||||
(a)Acres spaced or assigned to productive wells.
(b)Total acres in which interests are held.
(c)Sum of the fractional interests owned based on working interests, or interests under PSCs and other economic arrangements.
(d)Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether the acreage contains proved reserves.
(e)The Company’s fee mineral acreage is primarily undeveloped.
The Company’s investment in developed and undeveloped acreage comprises numerous concessions, blocks and leases. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before the contractual expiration date. In some instances, the Company may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Company has generally been successful in obtaining extensions. Scheduled lease and concession expirations for undeveloped acreage over the next three years are not expected to have a material adverse impact on the Company.
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| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
OIL, NGL AND NATURAL GAS SALES VOLUMES PER DAY
The following tables set forth the sales volumes from ongoing operations of oil, NGL and natural gas per day for each of the three years in the period ended December 31, 2025. The differences between the sales and production volumes per day are negligible and are generally due to the timing of shipments at the Company’s international locations where product is loaded onto tankers. Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil.
| Sales per Day (Mboe/d) | 2025 | 2024 | 2023 | |||||||||||||||||
| United States | ||||||||||||||||||||
| Permian | 786 | 664 | 584 | |||||||||||||||||
| Rockies & Other Domestic | 284 | 310 | 271 | |||||||||||||||||
| Gulf of America | 132 | 125 | 145 | |||||||||||||||||
| Total | 1,202 | 1,099 | 1,000 | |||||||||||||||||
| International | ||||||||||||||||||||
| Algeria and Other International | 31 | 33 | 35 | |||||||||||||||||
| Al Hosn Gas | 90 | 91 | 82 | |||||||||||||||||
| Dolphin | 40 | 39 | 39 | |||||||||||||||||
| Oman | 71 | 66 | 66 | |||||||||||||||||
| Total | 232 | 229 | 222 | |||||||||||||||||
| Total Sales per Day (Mboe/d) | 1,434 | 1,328 | 1,222 | |||||||||||||||||
OXY 2025 FORM 10-K | 123 | ||||
| table of contents | Supplemental Oil and Gas Information (Unaudited) | ||||||
| Sales per Day by Products | 2025 | 2024 | 2023 | |||||||||||||||||
| United States | ||||||||||||||||||||
Oil (Mbbl/d) | ||||||||||||||||||||
| Permian | 416 | 370 | 337 | |||||||||||||||||
| Rockies & Other Domestic | 92 | 96 | 77 | |||||||||||||||||
| Gulf of America | 112 | 105 | 120 | |||||||||||||||||
Total | 620 | 571 | 534 | |||||||||||||||||
NGL (Mbbl/d) | ||||||||||||||||||||
| Permian | 201 | 163 | 140 | |||||||||||||||||
| Rockies & Other Domestic | 78 | 106 | 97 | |||||||||||||||||
| Gulf of America | 9 | 9 | 11 | |||||||||||||||||
Total | 288 | 278 | 248 | |||||||||||||||||
Natural gas (MMcf/d) | ||||||||||||||||||||
| Permian | 1,011 | 783 | 644 | |||||||||||||||||
| Rockies & Other Domestic | 686 | 649 | 584 | |||||||||||||||||
| Gulf of America | 68 | 66 | 81 | |||||||||||||||||
Total | 1,765 | 1,498 | 1,309 | |||||||||||||||||
| International | ||||||||||||||||||||
Oil (Mbbl/d) | ||||||||||||||||||||
| Algeria and Other International | 25 | 27 | 29 | |||||||||||||||||
| Al Hosn Gas | 15 | 15 | 14 | |||||||||||||||||
| Dolphin | 6 | 6 | 6 | |||||||||||||||||
| Oman | 62 | 56 | 57 | |||||||||||||||||
| Total | 108 | 104 | 106 | |||||||||||||||||
NGL (Mbbl/d) | ||||||||||||||||||||
| Algeria and Other International | 2 | 3 | 3 | |||||||||||||||||
| Al Hosn Gas | 28 | 27 | 23 | |||||||||||||||||
| Dolphin | 8 | 8 | 8 | |||||||||||||||||
| Total | 38 | 38 | 34 | |||||||||||||||||
Natural gas (MMcf/d) | ||||||||||||||||||||
| Algeria and Other International | 17 | 18 | 15 | |||||||||||||||||
| Al Hosn Gas | 284 | 293 | 267 | |||||||||||||||||
| Dolphin | 155 | 150 | 150 | |||||||||||||||||
| Oman | 57 | 63 | 57 | |||||||||||||||||
| Total | 513 | 524 | 489 | |||||||||||||||||
| Total Sales per Day (Mboe/d) | 1,434 | 1,328 | 1,222 | |||||||||||||||||
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The Company had no changes in, and no disagreements with, the Company’s accountants on accounting and financial disclosure.
ITEM 9A. CONTROLS AND PROCEDURES
| MANAGEMENT’S ANNUAL ASSESSMENT OF AND REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING | ||
The management of Occidental Petroleum Corporation and its subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of Consolidated Financial Statements for external purposes in accordance with GAAP. The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and divestitures of the Company’s assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that the Company’s receipts and expenditures are being made only in accordance with authorizations of the Company’s management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management has assessed the effectiveness of the Company’s internal control system as of December 31, 2025, based on the criteria for effective internal control over financial reporting described in Internal Control - Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2025, the Company’s system of internal control over financial reporting is effective.
The Company’s independent auditors, KPMG LLP, have issued an audit report on the Company’s internal control over financial reporting.
| DISCLOSURE CONTROLS AND PROCEDURES | ||
The Company’s President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer supervised and participated in the Company’s evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, the Company’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2025.
ITEM 9B. OTHER INFORMATION
INSIDER TRADING ARRANGEMENTS
During the three months ended December 31, 2025, no director or Section 16 officer of the Company adopted terminated
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None.
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Part III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The Company’s Code of Business Conduct applies to the President and Chief Executive Officer, Senior Vice President and Chief Financial Officer, Vice President, Chief Accounting Officer and Controller and persons performing similar functions. The Code of Business Conduct also applies to the Company’s directors, employees and the employees of entities which it controls. The Code of Business Conduct is posted on the Company’s website, www.oxy.com. The Company will satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, any provision of the Code of Business Conduct by disclosing the nature of that amendment or waiver on its website within four business days following the date of the amendment or waiver.
The list of the Company’s executive officers and related information under Information About Our Executive Officers set forth in Part I of this 10-K is incorporated by reference herein. The information required by this Item 10 is incorporated herein by reference from the Company’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2025.
ITEM 11. EXECUTIVE COMPENSATION
The information under the caption “Compensation Discussion and Analysis - Compensation Committee Report” shall not be deemed to be “soliciting material,” or to be “filed” with the SEC, or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933. The information required by this Item 11 is incorporated herein by reference from the Company’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2025.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
| SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS | ||
All of the Company’s stock-based compensation plans for its employees and non-employee directors have been approved by the stockholders. The aggregate number of shares of Occidental common stock authorized for issuance under such plans is approximately 188 million, of which approximately 14.4 million had been reserved for issuance through December 31, 2025. The following is a summary of the securities available for issuance under such plans:
| a) | Number of securities to be issued upon exercise of outstanding options, warrants and rights | b) | Weighted-average exercise price of outstanding options, warrants and rights | c) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||||||||||||||
14,381,330(1) | 38.07(2) | 68,837,683(3) | |||||||||||||||||||||
(1)Includes shares reserved to be issued pursuant to RSUs, stock options and performance-based awards. Shares for performance-based awards are included assuming maximum payout, but may be paid out at lesser amounts, or not at all, according to achievement of performance goals.
(2)Price applies only to the Options included in column (a). Exercise price is not applicable to the other awards included in column (a), nor to warrants not issued under equity compensation plans.
(3)A plan provision requires each share covered by an award (other than stock appreciation rights and Options) to be counted as if three shares were issued in determining the number of shares that are available for future awards. Accordingly, the number of shares available for future awards may be less than the amount shown depending on the type of award granted. Additionally, under the plan, the amount shown may increase, depending on the award type, by the number of shares currently unvested or forfeitable, or three times that number as applicable, that are forfeited or canceled, or correspond to the portion of any stock-based awards settled in cash.
The information required by this Item 12 is incorporated herein by reference from the Company’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2025.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by this Item 13 is incorporated herein by reference from the Company’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2025.
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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The Company’s independent registered public accounting firm is KPMG LLP , Houston, TX , Auditor Firm ID: 185 .
The information about its principal accountant, KPMG LLP, Houston, Texas (185) required by this Item 14 is incorporated herein by reference from the Company’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2025.
Part IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about the Company or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other agreement parties and:
■Should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;
■Have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
■May apply standards of materiality in a way that is different from the way investors may view materiality; and
■Were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
(a) (1) and (2). Financial Statements and Financial Statement Schedule
Reference is made to Item 8 of the Table of Contents of the Form 10-K, where these documents are listed.
(a) (3). Exhibits
| 2.1 | Purchase and Sale Agreement, dated as of October 1, 2025, by and among Berkshire Hathaway Inc., Occidental Chemical Holding, LLC and, solely for the limited purposes therein, Environmental Resource Holdings, LLC (filed as Exhibit 2.1 to the Current Report on Form 8-K of Occidental filed on October 3, 2025, File No. 1-9210) | ||||
| 3.(i) | Restated Certificate of Incorporation of Occidental, dated November 12, 1999, and Certificates of Amendment thereto dated May 5, 2006, May 1, 2009, May 2, 2014 and June 3, 2020 (filed as Exhibit 4.1 to the Registration Statement on Form S-8 of Occidental filed on June 17, 2020, File No. 333-239236). | ||||
| 3.(i)(a) | Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental dated February 6, 2002, File No. 333-82246). | ||||
| 3.(ii) | Amended and Restated By-laws of Occidental Petroleum Corporation as of November 6, 2024 (filed as Exhibit 3.1 to the Current Report on Form 8-K of Occidental filed on November 12, 2024, File No. 1-9210). | ||||
| 3.(ii)(a) | Certificate of Designations with respect to the Cumulative Perpetual Preferred Stock, Series A (filed as Exhibit 3.1 to the Current Report on Form 8-K of Occidental filed on August 8, 2019, File No. 1-9210). | ||||
| 3.(ii)(b) | Certificate of Designations with respect to the Junior Participating Preferred Stock, Series B (filed as Exhibit 3.1 to the Current Report on Form 8-K of Occidental filed on March 13, 2020, File No. 1-9210). | ||||
| 4.1 | Description of Securities of Occidental Petroleum Corporation Registered under Section 12 of the Exchange Act (filed as Exhibit 4.1 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2020, File No. 1-9210). | ||||
| 4.2 | Indenture, dated as of August 8, 2019, between Occidental Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.1 to the Current Report on Form 8-K of Occidental filed on August 8, 2019, File No. 1-9210). | ||||
| 4.3 | First Supplemental Indenture to that certain Indenture, dated as of August 8, 2019, by and between Occidental Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.7 to the Current Report on Form 8-K of Occidental filed on July 13, 2020, File No. 1-9210). | ||||
| 4.4 | Second Supplemental Indenture to that certain Indenture, dated as of August 8, 2019, by and between Occidental Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.6 to the Current Report on Form 8-K of Occidental filed on December 22, 2020, File No. 1-9210). | ||||
| 4.5 | Third Supplemental Indenture to that certain Indenture, dated as of August 8, 2019, by and between Occidental Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.2 to the Current Report on Form 8-K of Occidental filed on July 15, 2021, File No. 1-9210). | ||||
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| Other instruments defining the rights of holders of other long-term debt of Occidental and its subsidiaries are not being filed since the total amount of securities authorized under each of such instruments does not exceed 10% of the total assets of Occidental and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of any such instrument to the Commission upon request. | |||||
| All of the exhibits numbered 10.1 to 10.25 are management contracts and compensatory plans required to be identified specifically as responsive to Item 601(b)(10)(iii)(A) of Regulation S-K pursuant to Item 15(b) of Form 10-K. | |||||
| 10.1 | Occidental Petroleum Corporation Savings Plan (Amended and Restated Effective as of January 1, 2026).* | ||||
| 10.2 | Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Restricted Stock Unit Incentive Award (filed as Exhibit 10.2 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2021, File No. 1-9210). | ||||
| 10.3 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Restricted Stock Unit Award (applicable to annual grants made in 2024) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2024, File No. 1-9210). | ||||
| 10.4 | Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective December 31, 2006 and Amended and Restated Effective January 1, 2021) (filed as Exhibit 10.2 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2020, File No. 1-9210). | ||||
| 10.5 | Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005 and Amended and Restated as of July 1, 2020) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2020, File No. 1-9210). | ||||
| 10.6 | Occidental Petroleum Corporation Executive Incentive Compensation Plan (As Amended and Restated Effective January 1, 2023) (filed as Exhibit 10.5 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2022, File No. 1-9210). | ||||
| 10.7 | Form of Indemnification Agreement between Occidental and each of its directors and certain executive officers (filed as Exhibit B to the Proxy Statement of Occidental for its May 21, 1987, Annual Meeting of Stockholders, File No. 1-9210). | ||||
| 10.8 | Form of Indemnification Agreement between Occidental and each of its directors and certain executive officers (filed as Exhibit 10.9 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2020, File No. 1-9210). | ||||
10.9 | Amended and Restated Occidental Petroleum Corporation 2015 Long-Term Incentive Plan (As Amended and Restated Effective as of May 2, 2025) (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2025, File No. 1-9210). | ||||
10.10 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Common Stock Award For Non-Employee Directors Grant Agreement (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2015, File No. 1-9210). | ||||
10.11 | Anadarko Retirement Restoration Plan (As Amended and Restated Effective as of December 31, 2021) (filed as Exhibit 10.14 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2021, File No. 1-9210). | ||||
10.12 | Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective July 1, 2020) (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2020, File No. 1-9210). | ||||
| 10.13 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Cash Return on Capital Employed Incentive Award (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2020, File No. 1-9210). | ||||
10.14 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Cash Return on Capital Employed Incentive Award (applicable to annual grants made in 2024) (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2024, File No. 1-9210). | ||||
10.15 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Stock Option Award (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2020, File No. 1-9210). | ||||
10.16 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Stock Appreciation Right Award (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2020, File No. 1-9210). | ||||
10.17 | Occidental Petroleum Corporation Executive Severance Plan (As Amended and Restated Effective November 6, 2024) (filed as Exhibit 10.17 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2024, File No. 1-9210). | ||||
| 10.18 | Occidental Petroleum Corporation Executive Change in Control Severance Plan (As Amended and Restated Effective February 12, 2025) (filed as Exhibit 10.18 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2024, File No. 1-9210). | ||||
| 10.19 | Form of Employee Notice, Impact of August 2020 Warrant Distribution on Long-Term Incentive Awards (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2020, File No. 1-9210). | ||||
10.20 | Letter Agreement by and between Occidental Petroleum Corporation and Sylvia J. Kerrigan dated September 14, 2022 (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2022). | ||||
| 10.21 | Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Restricted Stock Unit Incentive Award (for awards to Chief Legal Officer) (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2022). | ||||
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| 10.22 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Restricted Stock Unit Award (applicable to grant to Chief Legal Officer in 2024) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2024, File No. 1-9210). | ||||
| 10.23 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Total Shareholder Return Incentive Award (applicable to annual grants made in 2022 and 2023) (filed as Exhibit 10.26 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2022, File No. 1-9210). | ||||
| 10.24 | Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Total Shareholder Return Incentive Award (applicable to annual grants made in 2024) (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2024, File No. 1-9210). | ||||
| 10.25 | Occidental Petroleum Corporation Retirement Policy (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental filed on February 22, 2023, File No. 1-9210). | ||||
| 10.26 | Warrant Agreement (including Form of Warrant), dated July 24, 2020, between the Company and Equiniti Trust Company, as Warrant Agent (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental filed on July 27, 2020, File No. 1-9210). | ||||
| 10.27 | Third Amended and Restated Credit Agreement, dated as of February 2, 2024, by and among Occidental Petroleum Corporation, the banks party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental filed on February 5, 2024, File No. 1-9210). | ||||
| 10.28 | Amendment No. 1, dated as of May 16, 2024, to the Third Amended and Restated Credit Agreement, dated as of February 2, 2024, by and among Occidental Petroleum Corporation, the banks party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2024, File No. 1-9210). | ||||
| 10.29 | First Amendment to Warrant Agreement, dated as of March 3, 2025, by and between the Company and Equiniti Trust Company, LLC (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental filed on March 3, 2025, File No. 1-9210). | ||||
| 19.1 | |||||
| 21 | List of subsidiaries of Occidental as of December 31, 2025. | ||||
| 23.1 | Consent of Independent Registered Public Accounting Firm. | ||||
| 23.2 | Consent of Ryder Scott, Independent Petroleum Engineers. | ||||
| 31.1 | Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||
| 31.2 | Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||
| 32.1 | Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||
97.1 | Occidental Petroleum Corporation Clawback Policy (filed as Exhibit 97.1 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2023, File No. 1-9210). | ||||
| 99.1 | Ryder Scott Company Process Review of the Estimated Future Proved Reserves and Income Attributable to Certain Leasehold and Royalty Interests and Certain Economic Interests Derived Through Production Sharing Contracts as of December 31, 2025. | ||||
| 101.INS | Inline XBRL Instance Document. | ||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. | ||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | ||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document. | ||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | ||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. | ||||
| 104 | Cover Page Interactive Data File - The cover page from Occidental Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2025 is formatted in Inline XBRL (included as Exhibit 101). | ||||
| * | Appendices have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant agrees to furnish supplementally to the SEC a copy of any omitted appendix upon request by the SEC. | ||||
ITEM 16. FORM 10-K SUMMARY
None.
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| SIGNATURES | ||
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| OCCIDENTAL PETROLEUM CORPORATION | ||||||||
| By: | /s/ Vicki Hollub | |||||||
| Vicki Hollub | ||||||||
| President and Chief Executive Officer | ||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Title | Date | |||||||||||||
| /s/ Vicki Hollub | President, Chief Executive Officer | February 18, 2026 | ||||||||||||
| Vicki Hollub | and Director | |||||||||||||
| /s/ Sunil Mathew | Senior Vice President and | February 18, 2026 | ||||||||||||
| Sunil Mathew | Chief Financial Officer | |||||||||||||
| /s/ Christopher O. Champion | Vice President, Chief Accounting Officer | February 18, 2026 | ||||||||||||
| Christopher O. Champion | and Controller | |||||||||||||
| /s/ Vicky A. Bailey | Director | February 18, 2026 | ||||||||||||
| Vicky A. Bailey | ||||||||||||||
| /s/ Andrew F. Gould | Director | February 18, 2026 | ||||||||||||
| Andrew F. Gould | ||||||||||||||
| /s/ Carlos M. Gutierrez | Director | February 18, 2026 | ||||||||||||
| Carlos M. Gutierrez | ||||||||||||||
| /s/ William R. Klesse | Director | February 18, 2026 | ||||||||||||
| William R. Klesse | ||||||||||||||
| /s/ Jack B. Moore | Director | February 18, 2026 | ||||||||||||
| Jack B. Moore | ||||||||||||||
| /s/ Claire O’Neill | Director | February 18, 2026 | ||||||||||||
| Claire O’Neill | ||||||||||||||
| /s/ Avedick B. Poladian | Director | February 18, 2026 | ||||||||||||
| Avedick B. Poladian | ||||||||||||||
/s/ Kenneth B. Robinson | Director | February 18, 2026 | ||||||||||||
Kenneth B. Robinson | ||||||||||||||
| /s/ Robert M. Shearer | Director | February 18, 2026 | ||||||||||||
| Robert M. Shearer | ||||||||||||||
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FAQ
What was the key strategic move disclosed in Occidental (OXY)’s latest 10-K?
Occidental’s key move was selling its OxyChem business to Berkshire Hathaway for
How is Occidental (OXY) using proceeds from the OxyChem sale?
Occidental is primarily using OxyChem sale proceeds to reduce debt. It repaid about
What capital spending did Occidental (OXY) report for 2025?
In 2025, Occidental invested
What dividends and shareholder returns did Occidental (OXY) provide in 2025?
Occidental declared
What are Occidental (OXY)’s main climate and carbon management initiatives?
Occidental targets net‑zero operational emissions before 2040 and net‑zero total emissions, including product use, before 2050. It is developing carbon management projects like the STRATOS direct air capture facility, designed to capture up to 500,000 tons of CO2 annually once fully complete.
How did oil price trends in 2025 affect Occidental (OXY)?
Occidental’s results were influenced by lower oil prices in 2025. Average WTI fell to
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OXY Latest News
Feb 18, 2026
Occidental Announces Fourth Quarter 2025 Results
Jan 2, 2026
Occidental Completes Sale of OxyChem
Nov 10, 2025
Occidental Announces Third Quarter 2025 Results
Nov 5, 2025
Occidental Announces Dividend