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	December 31, 2025		For the transition period from                to

Commission File Number 1-9210

Occidental Petroleum Corporation

(Exact name of registrant as specified in its charter)

State or other jurisdiction of incorporation or organization	Delaware
I.R.S. Employer Identification No.	95-4035997
Address of principal executive offices	5 Greenway Plaza, Suite 110		Houston,	Texas
Zip Code	77046
Registrant’s telephone number, including area code	(713)	215-7000

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, $0.20 par value	OXY	New York Stock Exchange
Warrants to Purchase Common Stock, $0.20 par value	OXY WS	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No  ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes ☑   No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).     Yes ☑   No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	☑	Accelerated Filer	☐	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
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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

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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.

4	OXY 2025 FORM 10-K
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
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OIL AND GAS OPERATIONS
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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
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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
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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 Note9- Income Taxes and Note12- 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 Note9- 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 Note11– Environmental Liabilities and Expenditures and Note12- 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 Note11– Environmental Liabilities and Expenditures and Note12- 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 Note4- 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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ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

ITEM 1C.    CYBERSECURITY

RISK MANAGEMENT AND STRATEGY

The Company has implemented and maintains processes for assessing, identifying and managing material risks from potential unauthorized occurrences on or through its information technology (IT) and industrial control systems (ICS) networks that may result in material adverse effects on the confidentiality, integrity and availability of the Company’s systems and the information residing in those systems. These include a wide variety of mechanisms, controls, technologies, methods, systems, written policies, physical safeguards and other processes designed to prevent or mitigate data loss, theft, misuse or other security incidents or vulnerabilities affecting the Company’s systems and the data it collects, processes, stores and transmits as part of its businesses.

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’s cybersecurity strategy is intended to mitigate cybersecurity threats identified in the risk management process and provide a framework for the Company to have appropriate administrative, technical and physical safeguards to protect its systems and data and respond effectively to cybersecurity threats. The Company’s cybersecurity program aligns with the National Institute of Standards and Technology framework and leverages people, processes and technology to identify and respond to cybersecurity threats in a timely manner. The Company relies on continuous security monitoring, penetration testing, vulnerability scanning, personnel training and other tools to identify and mitigate potential cybersecurity threats. The Company also has established cybersecurity policies that address its cybersecurity practices and controls. The Company has invested in broad cybersecurity awareness and mandatory training to educate those with access to company networks on the Company’s cybersecurity policies and best practices. The Company conducts regular phishing tests to educate, train and assess the workforce’s ability to identify malicious emails. The Company also conducts internal security audits and other readiness tests, including audits conducted by third parties and tabletop exercises, to assess and improve preparedness and promote communication and monitoring across the organization. In addition to its administrative and technical safeguards, the Company has implemented physical safeguards intended to mitigate risks to its systems. Using a standardized written evaluation and other investigative processes, the Company identifies and assesses cybersecurity risks flowing from its vendors and suppliers, and manages these using a risk-based approach.

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.

The Company’s business strategy, results of operations and financial condition have not been materially affected by risks from cybersecurity threats, including as a result of previously identified cybersecurity incidents, but the Company cannot provide assurance that it will not be materially affected in the future by such risks or any future material incidents. For more information on the Company’s cybersecurity-related risks, see Risk Factors under Part I, Item 1A of this Form 10-K.

GOVERNANCE

BOARD

The Audit Committee of the Board oversees the Company’s IT security programs, including cybersecurity, which includes review of possible external threats and potential mitigations. The Board also reviews the Company’s cybersecurity program at least annually. In this review, the CIO briefs the full Board on cybersecurity and data protection matters, including analysis and review of the measures implemented by the Company to identify and mitigate cybersecurity risks. The Company also has protocols by which material cybersecurity incidents are to be reported to the Audit Committee and/or the 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

| 16 | OXY 2025 FORM 10-K | | --- | --- || table of contents | OTHER INFORMATION | | --- | --- |

prevention, detection, mitigation and remediation of cybersecurity incidents through reports from the Company’s cybersecurity leaders, each of whom is supported by a team of trained cybersecurity professionals. In addition to the Company’s extensive in-house cybersecurity capabilities, the Company also engages assessors, consultants, auditors or other third parties when necessary to assist with assessing, identifying and managing cybersecurity risks.

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.

OXY 2025 FORM 10-K	17
table of contents	OTHER INFORMATION
---	---		INFORMATION ABOUT EXECUTIVE OFFICERS
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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<br><br>Current Title	Age as of February 18, 2026	Positions with the Company and Employment History
Christopher O. Champion<br><br>Vice President,<br><br>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<br><br>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<br><br>President and Chief Executive Officer	66	President, Chief Executive Officer and Director since April 2016.
Richard A. Jackson<br><br>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<br><br>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<br><br>Senior Vice President and<br><br>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<br><br>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<br><br>Senior Vice President and<br><br>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.
18	OXY 2025 FORM 10-K
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table of contents	MARKET FOR REGISTRANT’S COMMON EQUITY
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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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table of contents	MARKET FOR REGISTRANT’S COMMON EQUITY
---	---		PERFORMANCE GRAPH
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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 andItems 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
GlobalInvestments	46
Critical Accounting Policies and Estimates	47
Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data	51		OXY 2025 FORM 10-K	21
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CURRENT BUSINESS OUTLOOK AND STRATEGY
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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 Note5- 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	%		24	OXY 2025 FORM 10-K
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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<br>2. DJ Basin<br>3. Permian Basin<br>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<br><br><br><br>2.Oman<br><br><br><br>3.Qatar<br><br><br><br>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
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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 ofSignificant 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 IncomeTaxes below.

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SEGMENT RESULTS OF OPERATIONS AND ITEMS AFFECTING COMPARABILITY
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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:

		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

All values are in US Dollars.

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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 andContingencies 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 Note4- 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 Note4- 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
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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
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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 <br>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 Note4- 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
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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
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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). SeeNote9- 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
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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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table of contents	QUANTITATIVE AND QUALITATIVE DISCLOSURES
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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)<br><br>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.

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INTEREST RATE RISK
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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<br>Fixed-Rate Debt			U.S. Dollar<br>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 Note5 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.

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table of contents	FINANCIAL STATEMENTS<br><br>INDEX
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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
Note4- Acquisitions, Divestitures and Other Transactions	77
Note5- Long-term Debt	82
Note6- Lease Commitments	85
Note7- Derivatives	86
Note8- Fair Value Measurements	87
Note9- 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<br><br>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<br><br>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<br><br>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<br>and Subsidiaries
---	---
	December 31,
---	---	---	---	---
millions	2025		2024
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,968	$	2,125
Trade receivables	2,575		2,839
Joint interest receivables	684		720
Inventories	1,823		1,756
Assets held for sale	1,176		1,140
Other current assets	601		490
Total current assets	8,827		9,070
PROPERTY, PLANT AND EQUIPMENT
Oil and gas	126,896		121,874
Midstream and marketing	9,638		8,593
Corporate	1,219		1,163
	137,753		131,630
Accumulated depreciation, depletion and amortization	(74,110)		(65,767)
Total property, plant and equipment, net	63,643		65,863
NON-CURRENT ASSETS
Operating lease assets	908		755
Investments in unconsolidated entities	2,475		2,646
Non-current assets held for sale	5,344		4,430
Other long-term assets	2,989		2,681
Total non-current assets	11,716		10,512
TOTAL ASSETS	$	84,186	$	85,445

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<br>and Subsidiaries
---	---			December 31,
---	---	---	---	---
millions except share and per-share amounts	2025		2024
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt	$	1,773	$	1,138
Accounts payable	3,285		3,472
Accrued liabilities	3,592		4,248
Liabilities held for sale	778		663
Total current liabilities	9,428		9,521
LONG-TERM DEBT, NET	20,623		24,979
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes, net	5,636		5,394
Asset retirement obligations	4,172		3,923
Non-current liabilities held for sale	418		333
Other deferred credits and liabilities	7,311		6,815
Total deferred credits and other liabilities	17,537		16,465
EQUITY
Preferred stock, at $1.00 per share par value, issued shares: 2025 — 84,897 and 2024 — 84,897	8,287		8,287
Common stock, $0.20 per share par value, authorized shares: 1.5 billion, issued shares: 2025 — 1,214,337,600 and 2024 — 1,166,769,167	243		233
Treasury stock: 2025 — 228,311,184 shares and 2024 — 228,311,184 shares	(15,597)		(15,597)
Additional paid-in capital	21,008		19,868
Retained earnings	21,891		21,189
Accumulated other comprehensive income	202		179
Total stockholders’ equity	36,034		34,159
Noncontrolling interest	564		321
Total equity	36,598		34,480
TOTAL LIABILITIES AND EQUITY	$	84,186	$	85,445

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<br>and Subsidiaries
---	---			Years Ended December 31,
---	---	---	---	---	---	---
millions except per-share amounts	2025		2024		2023
REVENUES AND OTHER INCOME
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
Total	22,075		22,195		23,831
COSTS AND OTHER DEDUCTIONS
Oil and gas lease 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 expense	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
Total	19,023		18,930		19,595
Income before income taxes and other items	3,052		3,265		4,236
OTHER ITEMS
Income from equity investments and other	76		759		426
Total	76		759		426
Income from continuing operations before income taxes	3,128		4,024		4,662
Income tax expense	(1,021)		(1,158)		(1,330)
Income from continuing operations	2,107		2,866		3,332
Income from discontinued operations, net of tax	262		212		1,364
NET INCOME	2,369		3,078		4,696
Less: Net income attributable to noncontrolling interest	(43)		(22)		—
Less: Preferred stock dividends and redemption premiums	(679)		(679)		(923)
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	1,647	$	2,377	$	3,773
PER COMMON SHARE
Income from continuing operations—basic	$	1.38	$	2.36	$	2.69
Discontinued operations—basic	0.27		0.23		1.53
Net income attributable to common stockholders—basic	$	1.65	$	2.59	$	4.22
Income from continuing operations—diluted	$	1.35	$	2.23	$	2.49
Discontinued operations—diluted	0.26		0.21		1.41
Net income attributable to common stockholders—diluted	$	1.61	$	2.44	$	3.90

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<br><br>Income	Occidental Petroleum Corporation<br>and Subsidiaries
---	---			Years Ended December 31,
---	---	---	---	---	---	---
millions	2025		2024		2023
Net income	$	2,369	$	3,078	$	4,696
Other comprehensive income (loss) items:
Gains (losses) on derivatives	(15)		(5)		44
Pension and postretirement gains (losses)	38		(89)		34
Other	—		(2)		2
Other comprehensive income (loss), net of tax	23		(96)		80
Comprehensive income	2,392		2,982		4,776
Less: Comprehensive income attributable to noncontrolling interest	(43)		(22)		—
Comprehensive income attributable to preferred and common stockholders	$	2,349	$	2,960	$	4,776

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<br>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	$	9,762	$	220	$	(13,772)	$	17,181	$	16,499	$	195	$	—	$	30,085
Net income	—		—		—		—		4,696		—		—		4,696
Other comprehensive income, net of tax	—		—		—		—		—		80		—		80
Dividends on common stock, $0.72 per share	—		—		—		—		(646)		—		—		(646)
Dividends on preferred stock, $8,000 per share	—		—		—		—		(736)		—		—		(736)
Preferred stock redemption – face value	(1,511)		—		—		—		—		—		—		(1,511)
Preferred stock redemption – premium	—		—		—		—		(151)		—		—		(151)
Preferred stock redemption – amortization of carrying value	36		—		—		—		(36)		—		—		—
Shareholder warrants exercised	—		1		—		98		—		—		—		99
Options exercised	—		—		—		13		—		—		—		13
Issuance of common stock and other, net	—		1		—		130		—		—		—		131
Purchases of treasury stock	—		—		(1,810)		—		—		—		—		(1,810)
Noncontrolling interest contributions, net	—		—		—		—		—		—		99		99
Balance, December 31, 2023	$	8,287	$	222	$	(15,582)	$	17,422	$	19,626	$	275	$	99	$	30,349
Net income	—		—		—		—		3,056		—		22		3,078
Other comprehensive income, net of tax	—		—		—		—		—		(96)		—		(96)
Dividends on common stock, $0.88 per share	—		—		—		—		(814)		—		—		(814)
Dividends on preferred stock, $8,000 per share	—		—		—		—		(679)		—		—		(679)
Shareholder warrants exercised	—		5		—		554		—		—		—		559
Issuance of common stock and other, net	—		—		—		143		—		—		—		143
Purchases of treasury stock	—		—		(15)		—		—		—		—		(15)
Common stock issued for CrownRock acquisition	—		6		—		1,749		—		—		—		1,755
Noncontrolling interest contributions, net	—		—		—		—		—		—		200		200
Balance, December 31, 2024	$	8,287	$	233	$	(15,597)	$	19,868	$	21,189	$	179	$	321	$	34,480
Net income	—		—		—		—		2,326		—		43		2,369
Other comprehensive loss, net of tax	—		—		—		—		—		23		—		23
Dividends on common stock, $0.96 per share	—		—		—		—		(945)		—		—		(945)
Dividends on preferred stock, $8,000 per share	—		—		—		—		(679)		—		—		(679)
Shareholder warrants exercised	—		9		—		921		—		—		—		930
Issuance of common stock and <br>other, net of cancellations	—		1		—		219		—		—		—		220
Noncontrolling interest contributions, net	—		—		—		—		—		—		200		200
Balance, December 31, 2025	$	8,287	$	243	$	(15,597)	$	21,008	$	21,891	$	202	$	564	$	36,598

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<br>and Subsidiaries
---	---			Years Ended December 31,
---	---	---	---	---	---	---
millions	2025		2024		2023
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	2,369	$	3,078	$	4,696
Adjustments to reconcile net income to net cash from operating activities:
Discontinued operations, net	(262)		(212)		(1,364)
Depreciation, depletion and amortization of assets	7,533		6,951		6,449
Deferred income tax provision (benefit)	127		(265)		54
Other noncash charges to income	420		454		133
Asset impairments	21		355		209
Losses (gains) on sales of assets and other, net	(263)		60		(522)
Undistributed losses (earnings) from equity investments	619		(83)		141
Dry hole expense	109		106		299
Changes in operating assets and liabilities:
(Increase) decrease in trade receivables	252		(116)		931
(Increase) decrease in inventories	12		(27)		(84)
(Increase) decrease in joint interest receivables and other current assets	(62)		286		(350)
Decrease in accounts payable and accrued liabilities	(964)		(540)		(423)
Increase (decrease) in current domestic and foreign income taxes	(305)		472		66
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
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures	(6,427)		(6,263)		(5,696)
Change in capital accrual	32		100		(22)
Purchases of assets, businesses and equity investments, net	(280)		(9,117)		(713)
Proceeds from sale of assets and equity investments, net	2,278		1,673		447
Equity investments and other, 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)
CASH FLOW FROM FINANCING ACTIVITIES
Draws on receivables securitization facility	—		—		283
Payment of receivables securitization facility	—		—		(283)
Proceeds from long-term debt, net	—		9,612		(46)
Payments of long-term debt, net	(3,754)		(4,514)		(22)
Redemption of preferred stock	—		—		(1,661)
Purchases of treasury stock	—		(27)		(1,798)
Cash dividends paid on common and preferred stock	(1,594)		(1,446)		(1,365)
Proceeds from issuance of common stock	966		584		135
Contributions from noncontrolling interest	200		200		100
Deferred payments for purchases of assets and businesses	(417)		(318)		—
Other financing, net	(236)		(242)		(229)
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)
Increase (decrease) in cash, cash equivalents, restricted cash and restricted cash equivalents	(111)		693		438
Cash, cash equivalents, restricted cash and restricted cash equivalents — beginning of year	2,157		1,464		1,026
Cash, cash equivalents, restricted cash and restricted cash equivalents — end of year	$	2,046	$	2,157	$	1,464

The accompanying notes are an integral part of these Consolidated Financial Statements.

OXY 2025 FORM 10-K	63
table of contents	FINANCIAL STATEMENTS
---	---
Consolidated Statements of Cash Flows	Occidental Petroleum Corporation<br>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	$	2,150	$	1,451	$	1,006
Discontinued operations - beginning of year (a)	7		13		20
Less: discontinued operations - end of year (a)	41		7		13
Continuing operations - end of year	2,005		2,150		1,451

(a) Reported as assets held for sale on our consolidated balance sheets.

The accompanying notes are an integral part of these Consolidated Financial Statements.

64	OXY 2025 FORM 10-K
table of contents	FINANCIAL STATEMENTS<br><br>FOOTNOTES
---	---		Notes to Consolidated Financial Statements	Occidental Petroleum Corporation<br>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

The Company’s percentage interest in the underlying net assets of affiliates for which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which the Company holds an undivided interest) are accounted for under the equity method. The Company reviews equity-method investments for impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in value may have occurred. The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows. The Company evaluates the facts and circumstances of any distributions in excess of its carrying amount in the investment to determine the appropriate accounting, including the source of the proceeds and any implicit or explicit commitments to fund the affiliate. If there is no implicit or explicit commitment, the distribution is treated as a gain. If an implicit or explicit commitment exists to possibly fund the affiliate at a future date, the distribution is recorded against the equity-method investment. See Note3-Investments and Related-Party Transactions for further discussion regarding 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 Note3- 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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to the NCI in the Consolidated Statements of Operations reflect changes in the amounts the NCI would hypothetically receive at each balance sheet date if the joint venture was liquidated. As of December 31, 2025, the VIE’s assets were comprised of $1.2 billion construction in progress. Noncontrolling interest as of December 31, 2025 was $564 million.

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 Note4- 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.

Because the Company’s major products are commodities, significant changes in the prices of oil, NGL and natural gas products may have a significant impact on the Company’s results of operations. Also, see the Property, Plant and Equipment section below.

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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Other current assets includes prepaid expenses, derivative assets and taxes receivable. Joint interest receivables represent amounts due for capital and operating costs from third-party non-operating partners.

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	$	1,222	$	1,219
Commodity inventory	601		537
Total	$	1,823	$	1,756

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	$	262	$	405	$	276
Additions to capitalized exploratory well costs pending the determination of proved reserves	409		556		750
Reclassifications to property, plant and equipment based on the determination of proved reserves	(205)		(594)		(314)
Capitalized exploratory well costs charged to expense	(100)		(105)		(307)
Balance — end of year	$	366	$	262	$	405

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 Note8- 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	$	620	$	590
Taxes other than on income	498		436
Accrued interest payable	386		446
Dividends payable	383		354
Asset retirement obligations	381		388
Operating lease liabilities	350		334
Income tax payable	159		471
Carbon Engineering acquisition payable	—		393
Other	815		836
Accrued liabilities - current	$	3,592	$	4,248

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)	2,393		2,204
Environmental remediation liabilities (b)	1,719		1,759
Pension and postretirement obligations	985		1,022
Operating lease liabilities	605		469
Other	1,609		1,361
Accrued liabilities - non-current	$	7,311	$	6,815

(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	$	4,311	$	3,964
Liabilities incurred – capitalized to PP&E	138		287
Liabilities settled and paid	(536)		(444)
Accretion expense	212		228
Acquisitions, divestitures and other, net	(24)		2
Revisions to previous estimates	452		274
Ending balance	$	4,553	$	4,311

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Fair value gains or losses are recognized in earnings in the current period. Gains and losses from derivative instruments are reported net in the Consolidated Statements of Operations. See Note7- Derivatives for additional information. There were no fair value hedges as of and during the years ended December 31, 2025, 2024 and 2023.

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	$	1,079	$	1,260	$	1,120
Interest paid (a)	$	1,250	$	1,052	$	1,017

(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	$	1,968	$	2,125
Cash and cash equivalents included in assets held for sale	41		7
Restricted cash and restricted cash equivalents	20		11
Restricted cash and restricted cash equivalents included in long-term receivables and other assets, net	17		14
Cash, cash equivalents, restricted cash and restricted cash equivalents	$	2,046	$	2,157

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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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 Note9- Income Taxes for more information.

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.

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. In Note 11- Environmental Liabilities and Expenditures, the Company has disclosed its reserve balances for environmental remediation matters that satisfy this criteria. See also Note 12- Lawsuits, Claims, Commitments and Contingencies.

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	$	2,551	$	2,452	$	2,339
Charged to costs and expenses	95		105		275
Charged to other accounts	208		131		24
Payments	(81)		(137)		(186)
Balance - end of year (a)	$	2,773	$	2,551	$	2,452

(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<br><br>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	$	21,569	$	22,710	$	23,230
All other revenues	24		(691)		(74)
Net sales	$	21,593	$	22,019	$	23,156
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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	$	14,459	$	2,715	$	—	$	17,174
NGL	1,897		352		—		2,249
Gas	1,017		352		—		1,369
Other	105		5		—		110
Segment total	$	17,478	$	3,424	$	—	$	20,902
Midstream and marketing	$	546	$	709	$	—	$	1,255
Eliminations	$	—	$	—	$	(588)	$	(588)
Consolidated	$	18,024	$	4,133	$	(588)	$	21,569
Year ended December 31, 2024
Oil and gas
Oil	$	15,604	$	2,940	$	—	$	18,544
NGL	1,865		390		—		2,255
Gas	514		361		—		875
Other	29		2		—		31
Segment total	$	18,012	$	3,693	$	—	$	21,705
Midstream and marketing	$	1,164	$	413	$	—	$	1,577
Eliminations	$	—	$	—	$	(572)	$	(572)
Consolidated	$	19,176	$	4,106	$	(572)	$	22,710
Year ended December 31, 2023
Oil and gas
Oil	$	14,893	$	3,057	$	—	$	17,950
NGL	1,619		372		—		1,991
Gas	970		335		—		1,305
Other	36		2		—		38
Segment total	$	17,518	$	3,766	$	—	$	21,284
Midstream and marketing	$	2,098	$	409	$	—	$	2,507
Eliminations	$	—	$	—	$	(561)	$	(561)
Consolidated	$	19,616	$	4,175	$	(561)	$	23,230
OXY 2025 FORM 10-K	75
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INVESTMENTS IN UNCONSOLIDATED ENTITIES

The following table represents significant investments in unconsolidated entities as of December 31, 2025:

millions	% Economic Interest			Carrying amount
WES		43.1	%	$	2,032
NET Power		40.3	%	—
DEL(a)		24.5	%	—
Other		various		443
Total Investments in unconsolidated entities				$	2,475

(a)    Not presented in investments in unconsolidated entities is the Company’s 24.5% ownership in DEL, which had a carrying value of $220 million and is presented in deferred credits and other liabilities - other.

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	$	664	$	764
Investments in excess of equity
Investment in excess of equity allocated to PP&E and equity investments	$	279	$	316
Investment in excess of equity allocated to intangibles and other assets	$	93	$	105
Total investments in excess of equity	$	372	$	421

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	$	4,794	$	4,580	$	4,086
Costs and expenses	5,136		3,025		3,219
Net income	$	(342)	$	1,555	$	867
Summarized Balance Sheet
Current assets	$	4,086	$	4,643	$	4,493
Non-current assets	$	17,599	$	17,132	$	17,634
Current liabilities	$	2,279	$	2,183	$	2,462
Long-term debt	$	9,787	$	9,296	$	9,673
Other non-current liabilities	$	2,624	$	2,328	$	2,292
Equity	$	6,995	$	7,968	$	7,700
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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, Divestituresand 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)	$	128	$	146	$	153
Purchases (b)	$	4	$	28	$	159
Services (c)	$	1,505	$	1,415	$	1,156
Advances and amounts due from related parties	$	30	$	36	$	49
Amounts due to related parties	$	333	$	342	$	331

(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<br><br>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	$	9,100
Closing Adjustments
Net Working Capital and Other Purchase Price Adjustments	273
Pre-closing dividends declared by the Company	13
Total Cash Purchase Price	$	9,386
Total shares of Occidental common stock issued	29.6
Occidental common stock share price	$	59.38
Stock portion of purchase price	$	1,755
Total purchase price	$	11,141

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	$	589
Trade receivables, net	198
Other current assets	39
Property, plant and equipment, oil and gas	11,837
Amount attributable to assets acquired	$	12,663
Fair value of liabilities acquired:
Current maturities of long-term debt	$	868
Accounts payable	207
Accrued liabilities	22
Long-term debt	378
Asset retirement obligations	47
Amount attributable to liabilities acquired	$	1,522
Fair value of net assets acquired:	$	11,141

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<br><br>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	$	23,478	$	25,676
Net income attributable to common stockholders	$	2,713	$	4,197
Net income attributable to common stockholders per share—basic	$	2.90	$	4.54
Net income attributable to common stockholders per share—diluted	$	2.74	$	4.21

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 Note3- 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 Note3- 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 Note5 Long-Term Debtfor 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.

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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	$	4,368	$	4,706	$	5,101
Interest, dividends and other income	—		(21)		(14)
Gains on sales of assets and others, net	3		239		—
Total revenues and other income	4,371		4,924		5,087
Costs and other deductions
Chemical cost of sales	3,099		3,027		3,009
Selling, general and administrative expense	119		102		96
Other operating and non-operating expense	383		262		(81)
Depreciation, depletion and amortization	342		420		416
Asset impairments and other charges	—		925		—
Acquisition-related costs	22		—		—
Other expense, net	16		6		(12)
Total costs and other deductions	3,981		4,742		3,428
Income before income taxes and other items	390		182		1,659
Income from equity investments and other	105		103		108
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

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	$	41	$	7
Trade receivables, net	640		687
Inventories	383		339
Other current assets	112		107
Total current assets held for sale	1,176		1,140
Investments in unconsolidated entities	475		513
Property, plant and equipment, net	4,442		3,515
Operating lease assets	207		182
Other long-term assets	220		220
Total non-current assets held for sale	5,344		4,430
Total assets held for sale	$	6,520	$	5,570
Liabilities
Current maturities of long-term debt	$	6	$	—
Accounts payable	410		281
Accrued liabilities	362		382
Total current liabilities held for sale	778		663
Long-term debt, net	41		(1)
Asset retirement obligations	126		119
Other deferred credits and liabilities	251		215
Total non-current liabilities held for sale	418		333
Total liabilities held for sale	$	1,196	$	996
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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	$	1,711	$	798	$	828
Charged to costs and expenses	375		1,007		52
Charged to other accounts	53		11		26
Payments	(176)		(105)		(108)
Balance - end of year (a)	$	1,963	$	1,711	$	798

(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
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---	---		NOTE 5 - LONG-TERM DEBT
---

As of December 31, 2025 and 2024, the Company’s debt consisted of the following:

millions	2025	2024
5.875% senior notes due 2025	—	536
5.500% senior notes due 2025	—	465
5.550% senior notes due 2026	—	870
3.400% senior notes due 2026	—	284
Two-year term loan due 2026 (5.475% and 6.249% as of December 31, 2025 and 2024, respectively)	1,280	2,700
3.200% senior notes due 2026	182	182
7.500% debentures due 2026	112	112
8.500% senior notes due 2027	489	489
3.000% senior notes due 2027	216	216
7.125% debentures due 2027	150	150
7.000% debentures due 2027	48	48
5.000% senior notes due 2027	600	600
6.625% debentures due 2028	14	14
7.150% debentures due 2028	232	232
7.200% senior debentures due 2028	82	82
6.375% senior notes due 2028	578	578
7.200% debentures due 2029	135	135
7.950% debentures due 2029	116	116
8.450% senior debentures due 2029	116	116
3.500% senior notes due 2029	286	286
5.200% senior notes due 2029	1,200	1,200
Variable rate bonds due 2030 (4.450% and 5.710% as of December 31, 2025 and 2024, respectively)	68	68
8.875% senior notes due 2030	1,000	1,000
6.625% senior notes due 2030	1,449	1,449
6.125% senior notes due 2031	1,143	1,143
7.500% senior notes due 2031	900	900
7.875% senior notes due 2031	500	500
5.375% senior notes due 2032	1,000	1,000
5.550% senior notes due 2034	1,200	1,200
6.450% senior notes due 2036	1,727	1,727
Zero Coupon senior notes due 2036	285	673
0.000% loan due 2039 (CAD denominated)	17	18
4.300% senior notes due 2039	247	247
7.950% senior notes due 2039	325	325
6.200% senior notes due 2040	737	737
4.500% senior notes due 2044	191	191
4.625% senior notes due 2045	296	296
6.600% senior notes due 2046	1,117	1,117
4.400% senior notes due 2046	424	424
4.100% senior notes due 2047	258	258
4.200% senior notes due 2048	304	304
4.400% senior notes due 2049	280	280
(continued on next page)				82	OXY 2025 FORM 10-K
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---	---		millions (continued)	2025		2024
---	---	---	---	---
6.050% senior notes due 2054	1,000		1,000
7.730% debentures due 2096	58		58
7.500% debentures due 2096	60		60
7.250% debentures due 2096	5		5
Total borrowings at face value	$	20,427	$	24,391
Adjustments to book value:
Unamortized premium, net	1,054		1,037
Debt issuance costs	(84)		(104)
Net book value of debt	$	21,397	$	25,324
Long-term finance leases	801		658
Current finance leases	198		135
Total debt and finance leases	$	22,396	$	26,117
Less current maturities of finance leases	(198)		(135)
Less current maturities of long-term debt	(1,575)		(1,003)
Long-term debt, net	$	20,623	$	24,979

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	$	24,391
Repayments
5.875% senior notes due 2025	(536)
5.500% senior notes due 2025	(465)
5.550% senior notes due 2026	(870)
3.400% senior notes due 2026	(284)
Zero Coupon senior notes due 2036	(388)
Two-year term loan due 2026	(1,420)
Other	(1)
Total repayments	$	(3,964)
Total borrowings at face value as of December 31, 2025	$	20,427

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.

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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<br><br>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	$	387	$	248	$	635
2027	289		226		515
2028	190		188		378
2029	58		152		210
2030	44		136		180
Thereafter	68		226		294
Total lease payments	1,036		1,176		2,212
Less: Discount	(81)		(177)		(258)
Total lease liabilities	$	955	$	999	$	1,954

(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	$	188	$	152
Interest on lease liabilities	40		36
Operating lease cost	486		459
Short-term lease cost	384		342
Total lease cost	$	1,098	$	989
millions	2025		2024
Cash payments related to leases
Operating cash flows from finance leases	$	40	$	34
Operating cash flows from operating leases	$	295	$	240
Investing cash flows from operating leases	$	192	$	209
Financing cash flows from finance leases	$	177	$	137
Changes in Right-of-Use assets
Right-of-use assets obtained in relation to new finance lease liabilities	$	395	$	195
Right-of-use assets obtained in relation to new operating lease liabilities	$	617	$	280		OXY 2025 FORM 10-K	85
---	---
table of contents	FINANCIAL STATEMENTS<br><br>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)	(59)	(34)
Natural gas commodity contracts
Volume (Bcf)	(189)	(130)

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<br><br>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 | $ | 345 | $ | 51 | $ | — | $ | (328) | $ | 68 | | Other long-term assets | — | | — | | — | | — | | — | | | Accrued liabilities | (336) | | (24) | | — | | 328 | | (32) | | | Deferred credits and other liabilities - other | — | | — | | — | | — | | — | | | December 31, 2024 | | | | | | | | | | | | Marketing Derivatives | | | | | | | | | | | | Other current assets | $ | 455 | $ | 92 | $ | — | $ | (512) | $ | 35 | | Other long-term assets | — | | 1 | | — | | (1) | | — | | | Accrued liabilities | (451) | | (90) | | — | | 512 | | (29) | | | Deferred credits and other liabilities - other | — | | (2) | | — | | 1 | | (1) | |

(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)	$	32	$	(374)	$	(74)

(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.

| OXY 2025 FORM 10-K | 87 | | --- | --- || table of contents | FINANCIAL STATEMENTS<br><br>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 Note5- 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	$	1,265	$	2,390	$	2,530
Foreign	1,863		1,634		2,132
Total income from continuing operations before income taxes	$	3,128	$	4,024	$	4,662

The following summarizes components of income tax (expense) benefit on continuing operations for the years ended December 31:

millions	2025		2024		2023
Current
Federal	$	(307)	$	(775)	$	(539)
State and local	—		(28)		(35)
Foreign	(587)		(620)		(702)
Total current tax expense	$	(894)	$	(1,423)	$	(1,276)
Deferred
Federal	(99)		197		(34)
State and local	(31)		20		20
Foreign	3		48		(40)
Total deferred tax (expense) benefit	$	(127)	$	265	$	(54)
Total income tax expense
Federal	(406)		(578)		(573)
State and local	(31)		(8)		(15)
Foreign	(584)		(572)		(742)
Total income tax expense	$	(1,021)	$	(1,158)	$	(1,330)
88	OXY 2025 FORM 10-K
---	---		table of contents	FINANCIAL STATEMENTS<br><br>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	$	609	$	405	$	293
State	39		16		42
Foreign
Algeria	155		207		285
Oman	359		332		335
Qatar	73		78		78
All other foreign	1		2		7
Total foreign	588		619		705
Income taxes paid, net of refunds received	$	1,236	$	1,040	$	1,040
OXY 2025 FORM 10-K	89
---	---		table of contents	FINANCIAL STATEMENTS<br><br>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	21	%	$	657	21	%	$	845	21	%	$	979
State and local income tax, net of federal income tax effect (a)	1		24		—		5		—		13
Foreign tax effects
Algeria
Tax rate differential	1		36		1		47		1		71
Change in tax law or rate	—		—		—		—		1		65
Nontaxable or nondeductible items	1		23		1		20		2		84
Others	—		7		1		20		—		(3)
Canada
Others	(1)		(16)		—		(7)		(1)		(54)
Oman
Tax rate differential	7		201		5		203		4		209
Others	1		34		—		4		—		(3)
Qatar
Tax rate differential	1		33		1		28		1		37
Others	—		(9)		—		8		—		(14)
United Arab Emirates
Tax rate differential	(5)		(143)		(3)		(105)		(2)		(94)
Other foreign jurisdictions	1		30		—		(5)		—		(11)
Effect of changes in tax laws or rates enacted in the current period	—		—		—		—		—		—
Effect of cross-border tax laws	—		10		—		1		—		4
Tax credits	(1)		(15)		(1)		(21)		—		(22)
Changes in valuation allowance	—		2		—		2		—		—
Nontaxable or nondeductible items	1		16		1		29		—		20
Changes in unrecognized tax benefits	5		144		3		136		2		105
Other adjustments	—		(13)		(1)		(52)		(1)		(56)
Worldwide effective tax rate	33	%	$	1,021	29	%	$	1,158	28	%	$	1,330

(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.

| 90 | OXY 2025 FORM 10-K | | --- | --- || table of contents | FINANCIAL STATEMENTS<br><br>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	$	(7,402)	$	(7,100)
Equity investments, partnerships and international subsidiaries	(831)		(633)
Gross long-term deferred tax liabilities	$	(8,233)	$	(7,733)
Deferred tax assets
Environmental reserves	409		416
Postretirement benefit accruals	173		249
Deferred compensation and benefits	344		258
Asset retirement obligations	893		788
Foreign tax credit carryforwards	713		1,975
Business credit carryforwards	60		54
Net operating loss carryforward	1,095		1,031
Interest expense carryforward	11		11
All other	685		539
Gross long-term deferred tax assets	4,383		5,321
Valuation allowance	(1,769)		(2,962)
Net long-term deferred tax assets	$	2,614	$	2,359
Total deferred income tax liability, net	$	(5,619)	$	(5,374)
Less: foreign deferred tax asset in long-term receivables and other assets, net	(17)		(20)
Total deferred income tax liability (a)	$	(5,636)	$	(5,394)

(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.

| OXY 2025 FORM 10-K | 91 | | --- | --- || table of contents | FINANCIAL STATEMENTS<br><br>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	$	1,951	$	1,951	$	2,010
Increases related to prior-year positions	—		—		—
Increases related to current-year positions	1		—		—
Settlements	—		—		—
Reductions for tax positions of prior years	(8)		—		(59)
Balance as of December 31	$	1,944	$	1,951	$	1,951

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 penalties associated with liabilities for unrecognized tax benefits recorded for the years ended December 31, 2025 and 2024.

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.

92	OXY 2025 FORM 10-K
table of contents	FINANCIAL STATEMENTS<br><br>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	$	153	$	133	$	—	$	—
Accrued liabilities	(2)		(2)		(51)		(52)
Deferred credits and other liabilities	(228)		(244)		(757)		(778)
	$	(77)	$	(113)	$	(808)	$	(830)
Accumulated other comprehensive loss included the following after-tax balances:
Net (gain) loss	$	(29)	$	(8)	$	(120)	$	(122)
Prior service credit	—		—		(59)		(40)
	$	(29)	$	(8)	$	(179)	$	(162)
OXY 2025 FORM 10-K	93
---	---		table of contents	FINANCIAL STATEMENTS<br><br>FOOTNOTES
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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	$	813	$	879	$	830	$	718
Service cost — benefits earned during the period	4		4		20		18
Interest cost on projected benefit obligation	42		42		42		35
Actuarial (gain) loss	14		(38)		(10)		105
Benefits paid	(68)		(71)		(45)		(50)
Plan amendments	—		—		(33)		—
Other	4		(3)		4		4
Benefit obligation — end of year	$	809	$	813	$	808	$	830
Changes in plan assets:
Fair value of plan assets — beginning of year	$	700	$	732	$	—	$	—
Actual return on plan assets	72		16		—		—
Employer contributions	21		23		41		45
Benefits paid	(68)		(71)		(45)		(50)
Other	7		—		4		5
Fair value of plan assets — end of year	$	732	$	700	$	—	$	—
Unfunded status:	$	(77)	$	(113)	$	(808)	$	(830)

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 <br>Obligation in Excess of <br>Plan Assets				Plan Assets in <br>Excess of Accumulated <br>Benefit Obligation
millions	2025		2024		2025		2024
Projected benefit obligation	$	636	$	648	$	173	$	165
Accumulated benefit obligation	$	636	$	647	$	173	$	165
Fair value of plan assets	$	525	$	505	$	207	$	195
94	OXY 2025 FORM 10-K
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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	$	4	$	4	$	5	$	20	$	18	$	16
Interest cost on projected benefit obligation	42		42		45		42		35		37
Expected return on plan assets	(36)		(41)		(45)		—		—		—
Recognized actuarial loss (gain)	3		2		4		(11)		(15)		(20)
Recognized prior service credit	—		—		—		(8)		(8)		(9)
Gain (loss) due to settlement	—		—		1		—		—		—
Net periodic benefit costs	$	13	$	7	$	10	$	43	$	30	$	24

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	5.29	%	5.52	%	5.45	%	5.68	%
Rate of increase in compensation levels	3.49	%	3.95	%	—		—
Net Periodic Benefit Cost Assumptions:
Discount rate	5.52	%	4.98	%	5.68	%	5.12	%
Rate of increase in compensation levels	3.95	%	3.96	%	—		—
Assumed long-term rate of return on assets	5.49	%	6.13	%	—		—

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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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	$	36	$	—	$	—	$	36
Corporate bonds (a)	—		17		—		17
Equity securities (b)	30		—		—		30
Other	1		43		—		44
Investments measured at fair value	$	67	$	60	$	—	$	127
Investments measured at net asset value (c)	—		—		—		605
Total pension plan assets	$	67	$	60	$	—	$	732
December 31, 2024
Asset Class:
Government securities	$	33	$	—	$	—	$	33
Corporate bonds (a)	—		17		—		17
Equity securities (b)	31		—		—		31
Other	2		41		—		43
Investments measured at fair value	$	66	$	58	$	—	$	124
Investments measured at net asset value (c)	—		—		—		576
Total pension plan assets	$	66	$	58	$	—	$	700

(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		$	68		$	52
2027		67			55
2028		62			54
2029		59			54
2030		58			53
2031 - 2035		268			264

The Company expects to contribute approximately $33 million to its defined benefit pension plans during 2026.

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---	---		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<br>Operations		Total		Ongoing Operations		Discontinued Operations		Total
Current Portion:
Accrued Liabilities	$	55	$	96	$	151	$	55	$	95	$	150
Non-Current Portion:
Deferred credit and other liabilities	141		1,578		1,719		170		1,589		1,759
Total current and non-current	$	196	$	1,674	$	1,870	$	225	$	1,684	$	1,909

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 million in 2025, $56 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 three 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	29	$	1,379	32	$	1,374
Third-Party Sites	69	238		63	200
Currently Operated Sites	4	25		12	88
Closed or Non-operated Sites	50	228		51	247
Total	152	$	1,870	158	$	1,909
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---	---

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.

Seven Closed or Non-operated Sites — a landfill in Western New York, a former refinery in Oklahoma, former chemical plants in California, New York, and Washington, and a closed coal mine in Pennsylvania — 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 ten 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.

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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 Liabilitiesand 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.

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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 billion in 2027 and 2028, $2.6 billion in 2029 and 2030, and $2.3 billion in 2031 and thereafter.

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---	---		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					938,457,983
First Quarter 2025	123,673		3,468,265		942,049,921
Second Quarter 2025	41,926,088		440,156		984,416,165
Third Quarter 2025	726,741		32,123		985,175,029
Fourth Quarter 2025	819,165		32,222		986,026,416
Total 2025	43,595,667		3,972,766		986,026,416

(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.

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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	$	2,107	$	2,866	$	3,332
Income from discontinued operations, net of tax	262		212		1,364
Net income	$	2,369	$	3,078	$	4,696
Less: Net income attributable to noncontrolling interest	(43)		(22)		—
Less: Preferred stock dividends	(679)		(679)		(923)
Net income attributable to common stock	$	1,647	$	2,377	$	3,773
Less: Incremental fair value for warrants inducement	(25)		—		—
Less: Net income allocated to participating securities	(10)		(13)		(23)
Net income, net of participating securities	$	1,612	$	2,364	$	3,750
Weighted-average number of basic shares	975.5		911.8		889.2
Basic earnings per common share	$	1.65	$	2.59	$	4.22
Net income attributable to common stock	$	1,647	$	2,377	$	3,773
Less: Incremental fair value for warrants inducement	(25)		—		—
Less: Net income allocated to participating securities	(10)		(13)		(21)
Net income, net of participating securities	$	1,612	$	2,364	$	3,752
Weighted-average number of basic shares	975.5		911.8		889.2
Dilutive securities	24.6		55.3		71.7
Total diluted weighted-average common shares	1,000.1		967.1		960.9
Diluted earnings per common share	$	1.61	$	2.44	$	3.90

For the year ended December 31, 2025, there were 84.2 million warrants/options consisting primarily of Berkshire warrants excluded from diluted shares. For the years ended December 31, 2024 and 2023, there were no Occidental common stock warrants nor options that were excluded from diluted shares.

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	$	(6)	$	(6)
Derivatives	—		15
Pension and postretirement adjustments (a)	208		170
Total	$	202	$	179

(a)See Note 10- Retirement and Postretirement Benefit Plans for further information.

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---	---		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 one 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	398	$	58.00	7,119	$	57.63
Granted	255	$	46.44	4,891	$	48.85
Vested	(170)	$	56.47	(3,551)	$	54.56
Forfeitures	(45)	$	55.30	(327)	$	53.44
Unvested as of December 31	438	$	52.15	8,132	$	53.86

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<br><br>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	4.0%		4.3%		4.6%
Volatility factor	32%		45%		64%
Expected life, years	2.83		2.83		2.84
Grant-date fair value of underlying Occidental common stock	$	48.84	$	61.36	$	59.71

A summary of changes in the Company’s unvested TSRIs in 2025 is presented below:

	TSRIs
thousands, except fair values	Awards	Weighted-Average <br>Grant-Date Fair Value <br>of Occidental Stock
Unvested as of January 1	1,251		$	55.08
Granted	391		$	48.84
Vested (a)	(388)		$	42.98
Forfeitures	(3)		$	48.84
Unvested as of December 31	1,251		$	56.90

(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	2,305	$	37.89	83	$	42.98
Vested	83	$	42.98	(83)	$	42.98
December 31	2,388	$	38.07	—	$	—

There were no options exercised during the years ended December 31, 2025 and 2024. The intrinsic value of options exercised during the year ended December 31, 2023 was $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<br><br>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<br>Grant-Date<br>Fair Value of Occidental Stock
Unvested as of January 1	447		$	54.55
Granted	391		$	48.84
Vested (a)	(156)		$	42.98
Forfeited	(3)		48.84
Unvested as of December 31	679		$	53.94

(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<br><br>FOOTNOTES
---	---		NOTE 15 - INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS
---

The Company conducts its operations through two segments: oil and gas and midstream and marketing. Income taxes, interest income, interest expense, environmental remediation expenses and acquisition-related costs of the Company’s operating subsidiaries and unallocated corporate expenses are consolidated under corporate and eliminations. Intersegment sales eliminate upon consolidation and are made at prices that approximate market. Identifiable assets are those assets used in the operations of the segments. Corporate assets consist of cash and restricted cash, certain corporate receivables and PP&E.

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 Note4- 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	$	4,586	$	5,214	$	6,240
Midstream and marketing segment	252		563		(35)
Corporate and eliminations	(631)		(584)		(586)
Interest and debt expense, net	(1,079)		(1,169)		(957)
Income from continuing operations before income taxes	$	3,128	$	4,024	$	4,662
Income tax expense	(1,021)		(1,158)		(1,330)
Income from continuing operations	$	2,107	$	2,866	$	3,332
Discontinued operations, net of tax	262		212		1,364
Net income	$	2,369	$	3,078	$	4,696
Less: Net income attributable to noncontrolling interest	(43)		(22)		—
Less: Preferred stock dividends and redemption premiums	(679)		(679)		(923)
Net income attributable to common stockholders	$	1,647	$	2,377	$	3,773

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<br><br>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	$	20,902	$	21,705	$	21,284
Gains (losses) on sale of assets and other income	(70)		(551)		192
Total	$	20,832	$	21,154	$	21,476
Significant segment expenses
Oil and gas lease operating expense	4,681		4,738		4,677
Transportation and gathering expense	1,629		1,583		1,427
Other operating and non-operating expense	1,161		997		889
Taxes other than on income	1,009		1,026		1,076
Depreciation, depletion and amortization	7,115		6,565		6,112
Other segment expenses	633		993		1,031
Total	$	16,228	$	15,902	$	15,212
Segment income before other items	$	4,604	$	5,252	$	6,264
Losses from equity investments and other	(18)		(38)		(24)
Segment income from continuing operations before taxes	$	4,586	$	5,214	$	6,240

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	$	1,279	$	886	$	2,433
Gains on sale of assets and other income	500		628		494
Total	$	1,779	$	1,514	$	2,927
Significant segment expenses
Purchased commodities and midstream cost of sales	800		1,035		2,749
Other operating and non-operating expense	359		289		234
Depreciation, depletion and amortization	294		273		266
Other segment expenses	168		151		163
Total	$	1,621	$	1,748	$	3,412
Segment income (losses) before other items	$	158	$	(234)	$	(485)
Income from equity investments and other	94		797		450
Segment income (losses) from continuing operations before taxes	$	252	$	563	$	(35)
OXY 2025 FORM 10-K	107
---	---		table of contents	FINANCIAL STATEMENTS<br><br>FOOTNOTES
---	---

SEGMENT INVESTMENTS AND EXPENDITURES

The following table includes segment-level balance sheet information:

millions	Oil and gas		Midstream and marketing		Corporate and<br>eliminations		Assets held for sale		Total
Year ended December 31, 2025
PP&E Additions	$	5,703	$	806	$	98	$	—	$	6,607
Investments in unconsolidated entities	$	129	$	2,346	$	—	$	—	$	2,475
Total Assets	$	60,393	$	13,901	$	3,372	$	6,520	$	84,186		Year ended December 31, 2024
---	---	---	---	---	---	---	---	---	---	---
PP&E Additions	$	5,408	$	930	$	82	$	—	$	6,420
Investments in unconsolidated entities	$	94	$	2,552	$	—	$	—	$	2,646
Total Assets	$	63,596	$	13,177	$	3,102	$	5,570	$	85,445

GEOGRAPHIC AREAS

The following table represents the Company’s property, plant and equipment, net by geographic area for the years ended December 31:

millions	2025		2024		2023
United States	$	57,038	$	59,158	$	48,677
International
UAE	3,375		3,495		3,609
Oman	2,238		2,187		2,156
Algeria	626		618		624
Qatar	326		361		393
Other International	40		44		35
Total International	6,605		6,705		6,817
Total	$	63,643	$	65,863	$	55,494		108	OXY 2025 FORM 10-K
---	---
table of contents	Supplemental Quarterly Financial Data<br><br>(Unaudited)
---	---		Supplemental Quarterly Financial Data (Unaudited)	Occidental Petroleum Corporation<br>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<br><br>(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<br><br>(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<br><br>(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<br><br>(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.

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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<br><br>(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.

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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.

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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.

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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.

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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.

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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
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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.

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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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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
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---	---		Sales per Day by Products	2025	2024	2023
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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
124	OXY 2025 FORM 10-K
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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 or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408(a) of Regulation S-K).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

OXY 2025 FORM 10-K	125
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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.

126	OXY 2025 FORM 10-K
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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).
OXY 2025 FORM 10-K	127
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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).*exhibit101123125.htm
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 Planhttps://www.sec.gov/Archives/edgar/data/797468/000079746825000029/exhibit1018occidentalpetro.htm(As Amended and Restated Effective February 12, 2025)https://www.sec.gov/Archives/edgar/data/797468/000079746825000029/exhibit1018occidentalpetro.htm(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).		128	OXY 2025 FORM 10-K
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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).
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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	Occidental Petroleum Insider Trading Policy (filed as Exhibit 19.1 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2024, File No. 1-9210).
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.

OXY 2025 FORM 10-K	129
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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			130	OXY 2025 FORM 10-K
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Document

Exhibit 10.1

Occidental Petroleum Corporation Savings Plan

Amended and Restated Effective as of January 1, 2026

Article 1. Introduction	1
1.1 Restatement of Plan	1
1.2 Purpose and Applicability of the Plan	1
1.3 Structure of the Plan	1
Article 2. Definitions and Construction	3
2.1 Definitions	3
2.2 Gender and Number	24
2.3 Headings	24
2.4 Requirement to Be in “Written Form”	24
2.5 Severability	24
2.6 Applicable Law	24
Article 3. Participation, Service and Vesting	26
3.1 Date of Participation	26
3.2 Duration	26
3.3 Transfers	26
3.4 Service	26
3.5 Vesting	27
3.6 Forfeiture of Contingent Interests	29
Article 4. Active Participant Contributions	31
4.1 Pre-Tax Deferrals, Roth Contributions and After-Tax Contributions	31
4.2 Catch-Up Contributions	33
4.3 Election Procedures	33
4.4 Salary Reduction	34
4.5 Deposit and Crediting of Deferrals and Contributions	34
4.6 Eligible Automatic Enrollment Arrangement	34
Article 5. Employer Contributions	36
5.1 Employees Eligible for Matching Contributions	36
5.2 Amount of Matching Contributions	36
5.3 Depositing and Crediting Matching Contributions	37
Article 6. Benefit Limitations	38
6.1 Elective Deferral Limit	38
6.2 Discrimination Limits on Pre-Tax Deferrals and Roth Contributions	40
6.3 Corrective Measures if ADP Test Failed	41
6.4 Discrimination Limits on Matching Contributions, After-Tax Contributions, and Adjustment Contributions	45
6.5 Corrective Measures if ACP Test Failed	47
6.6 Limitation on Annual Additions	50
6.7 Limitation on Pay Taken Into Account	53
6.8 Deductibility Limitation	53
Article 7. Benefit Distributions	55
7.1 Distributions Generally	55
7.2 In-Service Withdrawals	55
7.3 Benefits Upon Separation from Service	58
7.4 Payment Rules	58
7.5 Death Benefits	63
7.6 Required Minimum Distributions	65
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7.7 Mandatory Tax Withholding and Direct Rollovers	68
7.8 In-Plan Roth Rollovers	71
Article 8. Participant Loans	73
8.1 Availability of Loans	73
8.2 Amount of Loan	73
8.3 Procedures for Loans	73
Article 9. Investment Elections	75
9.1 Investment of Contributions	75
9.2 Transfers of Existing Balances	76
9.3 Transfer of Assets	77
9.4 Reserved	77
9.5 Matching Account Diversification Rights After August 1, 2004	77
Article 10. Participant Accounts and Records of the Plan	79
10.1 Accounts and Records	79
10.2 Account Value	79
10.3 Investment Funds	79
10.4 Unit Value of Investment Funds	79
10.5 Calculation of Unit Value	80
10.6 Valuation Adjustments	80
10.7 Debiting of Accounts upon Distribution, Withdrawal, Loan or Charge	80
10.8 Unit Value upon Transfer of Investment Funds	80
10.9 Oxy Stock Fund Valuation	80
10.10 Value of Accounts	81
10.11 Cost Account	82
10.12 Rollover and Roth and After-Tax Rollover Contributions	82
10.13 Merger of the THUMS Long Beach Company Savings and Investment Plan	84
Article 11. Financing	85
11.1 Trust Fund	85
11.2 Oxy Stock Fund	85
11.3 Forfeitures	89
11.4 Non-Reversion	90
11.5 Direct Transfer of Assets from Plans of Acquired Entities	90
11.6 Pension Expense Reimbursement Account (“PERA”)	90
Article 12. Administration	91
12.1 The Administrative Committee	91
12.2 Chairperson, Secretary, and Employment of Specialists	91
12.3 Compensation and Expenses	91
12.4 Manner of Action	92
12.5 Subcommittees	92
12.6 Other Agents	92
12.7 Records	92
12.8 Rules	92
12.9 Administrative Committee’s Powers and Duties	92
12.10 Investment Responsibilities	93
12.11 Administrative Committee’s Decisions Conclusive	94
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12.12 Indemnity	94
12.13 Fiduciaries	96
12.14 Notice of Address	97
12.15 Data	97
12.16 Benefit Claims Procedures	97
12.17 Member’s Own Participation	100
Article 13. Amendment and Termination	101
13.1 Amendment and Termination	101
13.2 Distribution on Termination	101
13.3 Successors	101
13.4 Plan Merger or Transfer	101
Article 14. Participating Affiliates	103
14.1 Adoption of the Plan	103
14.2 Conditions of Participation	103
14.3 Termination of Participation	103
14.4 Consequences of the Termination of an Employer	104
Article 15. Top-Heavy Provisions	106
15.1 Application of Top-Heavy Provisions	106
15.2 Definitions Applicable to this Article	106
15.3 Determination of Top-Heavy Ratio	107
15.4 Required Minimum Allocations	108
15.5 Required Minimum Vesting	108
15.6 Employees Covered by Collective Bargaining Agreement	109
Article 16. Miscellaneous Provisions	110
16.1 No Enlargement of Employment Rights	110
16.2 No Examination or Accounting	110
16.3 Investment Risk	110
16.4 Non-Alienation	110
16.5 Incompetency	111
16.6 Records Conclusive	112
16.7 Counterparts	112
16.8 Service of Legal Process	112
16.9 Uncashed or Unclaimed Benefits	112
16.10 Qualified Military Service	113

Article 1. Introduction

1.1 Restatement of Plan

Effective as of January 1, 2026, Occidental Petroleum Corporation (“Company”) hereby amends and restates the Occidental Petroleum Corporation Savings Plan (“Plan”) to make amendments and changes as reflected herein. The provisions of this restatement shall be effective as of January 1, 2026, except as follows or as otherwise specifically provided in this document. Where a particular provision of this restatement has an effective date earlier than January 1, 2026, the relevant provision of this restatement shall supersede the corresponding provision of the prior version of the Plan as of the earlier effective date. Where a particular provision of this restatement has an effective date later than January 1, 2026, the relevant provision of the prior version of the Plan shall continue to apply prior to such effective date.

1.2 Purpose and Applicability of the Plan

This Plan is intended to encourage and assist Eligible Employees in adopting a regular program of savings to provide additional security for their retirement. Except as otherwise provided herein, the provisions of this Plan restatement are applicable only to Eligible Employees on or after January 1, 2026. Unless otherwise explicitly provided in this Plan restatement, the Plan provisions in effect prior to this restatement shall continue to govern the terms and conditions of the Plan prior to January 1, 2026.

Notwithstanding any contrary Plan provision, if any modification of ERISA or the Code (or regulations or rulings thereunder) requires that a conforming Plan amendment be adopted as of a stated effective date in order for the Plan to continue to be a qualified plan, this Plan shall be operated in accordance with such requirements until the date when a conforming Plan amendment is adopted.

1.3 Structure of the Plan

The Plan is intended to qualify as a stock bonus plan under Code section 401(a) that includes a qualified cash or deferred arrangement under Code section 401(k)(2).

Effective June 1, 2002, to enable the deduction on dividends paid on certain employer securities as permitted by Code section 404(k), the Matching Accounts, or portions thereof, invested in the Oxy Stock Fund under the Plan, at any point in time and in the aggregate, are intended to qualify, and are hereby designated, as an employee stock ownership plan (“ESOP”), within the meaning of Code section 4975(e)(7). Effective July 19, 2007, to expand the availability of the deduction on dividends paid on employer securities as permitted by Code section 404(k), the ESOP is expanded to include the Oxy Stock Fund and the portions of Matching Accounts not invested in the Oxy Stock Fund shall cease to constitute part of the ESOP. On or before July 18, 2007, the Matching Accounts, or portions thereof, invested in the Oxy Stock Fund under the Plan, at any point in time, taken together, and effective on or after July 19, 2007, all assets invested in the Oxy Stock Fund at any point in time, regardless of funding source, constitute an “eligible individual account plan,” as defined in ERISA section 407(d)(3), which explicitly provides for the acquisition and holding of and investment primarily in

shares of Oxy Stock which constitute “qualifying employer securities,” as described in Code section 4975(e)(8), and “employer securities,” as defined in Code section 409(l).

The Company intends that the Plan and the ESOP together shall constitute a single plan under ERISA and the Code. Accordingly, the provisions set forth in the other sections of the Plan shall apply to the ESOP in the same manner as those provisions apply to the remaining portions of the Plan, except to the extent that those provisions are by their terms inapplicable to the ESOP, or to the extent that they are inconsistent with the specific provisions set forth herein. Except as set forth in specific provisions herein that are related to the ESOP, including but not limited to Plan section 9.5, the designation of any portion of the Plan constituting part of the ESOP shall not affect any Beneficiary designations or any other applicable agreements, elections or consents that Participants, Spouses, Alternate Payees or Beneficiaries validly executed under the terms of the Plan before June 1, 2002, the effective date of the ESOP; and such designations, agreements, elections, and consents shall apply under the ESOP in the same manner as they apply under the Plan.

Effective as of the Closing Date (as that term is defined in the Purchase and Sale Agreement (“Purchase Agreement”) by and among Berkshire Hathaway, Inc., Occidental Chemical Holding, LLC, and Environmental Resource Holdings, Inc. dated October 1, 2025 (“MEP Effective Date”), Occidental Chemical Corporation (“OxyChem”) ceased (or will cease) to be an Affiliate of the Company. Notwithstanding the foregoing and in accordance with terms set forth in Appendix I, OxyChem will remain an Employer under the Plan following the MEP Effective Date. The Plan shall be a multiple-employer plan within the meaning of Code section 413(c) beginning on the MEP Effective Date and during the period Appendix I remains in effect. Except as expressly modified by Appendix I or applicable law, all terms and conditions of the Plan will apply with respect to OxyChem and its eligible employees. In the event of an inconsistency between Appendix I and this Plan document, Appendix I will control, unless applicable law requires otherwise.

Article 2. Definitions and Construction

2.1 Definitions

Whenever used in the Plan, the following terms shall have the respective meanings set forth below, unless otherwise expressly provided; and when the defined meaning is intended, the term is capitalized.

(a)“Account” means the separate recordkeeping account maintained for each Participant which represents his or her total proportionate interest in the Trust Fund and which consists of the sum of following:

(1)After-Tax Account;

(2)After-Tax Rollover Account;

(3)In-Plan Roth Rollover Account;

(4)Matching Account;

(5)Pre-Tax Account;

(6)Rollover Account;

(7)Roth Account; and

(8)Roth Rollover Account.

The term “Account” shall also include any separate account established on behalf of an Alternate Payee pursuant to a Qualified Domestic Relations Order or a Beneficiary following the Participant’s death.

(b)“Accounting Date” means any day on which trading occurs on the New York Stock Exchange.

(c)“ACP Test” means the average contribution percentage test performed in accordance with Plan section 6.4.

(d)“Active Participant” means any Eligible Employee who:

(1)Has met the requirements to become a Participant as set forth in Article 3,

(2)Continues to be employed as an Eligible Employee, and

(3)Has not become an Inactive Participant or Former Participant.

(e)“Actual Deferral Percentage” means, for each group of Participants for any period, the average of the ratios (calculated separately for each Participant in each group) of Pre-Tax Deferrals and/or Roth Contributions taken into account under the rules of this paragraph made on behalf of the Participant for the Plan Year to that Participant’s Testing Compensation earned while a Participant for the Plan Year. Such ratios and the Actual

Deferral Percentage for each group shall be calculated to the nearest one-hundredth of 1 percent of a Participant’s Testing Compensation. If Pre-Tax Deferrals or Roth Contributions cannot be taken into account under the ADP Test because they do not meet the following rules, then such amount must satisfy the nondiscrimination requirements of Code section 401(a)(4) for the Plan Year for which they are made. The following rules shall apply in determining the Average Deferral Percentages:

(1)Pre-Tax Deferrals and Roth Contributions shall be taken into account for the Plan Year in determining a Participant’s Actual Deferral Percentage only if all of the following requirements are met:

(A)The Pre-Tax Deferral and/or Roth Contribution is allocated as of a date in the Plan Year and the allocation is not contingent on the Participant’s participation in the Plan or performance of services for an Employer after the allocation date.

(B)The Pre-Tax Deferral and/or Roth Contribution is contributed to the Trust Fund no more than 12 months after the last day of the Plan Year.

(C)The Pre-Tax Deferral and/or Roth Contribution is made on account of the Participant’s election to reduce Earnings that would otherwise be paid within that Plan Year. Notwithstanding the foregoing, to the extent elected by the Administrative Committee on a uniform basis, Pre-Tax Deferrals and/or Roth Contributions may be taken into account for the Plan Year if they are attributable to services performed during the Plan Year and, but for the Participant’s election to reduce Earnings, would have been received by the Participant after the last day of the Plan Year but within 21/2 months after the last day of the Plan Year. If the Administrative Committee makes this election for a Plan Year, then the Pre-Tax Deferrals and/or Roth Contributions shall be taken into account only in the ADP Test (or the ACP Test) for that Plan Year and shall not be taken into account in the ADP Test (or the ACP Test) for any other Plan Year.

(2)If any Highly Compensated Employee is a participant under two or more qualified cash or deferred arrangements of the Company or any Affiliate (including this Plan), all such cash or deferred arrangements shall be treated as one such arrangement for purposes of determining the Actual Deferral Percentage of the Highly Compensated Employee, except as provided in Treasury Regulations section 1.401(k)-2(a)(3)(ii).

(3)Pre-Tax Deferrals and/or Roth Contributions of Highly Compensated Employees for the Plan Year shall include Excess Deferrals, whether or not such Excess Deferrals are distributed under Plan section 6.1.

(4)Pre-Tax Deferrals and/or Roth Contributions taken into account under the ACP Test of Plan section 6.4 for the Plan Year shall not be taken into account under the ADP Test of this Plan section for the same or any other Plan Year.

(5)Pre-Tax Deferrals and/or Roth Contributions made pursuant to Code

section 414(u) shall not be taken into account for purposes of the ADP Test (or the ACP Test) for the Plan Year in which they are made or in any other Plan Year.

(f)“ADP Test” means the actual deferral percentage test performed in accordance with Plan section 6.2.

(g)“Adjustment Contributions” means Pre-Tax Deferrals and/or Roth Contributions which are recharacterized as After-Tax Contributions in order to comply with nondiscrimination tests of Code sections 401(k) and 401(m), as described in Plan sections 6.2 and 6.4. To the extent required by Treasury Regulations section 1.401(m)-2(b)(3), Adjustment Contributions after recharacterization shall be treated as:

(1)After-Tax Contributions for purposes of Code sections 72, 401(a)(4), and 401(m); and

(2)Pre-Tax Deferrals and/or Roth Contributions for purposes of Code sections 401(a) (other than Code sections 401(a)(4), 401(k), and 401(m)), 404, 409, 411, 415, 416,

and 417.

(h)“Administrative Committee” means the committee whose members are appointed by the Fiduciary Appointment Officer to administer the Plan in accordance with the applicable provisions of this Plan, including Article 12.

(i)“Affiliate” means:

(1)Any business entity while it is controlled by or under common control with the Company within the meaning of Code sections 414 and 1563, or

(2)Any member of an affiliated service group, within the meaning of Code section 414(m), of which the Company or any Affiliate is a member; and

(3)Any entity which, pursuant to Code section 414(o) and related Treasury Regulations, must be aggregated with the Company or any Affiliate for plan qualification purposes.

For purposes of paragraph (1), the determination of control shall be made without reference to paragraphs (a)(4) and (e)(3)(C) of Code section 1563. For the purposes of applying the limitations of Plan

sections 2.1(sss) and 6.6, the phrase “more than 50 percent” shall be substituted for the phrase “at least 80 percent” each place it appears in Code section 1563(a)(1).

(j)“After-Tax Account” means the recordkeeping account which evidences the value of After-Tax Contributions and any Adjustment Contributions, including related investment gains and losses of the Trust Fund.

(k)“After-Tax Contributions” means the voluntary contributions made by a Participant to the Plan on an after-tax basis, as described in Plan section 4.1.

(l)“After-Tax Rollover Account” means the recordkeeping account which evidences the value of After-Tax Rollover Contributions, including related investment gains and losses of the Trust Fund.

(m)“After-Tax Rollover Contributions” means the eligible after-tax contributions made at the direction of the Employee pursuant to Plan section 10.12 on or after January 1, 2020.

(n) “Alternate Payee” means, with respect to a Participant, any Spouse, former Spouse, child, or other dependent of that Participant, who is an alternate payee, within the meaning of Code section 414(p)(8), and who is recognized by a Qualified Domestic Relations Order as having the right to receive all or a portion of the benefits payable under the Plan with respect to the Participant.

(o)“Annual Addition” means the sum of the amounts described in Plan section 6.6(b).

(p)“Annual Bonus” means up to the first $100,000 of bonus paid from an Employer to an Active Participant, who is not a “named executive officer,” as that term is defined in Regulations S-K under the Securities Exchange Act of 1934 (17 CFR §229.402(a)(3)), during the Plan Year under a regular annual incentive compensation plan, such as the Company’s Variable Compensation Program or Incentive Compensation Program (but excluding without limitation a special individual or group bonus, a project bonus, and any other special bonus).

(q)“Average Contribution Percentage” means, for each group of Participants for any period, the average of the ratios (calculated separately for each Participant in each group) of the sum of Matching Contributions, After-Tax Contributions, and Adjustment Contributions made on behalf of the Participant for the Plan Year to that Participant’s Testing Compensation earned while a Participant for the Plan Year. Such ratios and Average Contribution Percentage for each group shall be calculated to the nearest one-hundredth of 1 percent of an Eligible Employee’s Testing Compensation. If Matching Contributions, After-Tax Contributions or Adjustment Contributions cannot be taken into account under the ACP Test because they do not meet the following rules, then such amount must satisfy the nondiscrimination requirements of Code section 401(a)(4) for the Plan Year

for which they are made. The following rules shall apply in determining the Average Contribution Percentages:

(1)After-Tax Contributions shall be taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year that the After-Tax Contributions are transferred to the Trust Fund. For this purpose, an After-Tax Contribution is treated as transferred to the Trust Fund at the time it would have been paid to the Participant if it is transferred to the Trust Fund within a reasonable time after the amount is withheld from the Participant’s Earnings.

(2)Adjustment Contributions are taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year in which the Adjustment Contributions are includible in the gross income of the Participant.

(3)Matching Contributions are taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year only if all of the following are met:

(A)The Matching Contribution is made on account of the Participant’s Pre-Tax Deferrals, Roth Contributions or After-Tax Contributions for the Plan Year.

(B)The Matching Contribution is allocated to the Participant’s Matching Account as of a date within the Plan Year.

(C)The Matching Contribution is transferred to the Trust Fund no more than 12 months after the last day of the Plan Year.

(4)Any Matching Contributions that are forfeited because the Pre-Tax Deferrals, Roth Contributions or After-Tax Contributions to which they relate are determined to be an Excess Deferral, an Excess Contribution, or an Excess Aggregate Contribution for the Plan Year are not taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year.

(5)If any Highly Compensated Employee is a participant under two or more Qualified Plans of the Company or any Affiliate (including this Plan) that provide for matching contributions or after-tax contributions, all such contributions made by or on behalf of the Highly Compensated Employee under such Qualified Plans during the 12- month period that coincides with the Plan Year shall be taken into account in determining the Average Contribution Percentage of the Highly Compensated Employee, except as provided in Treasury Regulations

section 1.401(m)-2(a)(3)(ii).

(6)Matching Contributions and After-Tax Contributions made pursuant to Code section 414(u) shall not be taken into account for purposes of the

ACP Test for the Plan Year in which they are made or in any other Plan Year.

(7)Subject to the conditions prescribed and to the extent permitted by Treasury Regulations section 1.401(m)-2(a)(6)(ii), the Administrative Committee may elect to take into account Pre-Tax Deferrals and Roth Contributions in computing Average Contribution Percentages.

(r)“Base Pay” means the base salary and wages earned by an Active Participant from an Employer for services rendered, including amounts of Pre-Tax Deferrals, Roth Contributions and amounts contributed pursuant to the Pre-Tax Spending Program.

(1)Base Pay does not include:

(A)Bonuses, incentives, overtime, shift differential, and overseas differentials;

(B)Reimbursement for expenses or allowances, including automobile allowances and moving allowances;

(C)Any amount contributed by the Employer (other than Pre-Tax Deferrals, Roth Contributions and amounts contributed pursuant to the Pre-Tax Spending Program) to any pension plan or plan of deferred compensation;

(D)Any amount contributed by an Employer (in addition to Pre-Tax Deferrals, Roth Contributions and Catch-Up Contributions) to this Plan;

(E)Any amount paid by an Employer for other fringe benefits, such as health and hospitalization, and group life insurance benefits, or perquisites; and

(F)Allowances paid during furlough and, for purposes of paragraph (2)(F) below, such furloughs shall not be treated as paid leaves of absence.

(2)Base Pay is determined in accordance with the following rules:

(A)For Active Participants compensated by salary, Base Pay means the actual base salary of record paid to the Active Participant (subject to the exclusions listed above).

(B)For Active Participants compensated based on mileage driven (primarily truck drivers), Base Pay means the number of miles driven multiplied by the applicable mileage pay rate (subject to the exclusions listed above), plus the Active Participant’s scheduled number of hours worked in the pay period multiplied by the Active Participant’s base hourly rate (subject to the exclusions listed above).

(C)For Active Participants compensated at an hourly rate, Base Pay means the base hourly rate (subject to the exclusions listed above) multiplied by the number of regularly scheduled hours worked in a pay period. If the Active Participant’s regularly scheduled work week is more than 40 hours, Base Pay shall include an additional amount equal to the base hourly rate (subject to the exclusions listed above) times one half the number of regularly scheduled hours worked in excess of 40 in the work week.

(D)For Active Participants compensated on an eight, ten, twelve, or some other assigned hour Shift Basis and whose annual Base Pay is pre-determined under the Company’s payroll recordkeeping, Base Pay for each pay period shall be the Active Participant’s pre-determined annual Base Pay (subject to the exclusions listed above) divided by the number of pay periods applicable to the Active Participant during the Plan Year. For the purpose of this subsection, the term “Shift Basis” means any arrangement whereby Active Participants work the assigned hour daily shifts which may result in alternating work weeks of more and less than 40 hours per week.

(E)Base Pay includes paid time off and vacation pay received in periodic payments and annual paid time off and vacation payments made to Employees paid by commission but does not include single sum paid time off and vacation payments to active or terminating Employees.

(F)Base Pay includes base salary or wages received during paid leaves of absence and periodic notice pay, but, effective July 1, 2006, Base Pay does not include single sum notice pay payments or any severance pay payments.

(G)Base Pay does not include long-term disability payments or payments made to any Participant pursuant to the Occidental Chemical Corporation Weekly Sickness and Accident Plan unless:

(i)Such payments are made to the Participant through the payroll accounting department of the Company or an Affiliate, and

(ii)The Participant is ineligible for participation in the Retirement Plan.

(H)Base Pay includes any payment to a Participant who does not currently perform services for an Employer by reason of qualified military service (within the meaning of Code section 414(u)(1)) to the extent that the payment does not exceed the amount that the Participant would have received if the Participant continued to

perform services for the Employer rather than entering qualified military service.

(s)“Beneficiary” means the person or persons (who may be named contingently or successively) designated by a Participant, an Alternate Payee, or a Beneficiary of a deceased Participant or a deceased Alternate Payee to receive his or her Account in the event of death.

If no Beneficiary is designated at the time of the Participant’s or Alternate Payee’s death, or at the time of death of the Beneficiary of a deceased Participant or Alternate Payee, or if no person so designated shall survive the Participant, Alternate Payee, or Beneficiary of a deceased Participant or Alternate Payee, the Beneficiary shall be the deceased person’s Spouse, or if the deceased individual has no surviving Spouse, his or her surviving children equally, or if there are no surviving children, his or her surviving parents equally, or if only one parent is living, his or her living parent, or if no parent is living, his or her surviving siblings equally, or if only one sibling is living, his or her surviving sibling, or if no sibling is living, his or her estate.

The designation by a married Participant of someone other than the Participant’s Spouse as a Beneficiary shall be invalid unless:

(1)The Spouse consents in writing to the designation of any specific non-Spouse Beneficiary which may not be changed without the Spouse’s consent (unless the Spouse’s consent expressly permits the Participant to change Beneficiary designations without further consent by the Spouse);

(2)The consent acknowledges the effect of such designation; and

(3)The consent is notarized.

No spousal consent shall be required if it is established to the satisfaction of the Plan representative that such consent cannot be obtained because there is no Spouse or because the Spouse cannot be located.

Notwithstanding the foregoing, where an Employee becomes a Participant through merger of his or her account from another plan into this Plan, “Beneficiary” means the person or persons so designated under such other plan until a new Beneficiary designation is effected as described above by such Employee.

(t)“Board” means the Board of Directors of the Company.

(u)“Catch-Up Contributions” means the contributions made by the Employer, on or after June 30, 2002, on behalf of an Active Participant, who will have attained age 50 before the last day of the Plan Year, on a

Pre-Tax and/or Roth basis as elected by the Participant pursuant to Plan section 4.2. Catch-Up Contributions for the Plan Year may not exceed the limit in effect for such Plan Year under Code section 414(v)(2)(B)(i), as adjusted pursuant to Code section 414(v)(2)(C).

(v)“Code” means the Internal Revenue Code of 1986, as amended. Each Code reference in this Plan shall be deemed to include reference to any comparable or succeeding statutory provision which supplements or replaces such Code reference.

(w)“Company” means Occidental Petroleum Corporation.

(x)“Covered Employee” means a Participant who is covered under the Plan’s eligible automatic contribution arrangement under Section 4.6. Prior to October 8, 2019, a Covered Employee will include all Eligible Employees hired on or after August 5, 2016, excluding interns and temporary employees, and on and after October 8, 2019, a Covered Employee will include all Eligible Employees (including Eligible Employees hired prior to August 5, 2016).

(y)“Disability” means the disability of:

(1)Any Active Participant who is determined to be disabled under section 423 of Title 42 of the U. S. Code and who receives disability insurance benefits thereunder; or

(2)Any Active Participant who is a participant in the Occidental Petroleum Corporation Long-Term Disability Plan or, prior to March 1, 2002, the OxyVinyls, LP Long-Term Disability Plan and who is determined to be disabled therein under the definition of “disability” applicable to the period beginning 24 months after the commencement of disability and who receives benefits thereunder.

An Active Participant shall be considered to have incurred the Disability as of the time of the commencement of the disability benefits as described above while the Active Participant was an Employee.

A Former Participant shall be considered to have incurred the Disability and retroactively vest upon receipt of more than 18 months of benefits under the Occidental Petroleum Corporation Long-Term Disability Plan.

A Participant who claims to have incurred the Disability as a result of being determined to be disabled under section 423 of Title 42 of the U.S. Code must give written notice thereof to the Administrative Committee and submit, at the expense of the Participant, to the Administrative Committee such evidence of Disability as the Administrative Committee may require. Failure by a Participant to comply with the foregoing requirements shall be deemed conclusive evidence that such Participant

has not incurred the asserted Disability. All rules with respect to the determination of Disability shall be uniformly and consistently applied to all Participants in similar circumstances.

(z)“Earnings” means the sum of Base Pay and Annual Bonus paid to an Active Participant by an Employer during the Plan Year. Effective for Plan Years beginning after 2001, the annual Earnings of each Participant taken into account in determining allocations for any Plan Year shall not exceed $200,000, as adjusted for cost-of-living increases in accordance with Code section 401(a)(17)(B).

(aa)“Eligible Dividends” means, as further described in Plan section 11.2:

(1)Between June 1, 2002 and July 18, 2007, dividends paid on Oxy Stock held in the Oxy Stock Fund attributable to the Participant’s Matching Account constituting the ESOP portion of the Plan; and

(2)On or after July 19, 2007, dividends paid on Oxy Stock held in the Oxy Stock Fund constituting the ESOP portion of the Plan.

(3)Eligible Dividends paid on Oxy Stock held in the Oxy Stock Fund attributable the Participant’s Matching Account shall be reflected in the Participant’s Matching Account. Eligible Dividends paid on Oxy Stock held in the Oxy Stock Fund attributable to other than the Participant’s Matching Account shall be reflected for recordkeeping purposes in the After-Tax Account, Pre-Tax Account, Rollover Account, Roth Account or Roth Rollover Account from which the Eligible Dividend is derived.

(ab)“Eligible Employee” means any Employee who is employed by an Employer, unless excluded under one or more of the following categories of Employees:

(1)Represented Employees where retirement benefits were the subject of good faith bargaining between the Employer and the union, unless the collective bargaining agreement covering the Represented Employees expressly provides participation in the Plan. Represented Employees covered by collective bargaining agreements providing for their participation in the Plan became Eligible Employees as of the dates noted in Appendix A.

(2)Employees who are nonresident aliens who receive no earned income from the Employer which constitutes U.S.-source income under Code section 861(a)(3), unless the Administrative Committee expressly makes the Plan available to such an Employee.

(3)Leased Employees.

(4)Employees of Occidental Oil and Gas Corporation who immediately before January 1, 2008 were eligible employees under the THUMS Long

Beach Company Savings and Investment Plan (as defined in that plan) and who thus continue to participate under that plan. Notwithstanding the previous sentence, effective July 1, 2008, Employees of Occidental Oil and Gas Corporation who immediately before July 1, 2008 were eligible employees under the THUMS Long Beach Company Savings and Investment Plan (as defined in that plan) shall be Eligible Employees under this Plan.

(5)Effective August 8, 2019, any Employee of Anadarko Petroleum Corporation who is not a citizen or legal resident of the United States and is not regularly employed at a worksite of Employer within the United States.

(ac) “Employee” means any person employed by the Company or an Affiliate.

Notwithstanding any other provision of this subsection, no individual shall be an Employee if such individual is not classified as a common-law employee in the employment records of the Company or an Affiliate, without regard to whether the individual is subsequently determined to have been a common-law employee of the Company or an Affiliate. The persons excluded by this paragraph from being Employees are to be interpreted broadly to include and to have at all times included individuals engaged by the Company or an Affiliate to perform services for such entity in a relationship that the entity characterizes as other than an employment relationship, such as where the Company or the Affiliate engages the individual to perform services as an independent contractor or leases the individual’s services from a third party. The exclusion of the individual from being an Employee shall apply even if a determination is subsequently made by the Internal Revenue Service, another governmental agency, a court or other tribunal, after the individual is engaged to perform such services, that the individual is an Employee of the Company or Affiliate for purposes of pertinent Code sections or for any other purpose.

(ad)“Employer” means the Company and any Affiliate which is designated, in accordance Article 14, by the Board or, if authorized by the Board, the Administrative Committee and which adopts the Plan. Affiliates which are not corporations are not eligible to be Employers under the Plan.

(ae)“ESOP” means, as further described in Plan section 1.3:

(1)Between June 1, 2002 and July 18, 2007, the portion of the Plan comprised of the Matching Accounts, or portions thereof, invested in the Oxy Stock Fund under the Plan, at any point in time and in the aggregate, and

(2)On or after July 19, 2007, the Oxy Stock Fund, at any point in time and in the aggregate.

(af)“Excess Aggregate Contribution” means the amount contributed by or on behalf of a Highly Compensated Employee in excess of the ACP Test limit, as specified in Plan section 6.5.

(ag)“Excess Contribution” means the amount deferred by a Highly Compensated Employee in excess of the ADP Test limit, as specified in Plan section 6.3.

(ah)“Excess Deferral” means the amount deferred by a Participant on a Pre-Tax or Roth basis in excess of the dollar limit specified in Plan section 6.1.

(ai)“ERISA” means the Employee Retirement Income Security Act of 1974, as from time to time amended. Each ERISA reference in this Plan shall be deemed to include reference to any comparable or succeeding statutory provision which supplements or replaces such ERISA reference.

(aj) “Fiduciary Appointment Officer” means the Vice President of Human Resources of the Company (or the successor to such position) or his or her designee.

(ak)“Former Participant” means an Active Participant or Inactive Participant who has had a Separation from Service, but whose Account has not been fully distributed.

(al)“Highly Compensated Employee” means an Employee described in Code section 414(q) and includes any Employee who:

(1)Was a 5-percent owner (as defined in Code section 416(i)(1)(B)(i)) at any time during the Plan Year or the preceding Plan Year; or

(2)For the preceding Plan Year, received Section 415 Compensation in excess of $80,000 (as adjusted by reference to Code section 414(q)(1)) and, with respect to Plan Years commencing on and after January 1, 2020, was a member of the top- paid group during the look back year.

Employees who are nonresident aliens and who receive no U.S.-source income shall not be counted as Employees when identifying Highly Compensated Employees. In determining Highly Compensated Employees, the Administrative Committee may make any of the elections permitted under Code section 414(q), IRS Notice 97-45 and any future guidance provided by the Internal Revenue Service.

A Former Participant shall be treated as a former Highly Compensated Employee if the Participant was a Highly Compensated Employee in a separation year, as defined in Treasury Regulations section 1.414(q)–1T, Q&A 5, or after the date on which the participant attained age 55.

The top-paid group consists of the top 20% of Employees ranked on the basis of Section 415 Compensation received during the look-back year. For purposes of determining the number of Employees in the top-paid group, the following shall be excluded: (A) any Employee who is a nonresident alien with respect to the United States who receives no income with a source within the United States from the Company or any Affiliate; (B) any Employee who has not completed at least six (6) months of service at the end of the year; (C) any Employee who normally works less than 171/2 hours per week; (D) any Employee who normally works no more than six months during any year; and (E) any Employee who has not attained the age of twenty one (21) at the end of the year.

(am)“Inactive Participant” means an Employee who was an active Participant but who is transferred to and is in a position of employment where he is no longer an Eligible Employee, as described in Plan section 3.3(b).

(an)“In-Plan Roth Rollover Account” means the recordkeeping account which evidences the value of In-Plan Roth Rollover Contributions, including gains and losses of the Trust Fund.

(ao)“In-Plan Roth Rollover Contributions” means the eligible contributions made at the direction of the Employee in accordance with Code section 402A(c)(4) and Plan section 7.8.

(ap)“Investment Committee” means the committee whose members are appointed by the Fiduciary Appointment Officer to administer the investments of the Plan.

(aq)“Investment Fund” means funds that have been approved by the Investment Committee for investment in the Trust Fund and includes the Oxy Stock Fund. The Investment Committee may, from time to time in its discretion and in exercise of its fiduciary responsibilities, select different funds, add to the set of available funds, close funds to new investment, or remove one or more funds (except the Oxy Stock Fund).

(ar)“Leased Employee” means any person within the meaning of Code section 414(n)(2) who is not reported on the payroll records of the Company or any Affiliate as a common law employee and who provides services to the Company or an Affiliate, but only if the services are provided under an agreement between the Company or Affiliate and a leasing organization, the person has performed services for the Company and Affiliates on a substantially full time basis for a period of at least one year, and the services are performed under the primary direction or control of the Company or Affiliate that is the service recipient.

Contributions or benefits provided to a Leased Employee by the leasing organization which are attributable to services performed for the Company and Affiliates will be treated as provided by the Company or

Affiliate. If a Leased Employee subsequently becomes an Eligible Employee, Service as a Leased Employee will be credited under the Plan to the extent required by Code section 414(n).

Notwithstanding the foregoing, an individual will not be a Leased Employee for a Plan Year for nondiscrimination testing or for any other purpose, if either paragraph

(1) or (2) is applicable to that individual for that Plan Year.

(1)The individual is covered by a money purchase pension plan meeting the requirements of Code section 414(n)(5)(B) and Leased Employees, determined without regard to the limitation in this paragraph, do not constitute more than 20% of all Non-highly Compensated Employees of the Company and all Affiliates.

(2)All requirements of this paragraph are satisfied for that Plan Year and each previous Plan Year with respect to which Code section 414(n) was effective with respect to the Company or any Affiliate.

(A)The Qualified Plans of the Company and all Affiliates exclude Leased Employees from participation and no such Qualified Plan is top-heavy (within the meaning of Code section 416);

(B)The number of leased persons, providing services to the Company and all Affiliates during the Plan Year, is less than 5% of the number of Employees (excluding such leased persons and Highly Compensated Employees) covered by any Qualified Plan maintained by the Company or any Affiliate at any time during such Plan Year. An individual is a leased person for this purpose if all of the following requirements are satisfied:

(i)During the Plan Year, the individual performs any services for the Company or any Affiliate, other than as an Employee, and the requirements of Code section 414(n)(2)(A) (relating to performing

services pursuant to an agreement with the Company or any Affiliate) and Code section 414(n)(2)(C) (relating to performing services under the primary direction or control of the Company or any Affiliate) are satisfied.

(ii)During the Plan Year, the individual is credited with at least

1,500 hours of service, including service performed as an Employee and in any other capacity. For purposes of this subparagraph, “hours of service” has the same meaning as the term “hour of service” provided by Department of Labor Regulations section 2530.200b-2. If one of the equivalencies set forth in Department of Labor Regulations section

2530.200b-3 is used, such equivalency shall be used on a reasonable and consistent basis and the 1,500-hour requirement must be adjusted accordingly. With respect to determining whether an individual has satisfied the 1,500-hour requirement, reasonable approximations may be made.

(iii)The individual either:

(I)Is not covered under a Qualified Plan as an Employee at any time during the Plan Year; or

(II)Performs at least 501 hours of service (reasonably adjusted if one of the equivalencies set forth in Department of Labor Regulations section 2530.200b–3 is used) for the Company or any Affiliate other than as an Employee.

(C)The Administrative Committee has not been notified by the leased person and provided satisfactory evidence by the leased person that he or she is a Leased Employee.

(as)“Nonhighly Compensated Employee” means an Employee who is not a Highly Compensated Employee.

(at)“Nonrepresented Employees” means any Employee who is not a Represented Employee.

(au)“Matching Account” means the recordkeeping account which evidences the value of Matching Contributions and the value of Eligible Dividends paid on Oxy Stock held in the Participant’s Matching Account, including related investment gains and losses of the Trust Fund.

(av)“Matching Contributions” means the contributions made by the Employer pursuant to Plan section 5.2 on account of Pre-Tax Deferrals, Roth Contributions or After-Tax Contributions made on behalf of or by the Participant.

(aw)“MidCon Corp. ESOP” means the MidCon Corp. Employee Stock Ownership Plan as effective November 20, 1996.

(ax)“Oxy Stock” means the common stock of Occidental Petroleum Corporation, which is the class of stock having the greatest voting power and dividend rights. Oxy Stock is readily tradable on established securities market within the meaning of Treasury Regulation section 1.401(a)(35)-1(f)(5) for purposes of Code sections 401(a)(22), 401(a)(28)(C), 409(h)(1)(B), 409(l) and 1042(c)(1)(A).

(ay)“Oxy Stock Fund” means the Investment Fund that is invested primarily in Oxy Stock and such short-term interest-bearing securities as the Investment Committee or the Trustee considers advisable.

(az)“Participant” means an Active Participant, Inactive Participant, or a Former Participant, as applicable.

(ba)“Plan Administrator” for purposes of ERISA and the Code means the Administrative Committee.

(bb)“Plan Amendment Officer” means the person designated by the Board to serve in such capacity.

(bc)“Plan Year” means the calendar year.

(bd)“Pre-Tax Account” means the recordkeeping account which evidences the value of Pre- Tax Deferrals, including related investment gains and losses of the Trust Fund.

(be)“Pre-Tax Deferrals” means the contributions made by the Employer on behalf of the Participant on a Pre-Tax basis as elected by the Participant pursuant to Plan section 4.1.

(bf)“Pre-Tax Spending Program” means the Occidental Petroleum Corporation Flexible Spending Accounts Plan.

(bg)“Qualified Domestic Relations Order” means a qualified domestic relations order, within the meaning of Code section 414(p), which creates or recognizes the existence of an Alternate Payee’s right to, or assigns to an Alternate Payee the right to, receive all or a portion of the benefits payable to a Participant.

(bh)“Qualified Plan” means a plan, other than this Plan, which is qualified under Code section 401(a).

(bi)“Represented Employee” means any Employee, whose employment is subject to a collective bargaining agreement.

(bj)“Retirement Plan” means the Occidental Petroleum Corporation Retirement Plan.

(bk)“Rollover Account” means the recordkeeping account which evidences the value of Rollover Contributions, including related investment gains and losses of the Trust Fund.

(bl)“Rollover Contributions” means the eligible pre-tax contributions made at the direction of the Employee pursuant to Plan section 10.12.

(bm)“Roth Account” means the recordkeeping account which evidences the value of Roth Contributions, including related investment gains and losses of the Trust Fund, but excluding any forfeitures.

(bn)“Roth Contributions” means the contributions made by the Employer on behalf of the Participant on an after-tax basis as elected by the Participant pursuant to Plan section 4.1. A Participant’s Roth Contributions will be separately accounted for, as will gains and losses attributable thereto, in a

separate account. Roth Contributions are not considered After-Tax Contributions for Plan purposes.

(bo)“Roth Rollover Account” means the recordkeeping account which evidences the value of Roth Rollover Contributions, including related investment gains and losses of the Trust Fund.

(bp)“Roth Rollover Contributions” means an eligible rollover contribution of any payment or distribution from another Roth rollover account of the Employee. A Participant’s Roth Rollover Contributions will be maintained in a separate account which includes any earnings properly allocable to such contributions and that will have separate recordkeeping.

(bq)“Separation from Service” means any termination of the employment relationship between an Employee and the Company and all Affiliates. A Separation from Service shall be deemed to occur upon the earlier of:

(1)The date upon which the Employee quits, is discharged, is laid off, incurs a Disability, or dies; or

(2)The first anniversary of the first day of a period in which the Employee is (and remains) absent from the Service for any reason (such as paid time off, vacation, sickness, or approved leave of absence) not enumerated in

paragraph (1), provided that if an Employee is granted a leave of absence but fails to return to employment at the end of the leave period, Separation from Service will be deemed to have occurred upon the date the Employee was originally granted a leave of absence.

(3)Notwithstanding paragraph (2), the Separation from Service date of an Employee who is absent from Service beyond the first anniversary of the first day of absence by reason of a maternity or paternity leave is the second anniversary of the first day of such absence. The period between the first and second anniversaries of the first day of absence from work is neither a period of Service nor a period of severance. For purposes of this paragraph, an absence from work for maternity or paternity reasons means an absence:

(A)By reason of the pregnancy of the individual;

(B)By reason of the birth of a child of the individual;

(C)By reason of the placement of a child with the individual in connection with the adoption of such child by such individual; or

(D)For purposes of caring for such child for a period beginning immediately following such birth or placement.

Effective for distributions after December 31, 2001, a transaction constituting a severance of employment, within the meaning of Code section 401(k)(2)(B)(i)(I), with respect to an Employee shall also be deemed to be a Separation from Service.

An Employee of an Employer who transfers to an Affiliate that is not an Employer shall not be treated as having a Separation from Service. Moreover, an Employee’s date of quit or discharge shall not be deemed to occur until any periodic notice payments, short-term disability payments, or weekly sickness and accident payments cease.

An Employee who is on leave of absence in order to serve the Armed Forces of the United States shall not have a Separation from Service unless the Employee fails to report for work at the end of such leave and prior to expiration of the period in which the Employee has reemployment rights under law. The absence of any Employee who fails to return to work within the allotted time shall be subject to the provisions of paragraph (2).

(br)“Service” means the periods of employment credited using the elapsed time method described to an Employee under Plan section 3.4.

(bs)“Section 415 Compensation” means, with respect to a Participant for the period specified, the total cash and non-cash remuneration paid to a Participant by the Employer or an Affiliate, determined as follows:

(1)Section 415 Compensation includes all amounts described in Treasury Regulations section 1.415–2(d)(2), including:

(A)All wages; bonuses; other amounts received (without regard to whether the amount is paid in cash) for personal services actually rendered in the course of employment with the Company or any Affiliate, to the extent that the amounts are includible in gross income for federal income tax purposes and for which the Company or Affiliate is required to furnish to the Participant a written statement under Code sections 6041(d), 6051(a)(3), and 6052;

(B)Amounts paid or reimbursed by the Company or Affiliate for moving expenses incurred by the Participant, but only to the extent that at the time of the payment it is reasonable to believe that these amounts are not deductible by the Participant under Code section 217; and

(C)The value of a nonqualified stock option granted to the Participant by the Company or Affiliate, but only to the extent that the value of the option is includible in the gross income of the Participant, for federal income tax purposes, for the taxable year in which granted.

(2)In addition, Section 415 Compensation includes all of the following:

(A)The Participant’s Pre-Tax Deferrals, Roth Contributions and Catch-Up Contributions for the Plan Year;

(B)Elective contributions that are excluded from the Participant’s gross income under a Code section 125 cafeteria plan maintained by the Participant’s Employer, such as the Pre-Tax Spending Program; and

(C)Any elective deferral, as defined in Code section 402(g)(3), made under a plan maintained by the Company or any Affiliate, and any amount which is contributed to or deferred by the Company or any Affiliate at the election of the Participant and which is not includible in the gross income of the Participant by reason of Code sections 125, 132(f)(4), 408(k), or 457.

(D)Effective July 1, 2006, Section 415 Compensation includes remuneration paid by the later of 21/2 months after an Employee’s Separation from Service or the end of the Plan Year that includes the date of the Employee’s Separation from Service with the Company or an Affiliate, if:

(i)The payment is regular compensation for services during the Employee’s regular working hours, or compensation for services outside the employee’s regular working hours (such as overtime or shift differential), commissions, bonuses, or other similar payments, and, absent a Separation from Service, the payments would have been paid to the Employee while the Employee continued in employment with the Company or an Affiliate;

(ii)The payment is for unused accrued bona fide sick, paid time off, vacation or other leave that the Employee would have been able to use if there had not been a Separation from Service;

(iii)The payment is to an individual who does not currently perform services for the Company or any Affiliate by reason of qualified military service (within the meaning of Code section 414(u)(1)) to the extent the payment does not exceed the amount the individual would have received if the individual had continued to perform services for the Company or an Affiliate rather than entering qualified military service; or

(iv)Compensation paid to a Participant who is permanently and totally disabled (as defined in Code section 22(e)(3)),

provided that salary continuation applies to all Participants who are permanently and totally disabled for a fixed or determinable period.

Any payment not described above shall not be considered Section 415 Compensation if paid after a Separation from Service, even if paid by the later of 21/2 months after the Separation from Service or the end of the Plan Year that includes the Separation from Service. Back pay shall be treated as Section 415 Compensation for the Plan Year to which the back pay relates to the extent the back pay represents wages and compensation that would otherwise be included under this definition.

(3)However, Section 415 Compensation excludes all amounts described in Treasury Regulations section 1.415–2(d)(3), including the following amounts:

(A)Any contributions made by the Company or any Affiliate to a plan of deferred compensation to the extent that, before the application of the limitations of Code section 415 to that plan, the contributions are not includible in the gross income of the employee for the taxable year in which contributed;

(B)Distributions from a plan of deferred compensation, regardless of whether such amounts are includible in the gross income of the employee when distributed; provided, however, that distributions from and any amounts received by the Participant pursuant to an unfunded nonqualified plan are included in Section 415 Compensation in the year the amounts are includible in the gross income of the Participant;

(C)Amounts realized from the exercise of a nonqualified stock option, or when restricted stock or property held by the Participant either becomes freely transferable or is no longer subject to a substantial risk of forfeiture;

(D)Amounts realized from the exercise of an incentive stock option, as defined in Code section 422, or the sale, exchange, or other disposition (including a disqualifying disposition) of stock acquired through the exercise of an incentive stock option;

(E)Amounts realized from the sale, exchange, or other disposition of stock acquired under an employee stock purchase plan, as defined in Code section 423; and

(F)Other amounts which receive special tax benefits, such as premiums for group- term life insurance, but only to the extent that the premiums are not includible in the gross income of the employee for federal income tax purposes.

(bt)“Spouse” means the individual of the opposite sex and, effective as of June 26, 2013, also includes an individual of the same sex, to whom a Participant is married, where the marriage was valid at the time the marriage ceremony was performed, in a state or foreign jurisdiction (the “Jurisdiction”) having legal authority to sanction such marriage, provided that such marriage has not subsequently been legally dissolved. For purposes of the Plan, such a marriage shall be treated as valid even if the couple is domiciled in a Jurisdiction that does not recognize the validity of the marriage. Notwithstanding the foregoing, for the period beginning June 26, 2013 and ending September 15, 2013, the Plan may be administered to recognize only those marriages between members of the same sex where the couple was domiciled in a Jurisdiction where the validity of the marriage was recognized during such period. For purposes of the Plan, the term “marriage” does not include a registered domestic partnership, civil union or other similar formal relationship recognized under the laws of a Jurisdiction but which is not recognized as a marriage under that Jurisdiction, even if state law provides that persons in these relationships have the same rights, protections, and benefits, under state law, as married persons.

(bu)“Stable Value Fund” means the fund selected by the Investment Committee that is invested in stable value contracts which state a given interest rate to be paid on account balances.

(bv)“Supplemental Plan Participant” means a Participant in this Plan who is or was also a participant in the Occidental Petroleum Corporation Supplemental Retirement Plan, effective through December 31, 2004, or the Occidental Petroleum Corporation Supplemental Retirement Plan II, effective as of January 1, 2005, as determined under Appendix F to this Plan.

(bw)“Testing Compensation” means, for purposes of the ADP Test and ACP Test, compensation within the meaning of Code section 414(s)(1), except that the Administrative Committee may elect not to include in such compensation any amount which is contributed by the Employer pursuant to a salary reduction agreement and which is not includible in gross income of the Employee under Code section 125, 132(f)(4), 402(e)(3), 402(h), or 403(b).

(bx)“Total Excess Aggregate Contributions” means the total amount of Excess Aggregate Contributions to be corrected to satisfy the ACP Test for the Plan Year as determined under Plan section 6.5(b).

(by)“Total Excess Contributions” means the total amount of Excess Contributions to be corrected to satisfy the ADP Test for the Plan Year as determined under Plan section 6.3(b).

(bz)“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury under the Code.

(ca)“Trust Agreement” means any agreement in the nature of a trust established to form a part of the Plan to receive, hold, invest, and dispose of the Trust Fund.

(cb)“Trust Fund” means the assets of every kind and description held under any Trust Agreement forming a part of the Plan.

(cc)“Trustee” means any person selected by the Company to act as Trustee under any Trust Agreement at any time of reference. On and after March 25, 2020, the Administrative Committee shall have the authority to select the Trustee in accordance with the applicable provisions of this Plan, including Article 12.

(cd)“Unit” means the unit of measure into which each Investment Fund is divided for purposes of ascertaining the share of each such fund attributable to each Participant, Beneficiary and Alternate Payee.

2.2 Gender and Number

Except as otherwise indicated by the context, any masculine or feminine terminology shall also include the opposite gender, and the definition of any term in the singular or plural shall also include the opposite number.

2.3 Headings

The headings of this Plan are inserted for convenience or reference only, and they are not to be used in the construction of the Plan.

2.4 Requirement to Be in “Written Form”

Various notices provided by the Company, the Administrative Committee, or the Investment Committee and various elections made by a Participant, Spouses, Alternate Payees and Beneficiaries are required to be in written form. Notwithstanding anything to the contrary in this Plan, any notices and elections related to the Plan may be conveyed through an electronic system or any other system approved by the Administrative Committee unless otherwise provided under applicable law or regulatory guidance. Any such notices, forms, and elections provided or made through an electronic medium shall comply with the provisions of Treasury Regulations section 1.401(a)-21.

2.5 Severability

If a provision of this Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included in the Plan.

2.6 Applicable Law

To the extent not preempted by ERISA or other federal law, the Plan and all rights hereunder shall be governed, construed, and administered in accordance with the laws of the State of Texas with the exception that any Trust Agreement shall be construed and enforced in all respects under and by the laws of the state in which the Trustee thereunder is located.

Article 3. Participation, Service and Vesting

3.1 Date of Participation

Each Eligible Employee shall become an Active Participant as of the first day of the month in which the Employee becomes an Eligible Employee. Notwithstanding the foregoing, each Employee who becomes an Eligible Employee pursuant to a purchase or other agreement approved by the Board shall become an Active Participant as of the date, if any, specified in such agreement. A Covered Employee will be notified that he or she is eligible to participate in the Plan at the time he or she becomes an Eligible Employee. If the Covered Employee does not make an affirmative election not to participate in the Plan or return an alternative election pursuant to section 4.1 of the Plan, then Pre-Tax Deferrals will automatically begin to be made on such Covered Employee’s behalf as described in section 4.6 of the Plan.

3.2 Duration

An Eligible Employee who becomes an Active Participant shall remain an Active Participant for as long as he remains an Eligible Employee or is entitled to receive any contributions or benefits hereunder.

3.3 Transfers

(a)Transfers to Eligible Employee Status. An Employee who transfers to employment as an Eligible Employee shall become an Active Participant on the first day of the month in which such transfer takes place.

(b)Transfers from Eligible Employee Status. A Participant who transfers to employment status where he or she no longer is an Eligible Employee shall become an Inactive Participant.

(1)An Inactive Participant is not eligible to make or receive Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions, After-Tax Contributions (including Adjustment Contributions) or Matching Contribution on Earnings paid after the date of transfer to an ineligible status.

(2)An Inactive Participant shall continue to accrue Service under this Plan. Upon Separation from Service, the Participant’s vested interest shall be based on total Service with the Company and all Affiliates.

(3)An Inactive Participant remains eligible to receive in-service withdrawals, subject to the terms of Plan section 7.2, plan loans, subject to the terms of Article 8, and to transfer eligible amounts to his or her Rollover Account, Roth Rollover Account or After-Tax Rollover Account, subject to the terms of Plan section 10.12.

3.4 Service

Service is used to determine a Participant’s vested percentage in his or her Matching Account.

(a)General Rules. An Employee shall be credited with Service on an elapsed time basis for the period during which the employment relationship exists between the Employee and the Company or any Affiliate, the length of which shall be determined, in completed years and months, during the following periods of time:

(1)Credit shall be given to an Employee for the period of time beginning on the first day of the month in which the individual first becomes an Employee and ending on the last day of the month in which occurs the Employee’s Separation from Service.

(2)Credit shall be given to an Employee for each period beginning upon the date the individual has a Separation from Service and ending upon the first day of the month in which the individual first becomes an Employee thereafter but only if the Employee is reemployed within 12 months of the date of such Separation from Service.

(3)Credit shall be given to an Employee after a Separation from Service for any period beginning on the first day of the month in which the Employee first becomes an Employee after rehire and ending on the last day of the month the Employee has a Separation from Service thereafter.

(4)Whenever the total number of years of Service of an Employee must be ascertained under this Plan, all noncontinuous periods of Service which are credited to such Employee shall be aggregated, regardless of the length or any period of Service and regardless of the length of any period between a Separation from Service and rehire. For purposes of aggregating such years of Service, the completed years and months credited to an Employee during any period of Service shall be added to the number of completed years and months credited to the Employee during any other period of noncontinuous Service. This Plan does not disregard periods of Service, even though permitted to do so under Code section 411(a)(6).

(5)Service by any Leased Employee shall be credited under this section should the Leased Employee ever become an Eligible Employee under this Plan.

(b)Special Rules. For purposes of determining an Employee’s Service under this Plan, the special Service counting rules set forth in Appendix B shall apply to increase, but not decrease, the Service of any Employee.

3.5 Vesting

(a)Employee Accounts. A Participant’s interest in his or her Pre-Tax Account, Roth Account, After-Tax Account, Rollover Account, Roth Rollover Account,

After-Tax Rollover Account and In-Plan Roth Rollover Account shall be fully vested at all times.

(b)Matching Account. A Participant’s interest in his or her Matching Account shall become vested in accordance with this section, if not vested earlier under the special vesting rules of subsection (c).

(1)Unless vested earlier under the provisions of this section, a Participant shall vest in his or her Matching Account based on the Participant’s completed years of Service.

(A)Effective January 1, 2007, a Participant who is first employed by a Company or any Affiliate after 2006, shall have no nonforfeitable right to his or her Matching Account until the Participant completes three years of Service and shall be 100 percent vested in his or her Matching Account when the Participant is credited with three or more years of Service.

(B)Effective January 1, 2007, a Participant who was first employed by the Company or any Affiliate before 2007, shall have the nonforfeitable percentage of his Matching Account determined based on the following table:

Years of Service	Percentage Vested
Less than 1	0%
1	20%
2	40%
3	100%

(C)Effective January 1, 2015, an Active Participant, irrespective of when he or she was first employed by the Company or an Affiliate, shall be 100 percent vested in his or her Matching Account.

(2)Furthermore, a Participant shall become fully vested in his or her Matching Account to the extent required under Code section 411(d)(3) and Plan section 13.2 upon a complete termination of the Plan, a partial termination of the Plan affecting the Participant, or upon a complete discontinuance of contributions to the Plan.

(c)Special Vesting Rules.

(1)Notwithstanding the foregoing, a Participant described in Appendix C shall vest in his or her Matching Account under the provisions of that Appendix C, rather than subsection (b).

(2)A Participant shall at all times be fully vested in any Eligible Dividends with respect to which the Participant is offered a dividend pass-through deduction to the extent required under Plan section 11.2(d)(3). These amounts will be held in either:

(A)The Participant’s Matching Account, or

(B)The Participant’s Pre-Tax Account, Roth Account, After-Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account, in which the Participant is always fully vested, based on the account from which the Eligible Dividend is derived.

(3)With respect to any frozen contributions under this Plan or any Qualified Plan that is merged into this Plan, if such contributions resume under this Plan or any Qualified Plan into which this Plan is merged, then for purposes of determining the Participant’s nonforfeitable right to such contributions, a Participant shall receive credit for Service incurred both prior to and subsequent to the date such contributions were frozen.

(d)Vesting and Benefit Payments. Being vested does not mean that a Participant is entitled to immediate distribution benefits. Benefits under the Plan shall be paid only in accordance with Article 7.

3.6 Forfeiture of Contingent Interests

Any portion of a Participant’s Account that is not vested under the provisions of Plan section 3.5 shall be forfeited upon the first to occur of the following forfeitable events:

(a)The Participant elects, in accordance with Plan section 7.3, to commence or receive a distribution of the value of the Participant’s vested Account on account of a Separation from Service. For this purpose, if the percentage vested in the table under Plan section 3.5(b)) is zero, the Participant will be deemed to have elected such a distribution and the nonvested portion of the Account will be immediately forfeited.

(b)The Participant incurs five consecutive breaks in service. For this purpose, a break in service is a period of 12 months in which the Participant is absent from Service, except that if the absence is due to a maternity or paternity reason described in Plan section 2.1(qqq)(3), the period between the first and second anniversaries of such absence shall be neither a period of Service nor a period of severance.

If the Participant who has forfeited his non-vested Account resumes employment as an Eligible Employee, then the cash value (determined at the time of forfeiture) of the amount forfeited shall be restored to the Participant’s Account. No buyback shall be

required and the reinstatement will occur regardless of the length of the Participant’s absence from Service.

Article 4. Active Participant Contributions

4.1 Pre-Tax Deferrals, Roth Contributions and After-Tax Contributions

(a)Covered Employees will be automatically enrolled in the Plan as described in Plan section

4.6 below.

(b)Except as otherwise provided in this Plan, each Active Participant may elect to contribute as After-Tax Contributions or to have the Employer contribute on the Participant’s behalf as Pre-Tax Deferrals and Roth Contributions an amount of the Participant’s Base Pay up to the contribution percentage limit specified for the Active Participant in Appendix D for the Plan Year. The Administrative Committee may adjust the contribution percentage limit specified in Appendix D at the beginning of each Plan Year without the need of a formal Plan amendment, provided that any such limitations shall be communicated to eligible Participants in advance of the pay periods to which such limitations will apply. The percentage elected of Pre-Tax Deferrals, Roth Contributions and/or After-Tax Contributions may be in increments and subject to the rules, restrictions, and limitations and in the form set forth by the Administrative Committee.

The Participant’s separately elected Pre-Tax Deferral, Roth Contribution and After-Tax Contribution percentages shall apply, but not in excess of an aggregate of 5 percent, to the Active Participant’s Annual Bonus. The Annual Bonus shall be counted for this purpose in the Plan Year it is paid even if it is received for services performed in a prior Plan Year. Effective January 1, 2017, unless the Participant affirmatively elects otherwise, with respect to any Participant hired prior to August 5, 2016, the election in effect as of August 5, 2016 will apply to any Annual Bonus paid in the 2017 Plan Year and any subsequent plan year until the Participant affirmatively elects otherwise.

(c)Notwithstanding anything in this Plan to the contrary, no Participant shall be permitted to have elective deferrals made under this Plan, or any other Qualified Plan maintained by the Company or Affiliates during any taxable year, in excess of the dollar limitation contained in Code section 402(g)(1) in effect for such taxable year, except to the extent permitted under Code section 414(v).

(d)No benefits other than Matching Contributions shall be conditioned on a Participant’s election to make After-Tax Contributions or have Pre-Tax Deferrals and Roth Contributions made on the Participant’s behalf under this Plan. Any portion of a contribution that is not designated as a Pre-Tax Deferral, Roth Contribution or Catch-Up Contribution shall be designated as an After-Tax Contribution.

(e)The Participant’s election made under this section shall be made in accordance with the rules set forth in this Article and such other rules of nondiscriminatory

application as the Administrative Committee may prescribe for the proper administration of the Plan.

4.2 Catch-Up Contributions

Each Active Participant who will have attained age 50 before the close of the Plan Year shall be eligible to make Catch-Up Contributions in accordance with and subject to the limitations of Code section 414(v) for pay periods ending after July 1, 2002. Each Participant must elect whether such Catch-Up Contributions will be in the form of Pre-Tax Deferrals or Roth Contributions.

(a)Catch-Up Contributions shall not be taken into account for purposes of the provisions of Plan sections 6.1 and 6.6, implementing the required limitations of Code sections 402(g) and 415, respectively.

(b)The Plan shall not be treated as failing to satisfy the provisions of the Plan sections 6.2, 6.4, or Article 15, implementing the requirements of Code section 401(k)(3), 401(k)(11), 401(k)(12), 410(b), or 416, as applicable, by reason of the making of Catch-Up Contributions.

(c)Elections to make Catch-Up Contributions shall be made separately from the Active Participant’s election of Pre-Tax Deferrals or Roth Contributions under Plan section 4.1, shall not be subject to the contribution percentage limit on Pre-Tax Deferrals and Roth Contributions specified in Plan section 4.1, and shall be made in accordance with uniform procedures established by the Administrative Committee. Such election procedures will require the eligible Active Participant to elect Catch-Up Contributions as a fixed dollar amount per pay period.

(d)Under no circumstances will Catch-Up Contributions elected under this Plan section entitle the Participant to Matching Contribution, even if it is later determined that the contribution is not a Catch-Up Contribution because it is less than an applicable limit.

(e)For purposes of recordkeeping and communications with Participants, Catch-Up Contributions, Pre-Tax Deferrals and Roth Contributions may be aggregated and reported as held in the Participant’s Pre-Tax Account or Roth Account, as applicable, without changing the character of any Catch-Up Contributions as such for purposes of Code section 414(v).

4.3 Election Procedures

(a)Each Active Participant shall be permitted to make the elections described in Plan section

4.1 and, if eligible, Plan section 4.2 in the manner prescribed by the Administrative Committee. If a Participant has elected to begin, stop, increase, or decrease Pre-Tax Deferrals, Roth Contributions, After-Tax Contributions or, if eligible, Catch-Up Contributions, the Active Participant may file a new election in the manner prescribed by the Administrative Committee to change Pre-Tax Deferrals, Roth Contributions, After-Tax Contributions or, if eligible, Catch-Up Contributions at any time and such election shall become effective on

the first pay period following the date on which the election is properly received. The election shall remain in effect until changed by the Active Participant or until he or she ceases to be an Active Participant or goes on an unpaid leave of absence.

(b)If an Active Participant becomes an Inactive Participant or Former Participant, or goes on unpaid leave of absence, any Pre-Tax Deferrals, Roth Contributions, After-Tax Contributions and Catch-Up Contributions for the Participant shall cease. If the individual again becomes an Active Participant or returns from an unpaid leave of absence, he or she may make a new election under this section.

(c)All elections shall apply to Earnings paid in the first available payroll period following the date the election is processed and shall be irrevocable for such period. In addition, except for occasional, bona fide administrative considerations, Pre-Tax Deferrals, Roth Contributions and Catch-Up Contributions made pursuant to such elections cannot precede the earlier of the performance of services relating to the Pre-Tax Deferrals, Roth Contributions or Catch-Up Contributions and the date when the Earnings subject to the election would be currently available to the Participant in the absence of an election to defer.

4.4 Salary Reduction

Each Active Participant who makes a Pre-Tax Deferral or Roth Contribution election described in Plan section 4.1 or, if eligible, a Catch-Up Contribution election described in Plan section 4.2 shall, by the act of making such election or elections, have his or her Earnings reduced by an equivalent amount for so long as the election remains in effect.

4.5 Deposit and Crediting of Deferrals and Contributions

Pre-Tax Deferrals, Roth Contributions, After-Tax Contributions, and Catch-Up Contributions shall be transferred to the Trust Fund as soon as reasonably practicable after the payroll payment date at which a corresponding amount would have been paid to the Participant in the absence of the election of such contributions. Pre-Tax Deferrals shall be allocated to the Participant’s Pre-Tax Account; Roth Contributions shall be allocated to the Participant’s Roth Account; Catch-Up Contributions shall be allocated to the Participant’s Pre-Tax Account and/or Roth Account, as applicable, and After-Tax Contributions shall be allocated to the Participant’s After-Tax Contribution Account as of the payroll payment date on which the corresponding amount would have been paid in absence of the elections under Plan section 4.1 and, if applicable, Plan section 4.2, but shall share in any investment gains and losses only after they are received by the Trust Fund.

4.6 Eligible Automatic Enrollment Arrangement

(a)Effective Date. The following automatic enrollment procedures will apply with respect to all Covered Employees. All Covered Employees hired prior to October 8, 2019, who have not made an affirmative election under Plan section 4.1 to make deferrals or contributions to the Plan equal or greater than the Default Percentage (defined below) will be automatically enrolled in

accordance with the following automatic enrollment procedures on November 15, 2019. For Plan Years beginning after December 31, 2019, the procedures set forth in this Plan section 4.6 are intended to constitute an eligible automatic contribution arrangement that satisfies Code section 414(w) and provides excise tax relief with respect to excess amounts distributed within 6 months after the end of the plan year under Code section 4979(f).

(b)Default Percentage. A Covered Employee will have a reasonable opportunity after receipt of the automatic enrollment notice to make an alternate election. If a Covered Employee fails to make an alternate election, Pre-Tax Deferrals will automatically begin being made on such Covered Employee’s behalf, in an amount equal to 5% of his or her Base Pay (i.e., the “Default Percentage”) on the Covered Employee’s date of hire.

(c)Alternate Election. In the event a Covered Employee does not desire to have Pre-Tax Deferrals made on his or her behalf at the Default Percentage, the Covered Employee may elect a different amount up to the contribution percentage limit specified for the Active Participant in Appendix D for the Plan Year or elect to not participate in the Plan. Any alternate election is to be made in accordance with the election procedures set forth in Section 4.3 above.

(d)Withdrawal. No later than 30 days after default Pre-Tax Deferrals are first withheld from a Covered Employee’s Base Pay, the Covered Employee may request a distribution of his or her default Pre-Tax Deferrals. The amount to be distributed from the Plan upon the Covered Employee’s request is equal to the amount of default Pre-Tax Deferrals made through the earlier of (a) the pay date for the second payroll period that begins after the Covered Employee’s withdrawal request and (b) the first pay date that occurs 30 days after the Eligible Employee’s request, plus attributable earnings through the date of distribution. Unless the Covered Employee affirmatively elects otherwise, any withdrawal request will be treated as an affirmative election to cease default Pre-Tax Deferrals made on the Covered Employee’s behalf. Default Pre-Tax Deferrals distributed pursuant to this Section 4.6(d) are not counted towards the Code section 402(g) limit. Matching Contributions that might otherwise be allocated to a Covered Employee’s Account on behalf of default Pre-Tax Deferrals will not be allocated to the extent the Covered Employee withdraws such default Pre-Tax Deferrals pursuant to this Section 4.6(d) and any Matching Contributions already made on account of such default Pre-Tax Deferrals that are later withdrawn pursuant to this Section 4.6(d) will be forfeited and subject to allocation as a forfeiture.

(e)Notices. For Plan Years beginning after December 31, 2019, the Company will provide Covered Employees with the notice required under Code section 414(w)(4) describing the Plan’s automatic enrollment procedures prior to the beginning of each Plan Year regardless of whether the Covered Employee has an affirmative election for Pre-Tax Deferrals in place.

Article 5. Employer Contributions

5.1 Employees Eligible for Matching Contributions

Subject to the other provisions of this Plan, the Employer shall contribute Matching Contributions to this Plan only for a Participant who was an Active Participant during the pay period for which the corresponding Pre-Tax Deferrals and/or Roth Contributions (including amounts recharacterized as Adjustment Contributions) or After-Tax Contributions were made. Notwithstanding any Plan provision to the contrary, any Matching Contribution (including any investment gain attributable thereto), which relates to an Excess Deferral under Plan section 6.1, Excess Contribution under Plan section 6.3 (unless recharacterized as Adjustment Contributions) or Excess Aggregate Contribution under Plan section 6.5 shall be forfeited and shall not be treated as a Matching Contribution with respect to the Participant for the Plan Year.

5.2 Amount of Matching Contributions

Matching Contributions shall be made on behalf of an Active Participant for each payroll period for which Pre-Tax Deferrals, Roth Contributions or After-Tax Contributions were made with respect to the Participant for the Plan Year. Matching Contributions may also be made on behalf of eligible Participants, as the Employer or Administrative Committee deems necessary or appropriate for administrative purposes, at such other times, but not later than 12 months after the end of the Plan Year. The amount of Matching Contributions allocated to the Participant’s Matching Contributions Account shall be equal to the matching percent shown in the table in Appendix E, based on the employment classification of the Participant on the last day of the payroll period, multiplied by the Pre-Tax Deferrals (including an Adjustment Contribution), Roth Contribution (including an Adjustment Contribution) or After-Tax Contribution made with respect to the Participant on the Participant’s first 5 percent of Base Pay and Annual Bonus for the pay period. With respect to United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, Local 12773 represented employees, the amount of Matching Contributions allocated to the Participant’s Matching Contributions Account shall be equal to the matching percent shown in the table in Appendix E, based on the employment classification of the Participant on the last day of the payroll period, multiplied by the Pre-Tax Deferrals (including an Adjustment Contribution), Roth Contributions (including an Adjustment Contribution) or After- Tax Contribution made with respect to the Participant on the Participant’s first 4 percent of Base Pay and Annual Bonus for the pay period. Effective February 29, 2016, the Matching Contributions allocated with respect to United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, Local 12773 represented employees will be the same as for other Active Participants. Effective January 1, 2016, the Matching Contributions allocated with respect to United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, Local 2154-03 represented employees will be the same as for other Active Participants. The Administrative Committee may limit the amount of Matching

Contributions made on behalf of a Participant to the extent that the Administrative Committee determines necessary to comply with the limits of Article 6.

5.3 Depositing and Crediting Matching Contributions

The Company shall make such contributions to the Trust Fund as are required by this Plan, subject to the right of the Company to discontinue the Plan. The Company shall contribute an amount which, when added to forfeitures under Plan section 11.3, is sufficient to provide the Matching Contribution allocations required by Plan section 5.2.

Matching Contributions shall be transferred to the Trust Fund as soon as reasonably practicable after the payroll payment date at which the corresponding Pre-Tax Deferrals, Roth Contributions or After-Tax Contributions would have been paid to the Participant in the absence of the election of such contributions. Matching Contributions shall be allocated to the Participant’s Matching Account as of the payroll payment date on which the corresponding amount would have been paid in absence of the Participant’s election, but shall share in any investment gains and losses only after they are received by the Trust Fund.

Article 6. Benefit Limitations

6.1 Elective Deferral Limit

(a)Dollar Limit. For any calendar year, the sum of the following items shall not exceed the elective deferral dollar limit of Code section 402(g)(1), as adjusted pursuant to Code section 402(g)(4):

(1)All Pre-Tax Deferrals and Roth Contributions (but not Catch-Up Contributions) made on behalf of an Active Participant for that calendar year; and

(2)Any other Pre-Tax or Roth contributions made for the calendar year to any Qualified Plan maintained by the Company or any Affiliate which are elective deferrals as defined in Code section 402(g)(3), but not including any such elective deferrals that are catch-up contributions under Code section 414(v).

Any amount deferred in excess of the dollar limit stated in this subsection is referred to as an Excess Deferral.

(b)Calendar Year as Participant’s Taxable Year. A Pre-Tax Deferral and Roth Contribution made on behalf of an Active Participant shall be treated as made for a calendar year, for purposes of Plan section 6.1(a)(1) if it is made on account of the Active Participant’s election to reduce Earnings that would otherwise be payable within that calendar year.

(c)Preventing Excess Deferrals. If before the end of a calendar year, the Administrative Committee determines (or the Active Participant notifies his or her Employer that he or she has determined) that Pre-Tax Deferrals and/or Roth Contributions to be made on behalf of an Active Participant for that calendar year would exceed the limits of this section or Code section 402(g), then the Administrative Committee shall take one or both of the following steps, to the extent necessary, to avoid exceeding the limits of this section or Code section 402(g):

(1)Permit an Active Participant to submit a revised election under Plan section 4.1; or

(2)Reduce Pre-Tax Deferrals and/or Roth Contributions that otherwise would be made, pursuant to the Participant’s current election, for the rest of the calendar year (and adjust the corresponding reductions in Earnings) so that the limits are not exceeded.

(d)Correcting Excess Deferrals. If Excess Deferrals have been made on the Participant’s behalf in excess of the limits of Code section 402(g), then the Excess Deferrals shall be corrected as follows:

(1)The Participant must notify the Administrative Committee, by such other means as the Administrative Committee shall prescribe, no later than March 1, immediately following the close of a calendar year, stating that the sum of the items described in subsection 6.1(a) are in excess of the limits of Code section 402(g). The notice provided by the Participant shall state the portion of such excess amount that has been allocated to this Plan as an Excess Deferral. The amount of the Excess Deferral allocated to this Plan shall not exceed the total amount of the Pre-Tax Deferrals and/or Roth Contributions (excluding Catch-Up Contributions) made on behalf of the Participant for that calendar year. The Administrative Committee may require the Participant to certify to the amount of the Excess Deferral and to provide substantiating evidence satisfactory to the Administrative Committee.

(2)If the Active Participant does not provide the notice described in paragraph (1) by the following March 1, but it is determined that Pre-Tax Deferrals and/or Roth Contributions (excluding Catch-Up Contributions) made on behalf of an Active Participant for a calendar year inadvertently exceed the limits of subsection (a), then the Excess Deferral for the calendar year shall be distributed in accordance with this subsection.

(3)The Administrative Committee shall direct the Trustee to distribute, by April 15 following the close of the calendar year, the Excess Deferral for that calendar year allocated (or deemed allocated) to the Plan by the Participant. Any Excess Deferrals shall be treated as consisting first of any Pre-Tax Deferrals made by the Participant for such Plan Year, as applicable, and second any Roth Contributions which the Participant made for the Plan Year, as applicable, except as otherwise elected by the Participant. The distributed Excess Deferral shall be withdrawn from the Investment Funds in which the Pre-Tax Account and/or Roth Account, as applicable, is then invested on a pro rata basis. The Trustee shall also distribute the net income attributable to the Excess Deferrals, as determined by the Administrative Committee in accordance with one of the methods permitted under Treasury Regulations section 1.402(g)–1(e)(5) disregarding, effective January 1, 2007, any provision of prior regulations relating to the distribution of gap period earnings. Corrective distributions under this subsection shall be coordinated with distributions of Excess Contributions under Plan section 6.3 in accordance with Treasury Regulations sections 1.401(k)–1(f)(5) and 1.402(g)–1(e)(6). Any Matching Contributions that have been made with respect to Excess Deferrals that are distributed to a Highly Compensated Employee, in accordance with this subsection, shall be forfeited, as soon as is practicable after corrective distributions are made. Such Matching Contributions shall be forfeited, whether or not the Participant would

otherwise have a vested interest in those Matching Contributions, pursuant to Plan section 3.5.

6.2 Discrimination Limits on Pre-Tax Deferrals and Roth Contributions

As of the last day of each Plan Year, the Administrative Committee shall require testing of Pre-Tax Deferrals and Roth Contributions made for the Plan Year to assure that the Actual Deferral Percentage (ADP) for the Plan Year of Participants who are Highly Compensated Employees does not exceed the ADP Test limits specified in this Plan section.

(a)Aggregation, Disaggregation and Restructuring. The rules of this section shall be administered so as to comply with the mandatory disaggregation requirements of Treasury Regulations section 1.410(b)-7(c) and, if the Administrative Committee chooses, the permissive aggregation rules of Treasury Regulations section 1.410(b)-7(d), provided that any aggregated plans shall use the same testing method under Treasury Regulations section 1.401(k)-2(a)(2)(ii) (i.e., current year or prior year testing method) as is used by the Plan for the Plan Year. Notwithstanding the foregoing, effective January 1, 2004, the mandatory disaggregation rules relating to the ESOP and non-ESOP portions of the Plan shall not apply.

(1)To the extent required by the mandatory disaggregation rules, Represented Employees and Nonrepresented Employees shall be treated as comprising separate plans for purposes of applying the ADP Test. Notwithstanding the foregoing, the Administrative Committee may treat two or more separate collective bargaining units as a single collective bargaining unit for purposes of applying the ADP Test, provided that the combinations of units are determined on a basis that is reasonable and reasonably consistent from Plan Year to Plan Year.

(2)If, after application of the mandatory disaggregation rules, this Plan is permissively aggregated with one or more other plans that include qualified cash or deferred arrangements for purposes of Code section 401(a)(4) or 410(b), then the cash or deferred arrangements of this Plan and such other plans shall be treated as one arrangement for purposes of this Plan section.

(3)In determining whether the restrictions of this Plan section are met, the Administrative Committee may exclude from the ADP Test all Eligible Employees who are not Highly Compensated Employees and who have not met the minimum age and service requirements of Code section 410(a)(1)(A), if the Administrative Committee elects to apply Code section 410(b)(4)(B). Alternatively, the Administrative Committee may apply the ADP Test separately to all Eligible Employees who have not met the minimum age and service requirements of Code section 410(a)(1)(A).

(b)ADP Test. The Actual Deferral Percentage for the Plan Year of Participants who are Highly Compensated Employees shall not exceed the greater of:

(1)The product of 1.25 and the Actual Deferral Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year; or

(2)The lesser of:

(A)The product of two and the Actual Deferral Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year, or

(B)The Actual Deferral Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year plus two percentage points.

By an amendment to the Plan, the Administrative Committee may elect to apply paragraphs (1) and (2) by using the Actual Deferral Percentage of Employees who are not Highly Compensated Employees for the prior Plan Year only if the current year testing method has been used for at least the last five Plan Years. If the Plan is aggregated with any other Qualified Plan, the Actual Deferral Percentage of Employees who are not Highly Compensated Employees for the prior Plan Year may be used only if the Plan is amended to so provide and each Qualified Plan that is aggregated with this Plan used the current year method for at least the last five years (or, if shorter, the period that such other Qualified Plan was in existence, including years in which the Qualified Plan was a portion of another Qualified Plan).

(c)The restrictions of this section shall be based on the Participant’s actual Testing Compensation while an Active Participant and total Pre-Tax Deferrals and Roth Contributions allocated to the Participant’s Account for the Plan Year. The Administrative Committee is authorized to restrict the Pre-Tax Deferrals and Roth Contributions of Highly Compensated Employees in a uniform manner if it determines, based on advance testing done during the Plan Year, that such restriction is necessary or appropriate to assure final Plan Year compliance with restrictions of this section.

6.3 Corrective Measures if ADP Test Failed

If, at the end of the Plan Year, the Administrative Committee determines that the Actual Deferral Percentage of Highly Compensated Employees exceeds the maximum permitted for the Plan Year under the ADP Test, then the Administrative Committee shall take the corrective steps described in this Plan section so that the requirements of Plan section 6.2 are met for the Plan Year. Pre-Tax Deferrals and Roth Contributions, along with any other elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly

Compensated Employee, exceeding the ADP Test limits are referred to as Excess Contributions.

(a)Correction Methods. To the extent permitted under Treasury Regulations

section 1.401(k)-2(b)(3) and this Plan section, the Administrative Committee shall first recharacterize Excess Contributions, along with allocable investment gains and losses, as Adjustment Contributions. To the extent Excess Contributions remain for the Plan Year, the Administrative Committee shall next distribute the Excess Contributions, along with allocable investment gains and losses, pursuant to Treasury Regulations section 1.401(k)-2(b)(2) and this Plan section. Regardless of whether recharacterized or distributed, all corrections of Excess Contributions shall be made in accordance with Treasury Regulations section 1.401(k)-2(b)(4) and this Plan section.

(b)Determining Total Excess Contributions. The amount of Excess Contributions attributable to each Highly Compensated Employees is the amount by which Pre-Tax Deferrals and Roth Contributions, along with any other elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly Compensated Employee, must be reduced so that the Actual Deferral Percentage for that Highly Compensated Employee is reduced to the maximum permissible Actual Deferral Percentage for Highly Compensated Employees. The maximum permissible Actual Deferral Percentage for Highly Compensated Employees is determined by reducing the Actual Deferral Percentage for the Highly Compensated Employee with the highest Actual Deferral Percentage for the Plan Year to the Actual Deferral Percentage for the Highly Compensated Employee with the next highest Actual Deferral Percentage.

If a lesser reduction would enable the ADP Test to be satisfied, only the lesser reduction is used to determine the maximum permissible Actual Deferral Percentage. This procedure is repeated until the ADP Test would be satisfied. The total amount of Excess Contributions to be corrected is equal to the sum of the dollar amounts computed under this subsection for each Highly Compensated Employee and is to be referred to as the Total Excess Contributions.

(c)Apportionment of Total Excess Contributions. Total Excess Contributions for the Plan Year shall be apportioned among Highly Compensated Employees as provided in this subsection.

(1)Pre-Tax Deferrals and/or Roth Contributions allocated to the Highly Compensated Employee with the highest dollar amount of Pre-Tax Deferrals and/or Roth Contributions taken into account under the ADP Test for the Plan Year, including any other elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly Compensated Employee, shall be reduced by the amount required to cause that Highly Compensated Employee’s remaining amount of Pre-Tax Deferrals and/or Roth

Contributions for the Plan Year to be equal to the dollar amount of Pre-Tax Deferrals and/or Roth Contributions for the Highly Compensated Employee with the next highest dollar amount. This amount shall be allocated as the Excess Contribution for the Highly Compensated Employee, unless a smaller reduction, when added to the total dollar amount already allocated as Excess Contributions for other Highly Compensated Employees pursuant to this procedure equals the Total Excess Contributions for the Plan Year. Excess Contributions shall be treated as consisting first of any Pre-Tax Deferrals made by the Participant for such Plan Year, as applicable, and second any Roth Contributions which the Participant made for the Plan Year, as applicable, except as otherwise elected by the Participant.

(2)If a Highly Compensated Employee’s Excess Contributions include elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly Compensated Employee, then the Excess Contribution of that to the Highly Compensated Employee shall not exceed the Pre- Tax Deferrals and/or Roth Contributions made under this Plan for the Plan Year. Any portion of the Total Excess Contributions which is apportioned to a Highly Compensated Employee pursuant to this subsection, but which cannot be corrected because of the preceding sentence, shall be apportioned to the Highly Compensated Employee with the next lowest total dollar amount of Pre-Tax Deferrals and/or Roth Contributions and that Highly Compensated Employee’s Excess Contributions shall be reduced by an amount which includes the amount not corrected for the other Highly Compensated Employee.

(3)If the total amount corrected under this subsection is less than the Total Excess Contributions for the Plan Year, the procedure in this paragraph shall be repeated until the total amount corrected is equal to the Total Excess Contributions for the Plan Year.

(4)The investment gains and losses allocable to the Excess Contributions are equal to the sum of allocable investment gains and losses for the Plan Year and allocable gains and losses after the Plan Year for which the distribution is made. The allocable investment gain or loss attributable to the Excess Contributions may be determined in accordance with any of the methods permitted under Treasury Regulations section 1.401(k)-2(b)(2)(iv), disregarding any provisions relating to the distribution of gap period earnings, and may be determined up to seven days before the date of the correction.

(5)Excess Contributions of the Highly Compensated Employee with respect to which Matching Contributions were not made shall be corrected to the extent necessary under this Plan section before Excess

Contributions of that Highly Compensated Employee with respect to which Matching Contributions were made.

(6)The requirements of this Plan section shall be deemed to have been satisfied if the total dollar amount corrected equals the Total Excess Contributions with allocable investment gains and losses, even if:

(A)The ADP Test would not satisfy the requirements of Plan section 6.2, if the test were rerun including in the test only Pre-Tax Deferrals and/or Roth Contributions that were not corrected under this subsection; or

(B)The amount corrected with respect to each Highly Compensated Employee is different from the amount computed for purposes of calculating the Total Excess Contributions amount.

(d)Rules Applicable to Adjustment Contributions. Excess Contributions shall not be treated as corrected even if recharacterized under this subsection (d), unless the requirements of this subsection are met.

(1)Excess Contributions that are recharacterized as Adjustment Contributions must be reported to the Internal Revenue Service and the Highly Compensated Employee as included in gross income of the Highly Compensated Employees to the same extent they would have been included in gross income if distributed.

(2)Excess Contributions must be recharacterized as Adjustment Contributions no later than 21/2 months after the close of the Plan Year (for Plan Years beginning after December 31, 2019, 6 months after the close of the Plan Year). For this purpose, recharacterization will be deemed to have occurred on the date on which the last Highly Compensated Employee is notified that his or her Pre-Tax Deferrals and/or Roth Contributions are being recharacterized as Adjustment Contributions.

(3)Excess Contributions may be recharacterized as Adjustment Contributions for a Plan Year only if the Plan allows After-Tax Contributions for that Plan Year and such Adjustment Contributions are included in the ACP Test for the Plan Year.

(4)Investment gains and losses allocable to Excess Contributions shall be allocated to the corresponding Adjustment Contributions after recharacterization.

(e)Rules Applicable to Distributions. Excess Contributions shall not be treated as corrected even if distributed under this subsection (e), unless the requirements of this subsection are met.

(1)Excess Contributions and allocable investment gains and losses must be distributed to the Highly Compensated Employee to whom it has been allocated within 12 months after the close of the Plan Year for which the Excess Contribution arose.

(2)The distributed Excess Contributions and allocable investment gains and losses shall be taken from the Investment Funds in which the Pre-Tax Account and/or Roth Account is then invested on a pro rata basis.

(3)Any Matching Contributions that have been made with respect to Excess Contributions that are distributed to a Highly Compensated Employee shall be forfeited, as soon as is practicable after corrective distributions are made. Such Matching Contributions shall be forfeited, whether or not the Participant would otherwise have a vested interest in those Matching Contributions, pursuant to Plan section 3.5.

(4)If the Highly Compensated Employee received a full distribution of his or her Account before Excess Contributions and allocable investment gains and losses are distributed to the Highly Compensated Employee, then the prior distribution shall be reported for taxation purposes as first a correction of Excess Contributions and allocable investment gains and losses to the extent required under this Plan section.

(5)A distribution of Excess Contributions and allocable investment gains and losses shall in no event be treated as satisfying a required minimum distribution for purposes of Code section 401(a)(9) and Plan section 7.6.

(6)The distribution required by this Plan section may be made notwithstanding any other Plan provision.

6.4 Discrimination Limits on Matching Contributions, After-Tax Contributions, and Adjustment Contributions

As of the last day of each Plan Year, the Administrative Committee shall require testing of Matching Contributions, After-Tax Contributions, and Adjustment Contributions made for the Plan Year for Participants, who were not Represented Employees for the period for which the contributions were made, to assure that the Average Contribution Percentage for the Plan Year of such Participants who are Highly Compensated Employees does not exceed the limits specified in the ACP Test. The rules of this section shall not apply at all to Matching Contributions, After-Tax Contributions, and Adjustment Contributions made for the Plan Year for Participants who are Represented Employees for the period for which the contributions are made.

(a)Aggregation, Disaggregation and Restructuring. The rules of this section shall be administered so as to comply with the mandatory disaggregation requirements of Treasury Regulations section 1.410(b)-7(c) and, if the Administrative Committee chooses, the permissive aggregation rules of Treasury Regulations section 1.410(b)-7(d), provided that any aggregated plans shall use

the same testing method under Treasury Regulations section 1.401(k)-2(a)(2)(ii) (i.e., current year or prior year testing method) as is used by the Plan for the Plan Year. Notwithstanding the foregoing, effective January 1, 2004, the mandatory disaggregation rules relating to the ESOP and non-ESOP portions of the Plan shall not apply.

(1)If, after application of the mandatory disaggregation rules, in the preceding paragraph, this Plan is permissively aggregated with one or more other plans that include matching or after-tax contributions subject to contribution testing under Code section 401(m) for purposes of Code section 401(a)(4) or 410(b), then this Plan and such other plans shall be treated as one arrangement for purposes of this Plan section.

(2)In determining whether the restrictions of this Plan section are met, the Administrative Committee may exclude from the ACP Test all Eligible

Employees who are not Highly Compensated Employees and who have not met the minimum age and service requirements of Code section 410(a)(1)(A), if the Administrative Committee elects to apply Code section 410(b)(4)(B). Alternatively, the Administrative Committee may apply the ACP Test separately to all Eligible Employees who have not met the minimum age and service requirements of Code section 410(a)(1)(A).

(b)ACP Test. The Average Contribution Percentage for the Plan Year of Participants who are Highly Compensated Employees shall not exceed the greater of:

(1)The product of 1.25 and the Average Contribution Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year; or

(2)The lesser of:

(A)The product of two and the Average Contribution Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year, or

(B)The Average Contribution Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year plus two percentage points.

By an amendment to the Plan, the Administrative Committee may elect to apply paragraphs (1) and (2) by using the Average Contribution Percentage of Employees who are not Highly Compensated Employees for the preceding Plan Year rather than the current Plan Year except that such election may not be changed unless permitted by the Internal Revenue Service.

(c)The restrictions of this section shall be based on the Participant’s actual Testing Compensation while an Active Participant and total Matching Contributions, After-Tax Contributions and Adjustment Contributions allocated to the Participant’s Account for the Plan Year. The Administrative Committee is authorized to restrict the After-Tax Contributions of Highly Compensated Employees in a uniform manner if it determines, based on advance testing done during the Plan Year, that such restriction is necessary or appropriate to assure final Plan Year compliance with restrictions of this section.

6.5 Corrective Measures if ACP Test Failed

If, at the end of the Plan Year, the Administrative Committee determines that the Average Contribution Percentage of Highly Compensated Employees exceeds the maximum permitted for the Plan Year under the ACP Test, then the Administrative Committee shall take the corrective steps described in this Plan section so that the requirements of Plan section 6.4 are met for the Plan Year. Matching Contributions, After-Tax Contributions, and Adjustment Contributions, along with any other matching contributions and after-tax contributions (including any recharacterized elective deferrals) made to other Qualified Plans that are included the Actual Deferral Percentage of a Highly Compensated Employee, exceeding the ACP Test limits are referred to as Excess Aggregate Contributions.

(a)Correction Method. The Administrative Committee shall distribute or forfeit Excess Aggregate Contributions, along with allocable investment gains and losses, pursuant to Treasury Regulations section 1.401(m)-2(b)(2) and this Plan section.

(b)Determining Total Excess Aggregate Contributions. The amount of Excess Aggregate Contributions attributable to each Highly Compensated Employee is the amount by which Matching Contributions, After-Tax Contributions and Adjustment Contributions, along with any other matching contributions and after-tax contributions (including any recharacterized elective deferrals) made to other Qualified Plans that are included the Average Contribution Percentage of a Highly Compensated Employee, must be reduced so that the Average Contribution Percentage for that Highly Compensated Employee is reduced to the maximum permissible Average Contribution Percentage for Highly Compensated Employees. The maximum permissible Average Contribution Percentage for Highly Compensated Employees is determined by reducing the Average Contribution Percentage for the Highly Compensated Employee with the highest Average Contribution Percentage for the Plan Year to the Average Contribution Percentage for the Highly Compensated Employee with the next highest Average Contribution Percentage. If a lesser reduction would enable the ACP Test to be satisfied, only the lesser reduction is used to determine the maximum permissible Average Contribution Percentage. This procedure is repeated until the ACP Test would be satisfied. The total amount of Excess Aggregate Contributions to be corrected is equal to the sum of the dollar amounts

computed under this subsection for each Highly Compensated Employee and is be referred to as the Total Excess Aggregate Contributions.

(c)Apportionment of Total Excess Aggregate Contributions. Total Excess Aggregate Contributions for the Plan Year shall be apportioned as provided in this subsection.

(1)Excess Aggregate Contributions allocated to the Highly Compensated Employee with the highest dollar amount of Matching Contributions, After-Tax Contributions and Adjustment Contributions taken into account under the ACP Test for the Plan Year shall be reduced by the amount required to cause that Highly Compensated Employee’s remaining amount of Matching Contributions, After-Tax Contributions and Adjustment Contributions for the Plan Year to be equal to the dollar amount of Matching Contributions, After-Tax Contributions and Adjustment Contributions for the Highly Compensated Employee with the next highest dollar amount. This amount shall be allocated as the Excess Aggregate Contribution for the Highly Compensated Employee, unless a smaller reduction, when added to the total dollar amount already allocated as Excess Aggregate Contributions for other Highly Compensated Employees pursuant to this procedure equals the Total Excess Aggregate Contributions for the Plan Year.

(2)If a Highly Compensated Employee’s Excess Aggregate Contributions include matching contributions and after-tax contributions (including any recharacterized elective deferrals) made to other Qualified Plans that are included the Average Contribution Percentage of a Highly Compensated Employee, then the Excess Aggregate Contribution of that to the Highly Compensated Employee shall not exceed the Matching Contributions, After-Tax Contributions and Adjustment Contributions made under this Plan for the Plan Year. Any portion of the Total Excess Aggregate Contributions which is apportioned to a Highly Compensated Employee pursuant to this subsection, but which cannot be corrected because of the preceding sentence, shall be apportioned to the Highly Compensated Employee with the next lowest total dollar amount of Pre-Tax Deferrals and/or Roth Contributions and that Highly Compensated Employee’s Excess Aggregate Contributions shall be reduced by an amount which includes the amount not corrected for the other Highly Compensated Employee.

(3)If the total amount corrected under this subsection is less than the Total Excess Aggregate Contributions for the Plan Year, the procedure in this paragraph shall be repeated until the total amount corrected is equal to the Total Excess Aggregate Contributions for the Plan Year.

(4)The investment gains and losses allocable to the Excess Aggregate Contributions are equal only to the sum of allocable investment gains

and losses for the Plan Year for which the distribution is made. The allocable investment gain or loss attributable to the Excess Aggregate Contributions may be determined in accordance with any of the methods permitted under Treasury Regulations section 1.401(m)–2(b)(2)(iv), disregarding any provisions relating to the distribution of gap period earnings, and may be determined up to seven days before the date of the correction.

(d)Distribution or Forfeiture. Excess Aggregate Contributions shall not be treated as corrected even if distributed under this subsection, unless the requirements of this subsection are met.

(1)Excess Aggregate Contributions and allocable investment gains and losses must be distributed to the Highly Compensated Employee to whom it has been allocated within 12 months after the close of the Plan Year for which the Excess Aggregate Contribution arose.

(2)Excess Aggregate Contributions and allocable investment gains and losses shall be distributed or, to the extent attributable to Matching Contributions in which the Highly Compensated Employee is not fully vested as of the end of the Plan Year, forfeited in the following order:

(A)After-Tax Contributions and allocable investment gains and losses on which Matching Contributions were not made;

(B)Adjustment Contributions and allocable investment gains and losses on which Matching Contributions were not made;

(C)After-Tax Contributions and allocable investment gains and losses along with the corresponding Matching Contributions and allocable investment gains and losses; and

(D)Adjustment Contributions and allocable investment gains and losses along with the corresponding Matching Contributions and allocable investment gains and losses.

(3)The distributed Excess Aggregate Contributions and allocable investment gains and losses shall be taken from the Investment Funds in which the subaccount is then invested on a pro rata basis.

(4)If the Highly Compensated Employee received a full distribution of his or her Account before Excess Aggregate Contributions and allocable investment gains and losses is distributed to the Highly Compensated Employee, then the prior distribution shall be reported for taxation purposes as first a correction of Excess Aggregate Contributions and allocable investment gains and losses to the extent required under this Plan section.

(5)A distribution of Excess Aggregate Contributions and allocable investment gains and losses shall in no event be treated as satisfying a required minimum distribution for purposes of Code section 401(a)(9) and Plan section 7.6.

(6)The distribution required by this Plan section may be made notwithstanding any other Plan provision.

6.6 Limitation on Annual Additions

(a)General Rule. Notwithstanding anything to the contrary contained in this Plan, the total Annual Additions under this Plan and any other defined contribution plan, as defined in Code section 414(i), maintained by the Company or any Affiliate, allocated to a Participant’s Account for any Plan Year, which shall be the limitation year for purposes of Code section 415, shall not exceed the lesser of:

(1)$40,000, as adjusted for increases in the cost-of-living under Code section 415(d) for Plan Years beginning after 2002; or

(2)100 percent of the Participant’s Section 415 Compensation for the limitation year.

(b)“Annual Addition” Defined. The term “Annual Addition,” with respect to any Participant for a Plan Year, shall mean the aggregate of:

(1)The amount of Employer contributions (including Matching Contributions and Pre- Tax Deferrals and Roth Contributions other than Catch-Up Contributions) allocated to the Participant’s Account under this Plan and any other Employer contributions (other than Catch-Up Contributions under Code section 414(v)) allocated under any other defined contribution plan, as defined in Code section 414(i), maintained by the Company or any Affiliate for the Plan Year;

(2)The amount of a Participant’s After-Tax Contributions (including Adjustment Contributions, but excluding Rollover, Roth Rollover and After-Tax Rollover Contributions) allocated to the Participant’s Account under this Plan and any other Employee contributions allocated under any other defined contribution plan maintained by the Company or any Affiliate for the Plan Year;

(3)Forfeitures allocated to the Participant’s Account under this Plan or any other defined contribution plan maintained by the Company or any Affiliate for the Plan Year; and

(4)For the purpose of Plan section 6.6(a)(1) only, the amount of Employer contributions, if any, allocated to an account described in Code section 419A(d)(1) or an account described in Code section 415(1)(2).

For purposes of this subsection and to comply with the requirements of Code section 415(h), the term “Affiliate” includes, in addition to Affiliates defined in Plan section 2.1(i), any entity that would be an Affiliate under that definition if the phrase “more than 50 percent” were substituted for the phrase “at least 80 percent” each place it appears in Code 1563(a)(1).

(c)Additional Rules. In applying the limits of subsection (a), the following rules shall apply:

(1)Excess Deferrals shall not be included as an Annual Addition if they are distributed in a corrective distribution under the provisions of that section. However, any Excess Deferrals that are not distributed in a corrective distribution under Plan section 6.1 shall be included as an Annual Addition, even if they are in excess of the Code section 402(g)(1) limit.

(2)Pre-Tax Deferrals and Roth Contributions in excess of the ADP Test limits of Plan section 6.2 shall be included as an Annual Addition, even if they are correctively distributed or re-characterized as Adjustment Contributions under Plan section 6.3.

(3)Matching Contributions and After-Tax Contributions (including any Adjustment Contributions) in excess of the ACP Test limits of Plan section 6.4 shall be included as an Annual Addition, even if they are correctively forfeited or distributed under Plan section 6.5. Matching Contributions relating to distributions of Excess Deferrals under Plan section 6.1(d) are forfeited and shall not be included as an Annual Addition.

(4)If a short limitation year is created because of an amendment or other action changing the limitation year (or Plan Year) to a different 12-consecutive-month period, the dollar limitation of Plan section 6.6(a)(1) to be applied for that short limitation year shall be multiplied by a fraction, the numerator of which is the number of months in the short limitation year and the denominator of which is 12.

(5)The Annual Additions of a Participant who is also a Supplemental Plan Participant for the Plan Year shall be determined under this paragraph if doing so results in a larger amount of Annual Additions for that Participant for the Plan Year. Annual Additions under this paragraph shall be determined by assuming that, for the Plan Year, the Participant contributed the contribution percentage limit in effect for the Participant as determined under Appendix D and received the maximum allocation of Matching Contribution under Plan section 5.2.

(d)Disposition of Excess Annual Additions

(1)Not a Supplemental Plan Participant. If the Participant is not also a Supplemental Plan Participant for the Plan Year, then the Participant’s Annual Additions shall be reduced under this Plan, if such reduction is required for purposes of reducing allocations on a combined basis, to the limits of subsection (a) and Code section 415(c), as follows:

(A)First, by distributing After-Tax Contributions (including any Adjustment Contributions) made for the Plan Year to the Participant, to the extent necessary; and

(B)Next, by distributing Pre-Tax Deferrals and/or Roth Contributions made for the Plan Year to the Participant, to the extent necessary; and

(C)Then, forfeiting Matching Contributions made for the Plan Year, to the extent necessary; and

(D)Finally, reducing any remaining excess Annual Additions under the terms of such other defined contribution plans maintained by the Company or any Affiliate as specified in those plans.

(2)Supplemental Plan Participant. If the Participant is also a Supplemental Plan Participant for the Plan Year, then the Participant’s Annual Additions shall first be reduced under the terms of the Retirement Plan for the Plan Year by reducing the allocations made under the Retirement Plan to the extent necessary to assure compliance with the limits of subsection (a) and Code section 415(c). Only after reductions under the Retirement Plan have been made shall reductions of Annual Additions be made under the terms of this Plan and such other defined contribution plans maintained by the Company or any Affiliate, if such a reduction is required for purposes of reducing allocations on a combined basis, to the limit of subsection (a) and Code section 415(c), as follows:

(A)First, by distributing After-Tax Contributions (including any Adjustment Contributions) made for the Plan Year to the Participant, to the extent necessary; and

(B)Next, by distributing Pre-Tax Deferrals and/or Roth Contributions made for the Plan Year to the Participant, to the extent necessary; and

(C)Then, forfeiting Matching Contributions made for the Plan Year, to the extent necessary; and

(D)Finally, reducing any remaining excess Annual Additions under the terms of such other defined contribution plans (other than the

Retirement Plan) maintained by the Company or any Affiliate as specified in those plans.

(e)Adjustment of Allocations. If an allocation to the Account of a Participant would exceed the limit of subsection (a) due to a reasonable mistake in estimating a Participant’s Section 415 Compensation or due to forfeitures or a reasonable error in the estimation of salary deferrals, then any amount which cannot be allocated shall be held in a suspense account and shall be allocated to the Account of such Participant in the next following Plan Year. The suspense account shall not share in investment gains or losses of the Trust Fund. Effective for Plan Years beginning after July 1, 2007, this subsection shall no longer apply because this correction methodology is no longer permitted under the final Treasury Regulations under Code section 415.

6.7 Limitation on Pay Taken Into Account

(a)In determining the amount of Pre-Tax Deferrals and Roth Contributions that may be made on behalf of a Participant for a Plan Year, the total amount of Earnings to which the percentage reduction, elected by the Participant, is applied shall not be limited. Notwithstanding the foregoing, however, the total annual amount of Pre-Tax Deferrals and Roth Contributions made for a Plan Year on behalf of the Participant shall not exceed the product of the maximum deferral percentage allowed under the Plan for the Plan Year multiplied by the compensation limit in effect for the Plan Year under Code section 401(a)(17).

(b)In determining the amount of After-Tax Contributions that may be made on behalf of a Participant for a Plan Year, the total amount of Earnings to which the percentage reduction, elected by the Participant, is applied shall not be limited. Notwithstanding the foregoing, however, the total annual amount of After-Tax Contributions made for a Plan Year on behalf of the Participant shall not exceed the product of the maximum contribution percentage allowed under the Plan for the Plan Year multiplied by the compensation limit in effect for the Plan Year under Code section 401(a)(17).

(c)In determining the amount of Matching Contributions that may be made on behalf of a Participant for a Plan Year, the total amount of Earnings to which the Matching Contribution is applied shall not be limited. Notwithstanding the foregoing, however, the total annual amount of Matching Contributions made for a Plan Year on behalf of an Active Participant shall not exceed the product of the matching percentage determined under Appendix E multiplied by the maximum amount of Earnings for which Matching Contributions are determined multiplied by the compensation limit in effect for the Plan Year under Code section 401(a)(17).

6.8 Deductibility Limitation

Notwithstanding any provision of the Plan to the contrary, the dollar amount of Employer contributions to this Plan are conditioned on their deductibility under Code section 404 and, thus, shall always be limited to the amount deductible under Code

section 404 for the taxable year for which such contributions are paid to the Trust Fund.

Article 7. Benefit Distributions

7.1 Distributions Generally

Distribution of a Participant’s vested Account may begin pursuant to Plan section 7.2, relating to in-service withdrawals, Plan section 7.3, relating to benefit payments on account of a Separation from Service, and Plan section 7.5, relating to death benefit distributions, as applicable under the terms of this Article, but not later than the date provided in Plan section 7.6, relating to required minimum distributions.

Notwithstanding the foregoing, a Participant’s Pre-Tax Account and Roth Account may not be distributed earlier than upon one of the following events:

(a)The Participant’s retirement, death, Disability, or Separation from Service;

(b)The termination of the Plan without the establishment of another defined contribution plan (other than an employee stock ownership plan within the meaning of Code section 4975(e)(7)), provided that distributions made under this paragraph may be made only in the form of a single lump sum that complies with Code section 401(k)(10)(B); or

(c)The Participant’s attainment of age 591/2 or, if the Plan is amended to so provide, a financial hardship of the Participant.

7.2 In-Service Withdrawals

(a)An Active Participant or Inactive Participant may withdraw, prior to his or her Separation from Service, in the following order, any amount, up to 100 percent of the sum of the Participant’s:

(1)After-Tax Rollover Account, if any;

(2)After-Tax Account, if any;

(3)Rollover Account, if any;

(4)Pre-Tax Account, but only if the Participant has attained age 591/2; and then

(5)Matching Account, but only if the Participant has completed at least three years of Service.

(b)An Active Participant or Inactive Participant also may withdraw, prior to his or her Separation from Service, any amount, up to 100 percent of the sum of the Participant’s, without regard to Plan section 7.2(e) below:

(1)Roth Account, but only if the Participant has attained age 591/2;

(2)Roth Rollover Account; or

(3)In-Plan Roth Rollover Account, but only if the Participant has attained age 591/2.

(c)No withdrawal may be requested in any processing period in which a plan loan, as described in Article 8, is being processed. Furthermore, no withdrawal request

may be processed more often than once in any six-month period beginning with the date that the Participant’s most recent withdrawal request was processed. Effective August 8, 2016, there will be no restriction on the timing of withdrawal requests or the coordination of withdrawal requests with the processing of loan or other requests under the Plan.

(d)Application for a withdrawal shall be made on such forms as the Administrative Committee prescribes and shall be effective as of the end of the processing period in which such application is received and approved by the Administrative Committee. The Administrative Committee shall direct the Trustee, in such cases, to pay the Participant or Inactive Participant the withdrawal amount in a single sum.

(e)Withdrawals shall be paid first out of the net cumulative pre-1987 contributions from the After-Tax Account. Withdrawals shall then be paid out of the net cumulative post-1986 contributions, together with earnings thereon, on a pro rata basis, from the After-Tax Account. Additional amounts shall be withdrawn, if needed, from earnings on pre-1987 contributions from the After-Tax Rollover Account, if any, then from the After-Tax Account, if any, then from the Rollover Account, if any, then from the Pre-Tax Account, if permissible, and then from the Matching Account, to the extent permissible. The amount withdrawn shall be taken from such Investment Funds in which the subaccount is invested on a pro rata basis.

(f)A withdrawal from a Participant’s Account balances invested in Oxy Stock shall be in the form of full shares of Oxy Stock and cash representing any fractional share, except that cash shall be paid in lieu of full shares of Oxy Stock if the Participant specified in the written request for withdrawal that the withdrawal be in the form of cash. A withdrawal from Account balances invested in assets other than Oxy Stock shall be paid in cash. Notwithstanding the foregoing, a withdrawal consisting of pre-1987 contributions from the After-Tax Account only shall be in the form of cash.

(1)Except as provided below, if a Participant withdraws any amount from the Matching Account, the Participant (other than a Participant who has attained age 591/2 at the time the withdrawal is requested and who withdraws the entire balance in his or her Account) shall not be permitted to make any Pre-Tax Deferrals, Catch-Up Contributions, Roth Contributions, After-Tax Contributions, or receive Matching Contributions for a period of six calendar months after the withdrawal is processed (except that such Participant will still be eligible to receive Matching Contributions on any Annual Bonus). Effective for withdrawals requested after August 8, 2016, if a Participant is suspended from making any Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions, and/or After-Tax Contributions in accordance with the sentence above, such contributions will be automatically reinstated upon expiration of the six-month suspension period at the Default Percentage,

as applicable, or if the Participant was not subject to automatic enrollment or had opted out of automatic enrollment at the percentage in place prior to the suspension. Effective January 1, 2017, unless the Participant affirmatively elects otherwise, with respect to any Participant hired prior to August 5, 2016, upon re-instatement, the election in effect as of August 5, 2016 will apply to any Annual Bonus paid in the 2017 Plan Year and any subsequent plan year until the Participant affirmatively elects otherwise. Effective August 8, 2016, any Participant subject to automatic enrollment pursuant to Plan section 4.6, must make a separate election to make Pre-Tax Deferrals, Roth Contributions and After-Tax Contributions from Participant’s Annual Bonus.

(2)The preceding subsection shall be inapplicable in the case of a withdrawal effected by a creditor of a Participant pursuant to any insolvency proceeding initiated under federal or state law or pursuant to any tax levy.

(3)In addition, notwithstanding the foregoing and effective January 1, 2013, a Participant who has attained age 59 ½ and who withdraws less than the entire balance in his or her Account, shall not be suspended from making Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions, After-Tax Contributions, or receiving Matching Contributions, but pursuant to subsection (b) shall not be permitted to make another withdrawal for six months beginning with the date that the Participant’s most recent withdrawal request was processed. Effective August 5, 2016, a Participant who has attained age 59 ½ and who withdraws less than the entire balance in his or her Account will no longer be subject to the one withdrawal per six-month period limitation.

(g)Pursuant to the procedures established by the Administrative Committee, during 2020, a Participant who is a “Qualified Individual” (as defined below) may request a Coronavirus-Related Distribution (“CRD”) up to $100,000 from the individual’s Account. A “Qualified Individual” is an individual who can certify that: (i) he or she has been diagnosed with the virus SARS-CoV-2 or with coronavirus 2019 (“COVID-19”) by a test approved by the Centers for Disease Control and Prevention (“CDC”); (ii) his or her spouse or dependent is diagnosed with SARS-CoV-2 or with COVID-19 by a test approved by the CDC; (iii) he or she experiences adverse financial consequences due to SARS-CoV-2 or COVID-19 as a result of one or more of the following: (A) he or she is quarantined; (B) he or she is being furloughed or laid off; (C) his or her workings hours have been reduced; (D) he or she is unable to work due to a lack of child care; (E) he or she has to close or reduce hours of a business that he or she owns or operates. The Administrative Committee may rely on a Participant’s certification that the Participant is a Qualified Individual.

In accordance with the procedures established by the Administrative Committee, a Participant may recontribute to the Participant’s Account the amount distributed as a CRD pursuant to this Section 7.2(g) in accordance with Section 2202 of the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) and IRS guidance thereunder during the 3-year period commencing after the date the distribution was received.

7.3 Benefits Upon Separation from Service

(a)Every Participant who incurs a Separation from Service for any reason other than death may elect to receive a distribution of the vested portion of his or her Account, in a payment form specified by Plan section 7.4. The failure of a Participant to elect a distribution of benefits upon his or her Separation from Service shall be deemed to be an election by the Participant to defer the commencement of benefits.

(b)Unless the Participant chooses to defer the commencement of benefits, either affirmatively or by failing to make a distribution election, and subject to Plan section 7.6, distribution of benefits to a Participant who incurs a Separation from Service shall begin no later than the 60th day after the close of the Plan Year in which occurs the later of:

(1)The Participant’s Separation from Service; or

(2)The Participant’s 65th birthday.

If for any reason the amount which is required to be paid cannot be ascertained on the date payment would be due hereunder, payment or payments shall be made not later than 60 days after the earliest date on which the amount of such payment is ascertained.

7.4 Payment Rules

(a)General Rules. All distributions from this Plan shall be valued as provided in Article 10 and paid in cash or Oxy Stock as provided in this Plan section. The automatic form of benefit payment to a Participant who has incurred a Separation from Service and elected a distribution of his or her vested Account. Effective January 1, 2020, if at any time prior to the full repayment of a Participant’s loan under the Plan, the Participant should transfer employment to a new employer by reason of a corporate transaction, the Participant may, to the extent permitted by the Administrative Committee, elect a direct rollover of his or her loan note to an eligible plan sponsored by the Participant’s new employer, provided that the new employer’s plan agrees to accept such rollover and the loan is not in default.

(b)Election Procedures. All Participant elections to commence benefits shall be made during an election period of not more than 90 days and, except as provided below, not less than 30 days ending on the day prior to the date as of which his benefits are scheduled to commence in accordance with the benefit payment

election procedures prescribed by the Administrative Committee. Such procedures shall require the following:

(1)An election form shall be provided to the Participant in non-technical language which will contain a general description of the distribution options.

(2)A Participant may revoke an election of any benefit form described in this section and choose again to take any available benefit form at any time and any number of times within the above election period.

(3)A Participant, after having received the written description described in this subsection, may reject the automatic form of benefit and elect a different option under subsection (c), even though the written description was provided less than 30 days prior to the Participant’s benefit commencement date, so long as the conditions contained in Treasury Regulations section 1.417(e)-1T(b)(3)(ii) have been met. If the Participant makes an untimely request for additional information, the Administrative Committee, at its discretion, may grant such request, but the granting of such request shall not result in the extension of the election period.

(c)Optional Payment Forms. A Participant who has incurred a Separation from Service for any reason other than death may elect to have his or her vested Account distributed to the Participant under one of the following distribution options, in lieu of the automatic lump sum, as selected by the Participant in the manner prescribed and approved by the Administrative Committee:

(1)Partial Cash Distribution. A request for a specified dollar portion of the Participant’s vested Account. A Participant may request one partial cash distribution in any six-month period. If the Participant receives a partial cash distribution, the Participant must wait until the next processing period before he or she may request a subsequent lump sum payment or total distribution. Effective August 8, 2016, there will be no timing limitation for partial cash distributions. A Participant may elect a partial cash distribution under one of the following options; Investment Fund balances will automatically be depleted on a pro rata basis in the following account depletion sequence:

(A)Option 1.

(i)After-Tax Rollover Account;

(ii)After-Tax Account;

(iii)Rollover Account; and

(iv)Pre-Tax Account;

(B)Option 2

(i)Matching Account;

(ii)Roth Rollover Account;

(iii)In-Plan Roth Rollover Account; and

(iv)Roth Account.

(C)Or under both (A) and (B) above.

Remaining balances in each account will continue to participate in Investment Fund earnings until valued for distributions as provided in Article 10.

(2)Special Distribution. The portion of Participant’s vested Account, which is an Eligible Rollover Distribution (as determined under Plan section 7.7(b)(4)) and which is invested in Investment Funds other than the Oxy Stock Fund, is distributed as a Direct Rollover (within the meaning of Plan section 7.7(b)(1)), as directed by the Participant. The Oxy Stock Fund balance from the Participant’s vested Account is distributed to the Participant as shares of Oxy Stock along with a cash distribution of any remaining portion of the Participant’s vested Account.

(3)Total Deferral. Defers distribution of the Participant’s vested Account, but not beyond the end of the year in which the Participant attains age 70 ½. Subject to Plan section 7.6, the Participant may revoke his or her deferral election at any time by submitting another distribution request.

(d)Reserved.

(e)Payment Medium. The provisions of this subsection are intended to comply with the stock distribution requirements of Code sections 409(h) and 409(o) applicable to the portion of this Plan constituting an employee stock ownership plan, as required by Code section 4975(e)(7). Notwithstanding any Plan provision to the contrary, the Administrative Committee shall take steps to ensure that this section is interpreted and administered so as to comply with such requirements. In the event of any conflict, the rules of the Code and Treasury Regulations shall control.

(1)General Rule. In the case of a Participant, Beneficiary or Alternate Payee receiving a distribution in the form of single lump sum payment, the value of the vested Account attributable to investments other than Oxy Stock shall be paid in cash and the value of the vested Account attributable to Oxy Stock shall be distributed in full shares of Oxy Stock plus cash representing the value of any fractional share, except as

provided in Plan section 7.4(h)(3) for mandatory cashout distributions and Plan section 7.6(a) for required minimum distributions.

(2)Alternative Elections.

(A)By written notice to the Administrative Committee, the Participant, Beneficiary or Alternate Payee may elect to receive cash in lieu of and equal to the value of the Oxy Stock that would otherwise be distributed under the general rule.

(B)By written notice to the Administrative Committee, a Participant, Beneficiary or Alternate Payee may elect to receive all or a portion of the vested Account in the form of whole shares of Oxy Stock, plus cash for any fractional share. Any such election shall be implemented in accordance with procedures established by the Administrative Committee by transferring the investment of such Account or portion thereof, as applicable, (including without limitation amounts transferred from the MidCon Corp. ESOP) as soon as practicable to the Oxy Stock Fund and distributing such amounts as soon as practicable thereafter.

(3)Put Option.

(A)Oxy Stock is readily tradable on established securities market within the meaning of Treasury Regulation section 1.401(a)(35)-1(f)(5). Thus, the provisions of this paragraph (3) shall apply only in the event and to the extent that as of the date of distribution of Oxy Stock, the Oxy Stock is not readily tradable on established securities market or is subject to a trading limitation.

(B)If Oxy Stock is not readily tradable on established securities market or is subject to a trading limitation when distributed, the distributee shall have the option to sell (the “put option”) such Oxy Stock, in whole or in part, to the Company. The put option shall be granted in accordance with Code section 409(h) and all applicable Treasury Regulations. Specifically, the put option shall provide that for a period of at least 60 days following the date of distribution of the Oxy Stock and, if not exercised within such period of 60 days, during the first 60 days in the following Plan Year, the distributee shall have the right to have the Company purchase such shares at their fair market value, determined in accordance with Treasury Regulations section 54.4975- 11(d)(5), as of the Valuation Date coincident with or immediately preceding the date of exercise of such put option. The put option may be exercised by notifying the Employer in writing that the option is being exercised.

(C)Once the put option is exercised, the fair market value of such shares shall be paid in a lump sum as soon as practicable. Notwithstanding the foregoing, the Company reserves the right to adopt a different payment schedule at any time, but such payment schedule shall not be longer than in annual installments over a period of five years, with interest on the deferred balance at a reasonable rate as determined by the Administrative Committee; provided that any purchase of stock having a value of $1,000 or less shall be paid for in a lump sum.

(D)The provisions of this paragraph (3) shall continue to apply to Oxy Stock if the Oxy Stock Fund ceases to be an employee stock ownership plan within the meaning of Code section 4975(e)(7).

(E)Notwithstanding the foregoing, this paragraph (3) need not apply to that portion of an Account which the Participant has elected to invest under the diversification provisions of Plan section 9.5.

(f)Payments to Alternate Payees. To the extent permitted by the terms of a Qualified Domestic Relations Order, amounts assigned to an Alternate Payee may be paid as soon as possible in a lump sum, notwithstanding the age, employment status, or other factors affecting the ability of the Participant to make a withdrawal or otherwise to receive a distribution of amounts allocated to the Participant’s Account, provided that the total amount assigned to an Alternate Payee does not exceed $5,000 at the time the amount is distributed or, if the amount assigned does exceed $5,000, the Alternate Payee consents in writing to the distribution. Only if required under the Qualified Domestic Relations Order, an Alternate Payee’s Account may be distributed under one of the optional payment forms specified in subsection (c), if elected by the Alternate Payee in accordance with procedures established by the Administrative Committee. Notwithstanding the foregoing, the Alternate Payee shall be paid in no event no later than the dates specified in Plan section 7.6 (relating to required minimum distributions).

(g)Special Rules for Former Laurel Plan Accounts.

(1)In the case of a Participant for whom a direct plan-to-plan transfer was made to this Plan from the Laurel Industries Inc. Incentive Savings Plan (the “Laurel Plan”), distribution may be made, at the election of the Participant, in any form described in section 6.5(b)(2) of the Laurel Plan as in effect on December 31, 1996, provided that the amount subject to such election shall not exceed the amount of the Participant’s Account attributable to such transfer.

(2)In the case of a Beneficiary of a Participant for whom a direct plan-to-plan transfer was made to this Plan from the Laurel Industries Inc. Incentive Savings Plan (the “Laurel Plan”), distribution may be made, at

the election of the Beneficiary, in any form described in section 6.6(g)(1)(ii) of the Laurel Plan as in effect on December 31, 1996, provided that the amount subject to such election shall not exceed the amount of the Beneficiary’s Account attributable to such transfer.

(h)Mandatory Cashout Distribution. Notwithstanding the election procedures set forth above in Plan section 7.4(b):

(1)Distribution Less Than or Equal to $1,000. With respect to a Participant who incurred a Separation from Service prior to 2021, if the vested Account of the terminated Participant is equal to or less than $1,000, the entire amount shall be distributed in a lump sum as promptly as possible.

(2)Distribution Less Than or Equal to $5,000. Effective January 1, 2021, if the vested Account of a terminated Participant is less than or equal to $5,000, and the Participant fails to elect to have his or her benefits paid directly or in the form of a Direct Rollover (within the meaning of Plan section 7.7(b)(1)) to an Eligible Retirement Plan (within the meaning of Plan section 7.7(b)(3)), the entire account shall be distributed as an automatic rollover to an individual retirement account designated by the Administrative Committee. The Participant will be notified in writing regarding the identity of the individual retirement account trustee or issuer and that his distribution may be transferred without cost or penalty to another individual retirement account.

(3)Distribution to Beneficiaries, Alternate Payees or Participants Over Age 62. Notwithstanding Plan section 7.4(h)(2) above, any distribution that is less than or equal to $5,000 and payable to a Beneficiary, Alternate Payee or Participant who is over age 62 will be distributed in a lump sum as promptly as possible and will not be distributed as an automatic rollover to an individual retirement account.

(4)Form of Distribution. All mandatory cashout distributions will be made in cash and there will be no requirement to issue any shares of Oxy Stock.

7.5 Death Benefits

(a)Participant’s Death After Benefit Commencement. If the Participant dies after distribution of his or her vested Account has commenced, the remaining portion of such benefit, if any, will continue to be distributed at least as rapidly as under the method of distribution in effect prior to the Participant’s death.

(b)Participant’s Death Before Benefit Commencement. Upon the death of a Participant before benefit payments begin, the balance of the deceased Participant’s Account shall be distributed to the Participant’s Beneficiary as soon as practicable after the Participant’s death. Notwithstanding the foregoing, a Beneficiary who is the Participant’s Spouse may elect, before any benefit

payments begin, in accordance with procedures established by the Administrative Committee, to defer receipt of payment of the deceased Participant’s Account, until the year in which the Participant would have attained age 70 ½ in accordance with Plan section 7.6(c)(2).

(1)If the Participant’s Beneficiary is a trust or estate, the distribution shall be paid in a single lump sum payment.

(2)If the Beneficiary is other than the Participant’s Spouse and unless the Beneficiary elects otherwise, the distribution shall be paid in a single lump sum.

(3)If the Beneficiary is the Participant’s Spouse, then in addition to the payment form described in paragraph (2), the Spouse may elect, in accordance with procedures established by the Administrative Committee, to have the distribution paid in the form of a partial cash distribution, as described in Plan section 7.4(c)(1).

(c)Death of Alternate Payee or Beneficiary. If an Alternate Payee or a Beneficiary of a deceased Participant or Alternate Payee dies prior to distribution of the separate Account established on behalf of the Alternate Payee or Beneficiary, the balance of the deceased individual’s Account shall be distributed to his or her Beneficiary as soon as practicable after his death. Such distribution shall be made in the form of a lump sum payment.

7.6 Required Minimum Distributions

This section applies for purposes of determining required minimum distributions for distribution Plan Years beginning on or after January 1, 2003. In other words, this section provides the latest time for distributions to be made or commenced. Other Plan provisions may specify earlier dates for distributions and such provisions shall govern to the extent they are consistent with this section. This section, however, takes precedence over any inconsistent Plan provision. All distributions required under this section shall be determined and made in accordance with Code section 401(a)(9) and the Treasury Regulations thereunder, including the minimum distribution incidental benefit requirements, which are incorporated herein by this reference. For purposes of this Plan section, the required minimum distribution amount shall be determined based on the Account balance as of the last Accounting Date in the Plan Year immediately preceding the Distribution Calendar Year, increased by contributions made and allocated as of dates in the Plan Year after the last Accounting Date, if any, and reduced by distributions made in the Plan Year after the last Accounting Date, if any. The Account balance for the Plan Year immediately preceding the Distribution Calendar Year includes any amounts rolled over or transferred to the Plan in the Plan Year.

(a)Form of Distribution. Unless the Participant’s Account is distributed in a single sum on or before the Required Beginning Date, as of the first Distribution Calendar Year, distributions will be made in accordance with subsections (b) and (c). All required minimum distributions will be made in cash, and there will be no requirement to issue any shares of Oxy Stock.

(b)Required Minimum Distributions During Participant’s Lifetime. The Participant’s entire Account will be distributed, or begin to be distributed, to the Participant no later than the Participant’s Required Beginning Date. During the Participant’s lifetime, the minimum amount that will be distributed for each Distribution Calendar Year is the amount determined under the default rule of paragraph (1) or, if the Participant satisfies the conditions in a timely manner, under the alternative rule of (2):

(1)Default Rule. The quotient obtained by dividing the Participant’s Account balance by the distribution period in the Uniform Lifetime Table set forth in Treasury Regulations section 1.401(a)(9)-9, using the Participant’s age as of the Participant’s birthday in each Distribution Calendar Year.

(2)Alternative Rule. If the Participant’s sole Beneficiary for the Distribution Calendar Year is the Participant’s Spouse, the quotient obtained by dividing the Participant’s Account balance by the number in the Joint and Last Survivor Table set forth in Treasury Regulations section 1.401(a)(9)-9, using the Participant’s and Spouse’s attained ages as of the Participant’s and Spouse’s birthdays in the Distribution Calendar Year. For this alternative rule to apply, the Participant must

request its application and provide such proof of marriage and the Spouse’s age, at such time and in such manner as the Administrative Committee may reasonably require, in advance of the Distribution Calendar Year.

Required minimum distributions will be determined under this subsection beginning with the first Distribution Calendar Year and redetermined for each subsequent Distribution Calendar Year up to and including the Distribution Calendar Year that includes the Participant’s date of death.

(c)Required Minimum Distributions After Participant’s Death.

(1)Death of Participant On or After Date Distributions Begin.

(A)Participant Survived by One Beneficiary. If the Participant dies on or after the date distributions begin and there is a sole Beneficiary, the minimum amount that will be distributed for each Distribution Calendar Year after the year of the Participant’s death is the quotient obtained by dividing the Participant’s Account balance by the remaining Life Expectancy, determined as follows:

(i)If the Participant is not married or the sole Beneficiary is not the Participant’s surviving Spouse, the remaining Life Expectancy is calculated using the age of the Participant in the year of death, reduced by one for each subsequent year.

(ii)If the Participant’s surviving Spouse is the Participant’s sole Beneficiary, the remaining Life Expectancy of the surviving Spouse is calculated for each Distribution Calendar Year after the year of the Participant’s death using the surviving Spouse’s age as of the Spouse’s birthday in that year. For the Distribution Calendar Year after the year of the surviving Spouse’s death, any remaining payment shall be made in a single sum to the Spouse’s estate.

(B)Participant Survived by More Than One Beneficiary. If the Participant dies on or after the date distributions begin and there is more than one Beneficiary as of September 30 of the year after the year of the Participant’s death, the Participant’s remaining Account shall be paid in a single sum as required by Plan section 7.5.

(C)No Beneficiary Survives the Participant. If there is no Beneficiary as of September 30 of the year after the year of the Participant’s death, the Participant’s remaining Account will be paid in a single sum to the Participant’s estate no later than the Distribution Calendar Year after the Participant’s death.

(2)Death of Participant Before Date Distributions Begin. If the Participant dies before distributions begin, the Participant’s Account balance will be distributed, or begin to be distributed no later than provided in this paragraph. The minimum amount that will be distributed or begin to be distributed for each Distribution Calendar Year after the year of the Participant’s death is the amount determined in paragraph (1) above.

(A)If the Participant’s surviving Spouse is the Participant’s sole Beneficiary, then distributions to the surviving Spouse will begin no later than:

(i)December 31 of the calendar year immediately following the calendar year in which the Participant died; or

(ii)December 31 of the calendar year in which the Participant would have attained age 70 ½, if later.

(B)If the Participant’s surviving Spouse is the Participant’s sole Beneficiary and the surviving Spouse dies after the Participant but before distributions to the surviving Spouse begin, this subsection, other than subparagraph (A) immediately above, will apply as if the surviving Spouse were the Participant.

If the Participant’s surviving Spouse is not the Participant’s sole Beneficiary, then distributions to the Beneficiary will begin by December 31 of the calendar year immediately following the calendar year in which the Participant died.

(C)If there is no Beneficiary as of September 30 of the year following the year of the Participant’s death, the Participant’s Account balance will be distributed to the Participant’s estate no later than by December 31 of the calendar year containing the fifth anniversary of the Participant’s death.

(d)Special Definitions. In addition to the terms defined in Plan section 2.1 or elsewhere in this Plan, whenever used in this Plan section, the following terms shall have the respective meanings set forth below, unless expressly provided otherwise. When the defined meaning is intended, the term is capitalized.

(1)“Distribution Calendar Year” means a calendar year for which a minimum distribution is required. For distributions beginning before the Participant’s death, the first Distribution Calendar Year is the later of (A) the calendar year during which the Participant attains age 70 ½, if the Participant is a “5-percent owner,” as defined in Code section 416, or has incurred a Separation from Service or (B) December 31 of the calendar year in which the Participant has a Separation from Service. For distributions beginning after the Participant’s death, the first Distribution Calendar Year is the calendar year in which distributions are required to begin. The required minimum distribution for the

(2)“Life Expectancy” means the life expectancy determined under the Single Life Table in Treasury Regulations section 1.401(a)(9)-9.

(3)“Required Beginning Date” means the later of:

(A)The December 31 of the calendar year in which the Participant attains age 701/2, if the Participant is a “5-percent owner,” as defined in Code section 416, or has incurred a Separation from Service, and

(B)In all other cases, the December 31 of the calendar year in which the Participant has a Separation from Service.

(C)Effective August 8, 2016, “Required Beginning Date” means the later of:

(i)The April 1 of the calendar year following the calendar year in which the Participant attains age 70 ½, if the Participant is a “5-percent owner,” as defined in Code section 416, or has incurred a Separation from Service, and

(ii)In all other cases, the April 1 of the calendar year following the calendar year in which the Participant has a Separation from Service.

Notwithstanding any provision of this Plan section to the contrary and consistent with Code section 401(a)(9)(I) and IRS Notice 2020-51, no 2020 RMD (as defined below) shall be required under this Plan section for the 2020 calendar year. The Required Beginning Date for any individual shall be determined without regard to the preceding sentence for purposes of applying this Plan section to required minimum distributions for any calendar year after 2020. A Direct Rollover will be offered only for distributions that would be Eligible Rollover Distributions without regard to Code section 401(a)(9)(I), as these terms are defined in Plan section 7.7(b). A “2020 RMD” includes a minimum distribution that would have been required in 2020 (or paid in 2021 for the 2020 calendar year for a Participant with a Required Beginning Date of April 1, 2021) but for the enactment of Code section 401(a)(9)(I).

7.7 Mandatory Tax Withholding and Direct Rollovers

(a)General Rule. Notwithstanding any Plan provision to the contrary, all withdrawals and other distributions under this Plan shall comply with the requirements of this section, Code section 401(a)(31), the Treasury Regulations thereunder, and related regulatory rules. Under this section, a Distributee entitled to a current withdrawal or distribution from the Plan may elect, at the time and in the manner prescribed by the Administrative Committee, to have any portion of an Eligible Rollover Distribution paid directly to an Eligible Retirement Plan. In prescribing the manner of making elections with respect to Eligible Rollover Distributions, the Administrative Committee may provide for a uniform,

nondiscriminatory application of any restrictions permitted under applicable sections of the Code, Treasury Regulations, and related regulatory rules, including a requirement that a Distributee may not elect to make a Direct Rollover from a single Eligible Rollover Distribution to more than one Eligible Retirement Plan.

(b)Special Definitions. In addition to the terms defined in Plan section 2.1 or elsewhere in this Plan, whenever used in this Plan section, the following terms shall have the respective meanings set forth below, unless expressly provided otherwise. When the defined meaning is intended, the term is capitalized.

(1)“Direct Rollover” means an Eligible Rollover Distribution that is paid directly to an Eligible Retirement Plan at the direction and for the benefit of the Distributee.

(2)“Distributee” means a Participant, a Participant’s surviving Spouse or a Participant’s Spouse who is the Alternate Payee.

Effective for distributions made after December 31, 2009 on behalf of a deceased Participant to a Beneficiary who is neither the Participant’s surviving Spouse or the Participant’s former Spouse and Alternate Payee, the non-spouse Beneficiary shall be a Distributee and the distribution will be treated as an Eligible Rollover Distribution if the following requirements are met. The distribution must made on behalf of the non-spouse Beneficiary in a direct transfer to an individual retirement account, described in Code section 408(a), or an individual retirement annuity, described in Code section 408(b) that is treated as an inherited individual retirement account or annuity for purposes of Code section 408(d)(3)(C). In addition, Code section 401(a)(9)(B), other than clause (iv) thereof relating to required minimum distributions to the Beneficiary, shall apply to the inherited individual retirement account or annuity.

(3)“Eligible Retirement Plan” is an individual retirement account described in Code section 408(a), an individual retirement annuity described in Code section 408(b) (other than an endowment contract), an annuity plan described in Code section 403(a), a qualified trust described in Code section 401(a) that accepts the Distributee’s Eligible Rollover Distribution, an annuity contract described in Code section 403(b); an eligible deferred compensation plan under Code section 457(b) which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state and which agrees to separately account for amounts transferred into such plan from this Plan; and a Roth IRA described in Code section 408A(b).

(4)“Eligible Rollover Distribution” means any distribution of all or any portion of the balance to the credit of the Distributee, except that an Eligible Rollover Distribution does not include:

(A)Any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the Distributee and the Distributee’s designated Beneficiary, or for a specified period of ten years or more;

(B)Any distribution to the extent the distribution is required under Code section 401(a)(9) and related Treasury Regulations;

(C)Any loan that is treated as a deemed distribution pursuant to Code section 72(p);

(D)Any dividends paid on employer securities and passed through to the Participant, Alternate Payee or Beneficiary, as described in Code section 404(k);

(E)A distribution that is a permissible withdrawal from an eligible automatic contribution arrangement within the meaning of section 414(w); and

(F)The portion of any distribution shall not fail to be an Eligible Rollover Distribution merely because such portion consists of After-Tax Contributions, which are not includable in gross income, if such portion is transferred to an individual retirement account or annuity described in Code section 408(a) or (b), to a qualified plan described in Code section 401(a) or 403(a), or to an annuity contract described in Code section 403(b) that agrees to separately account for amounts so transferred, including separately accounting for the portion of such distribution which is includable in gross income and the portion of such distribution which is not so includable. The portion of any distribution from a designated Roth account under the Plan shall not fail to be an Eligible Rollover Distribution if such portion is transferred to another Roth account under an applicable retirement plan described in Code section 402A(e)(1) or a Roth IRA described in Code section 408A.

Determinations of what constitutes an Eligible Rollover Distribution shall at all times be made in accordance with the current rules under Code section 402(c), which shall be controlling for this purpose.

(G)“Conversion” means a Direct Rollover of an Eligible Rollover Distribution from the Plan to the Roth IRA, within the meaning of Code section 408A. The amount rolled over is included in the gross income of the Distributee to the same extent that such amount

would have been included in gross income if not rolled over. A Conversion is not subject to mandatory income tax withholding under Code section 3405. A Distributee may elect a Conversion of an Eligible Rollover Distribution made on or after January 1, 2008.

7.8 In-Plan Roth Rollovers

(a)Participant Eligibility. A Participant may elect to roll over a distribution to an In-Plan Roth Rollover Account in accordance with the provisions of this section 7.8. A Participant may elect to rollover amounts held in the accounts described below in Plan section 7.8(b) without regard to whether the Participant satisfies the requirements for distribution in accordance with this Article VII. In-Plan Roth Rollover Contributions shall be subject to the same Plan rules as Roth Contributions. The Plan Administrator will maintain such records as are necessary for the proper reporting of In-Plan Roth Rollover Contributions and will administer the In-Plan Roth Rollover Account in accordance with Code section 402A and the regulations promulgated thereunder.

(b)Permitted Sources. The following contributions are permitted for roll over to the In-Plan Roth Rollover Account:

(1)After-Tax Account,

(2)After-Tax Rollover Account,

(3)Matching Account,

(4)Pre-Tax Account,

(5)Rollover Account, and

(6)SIP Accounts noted in Appendix G.1.

(c)Participant’s Spouse. Solely for the purposes of determining eligibility for an In-Plan Roth Rollover Contribution, the Plan will treat a Participant’s surviving Spouse, former Spouse or Alternate Payee Spouse as a Participant. A non-spouse beneficiary may not make an In- Plan Roth Rollover Contribution to the Plan.

(d)Form of Rollover. An In-Plan Roth Rollover Contribution must be made by the Participant in the form of a direct rollover. An In-Plan Roth Rollover Contribution may not include Plan loans.

(e)Distributions. The distribution provisions in Plan section 7.1 will apply to In-Plan Roth Rollover Contributions.

(f)Treatment of In-Plan Roth Rollover Contributions. Notwithstanding any other provision of the Plan to the contrary, an In-Plan Roth Rollover Contribution is not a Rollover or Roth Rollover Contribution for purposes of the Plan. Except for amounts withheld pursuant to a voluntary withholding election, an In-Plan Roth Rollover Contribution will not be treated as a

distribution for purposes of sections 72(p), 401(a)(11), or 411(d)(6)(B)(ii) of the Code. Amounts in a Participant’s In-Plan Roth Rollover Account may only be withdrawn by a Participant when the Participant is eligible for a distribution from the Plan under Article VII.

Article 8. Participant Loans

8.1 Availability of Loans

The Administrative Committee, in accordance with the following, may make loans to Participants who are Active Participants or Inactive Participants (referred to for purposes of this section as “Participants”) from the vested portion of the Participant’s Account. Loans shall (a) be made available on a reasonably equivalent basis, (b) not be made available to Highly Compensated Employees in an amount equal to a greater percentage of their vested Account balance or the percent made available to other loan applicants, (c) bear a reasonable rate of interest, and (d) be adequately secured by the Participant’s vested Account balance.

8.2 Amount of Loan

No loan (when added to the outstanding balance of all other loans made by the Plan to the Participant) shall exceed the lesser of:

(a)Fifty percent of the Participant’s vested Account, or

(b)Fifty thousand dollars, reduced by the highest outstanding balance of his or her loans from the Plan during the one year period ending on the date the loan is made over the outstanding balance of all of his or her Plan loans on the date on which such loan was made.

For the purpose of this limitation, all loans from all plans of the Employer are aggregated.

In accordance with Section 2202 of the CARES Act, for any loan made to a Qualified Individual during the March 27, 2020 through September 23, 2020 period, the maximum amount of a loan was increased to the lesser of $100,000 and 100% of the Participant’s Account. In addition, for any Qualified Individual with a loan outstanding on or after March 27, 2020, the Qualified Individual may delay repayment in accordance with Section 2202(b)(2) of the CARES Act and Notice 2020-50.

8.3 Procedures for Loans

The Administrative Committee shall promulgate written loan procedures which shall form part of the Plan which may include, but need not be limited to, the following information:

(a)The identity of the persons or positions authorized to administer the loan program.

(b)The procedure for applying for loans.

(c)The basis on which loans will be approved or denied.

(d)The limitations, if any, on the types and amount of loans offered.

(e)The procedure under the program for determining a reasonable rate of interest.

(f)The types of collateral which may secure a Participant’s loan.

(g)The events constituting default and the steps that will be taken to preserve Plan assets in the event of such default.

In the event of any conflict between the loan procedures and the provisions of this section, the loan procedures shall control.

Article 9. Investment Elections

9.1 Investment of Contributions

All Pre-Tax Deferrals, Roth Contributions, After-Tax Contributions, Adjustment Contributions, Catch-Up Contributions, Rollover Contributions, Roth Rollover Contributions, After-Tax Rollover Contributions, In-Plan Roth Rollover Contributions and loan repayments (both principal and interest) made by and on behalf of a Participant each Plan Year and amounts merged into the Plan shall be invested as the Participant shall designate in the Investment Funds then available in increments of 1 percent of the aggregate amount of such contributions. Participants may invest up to 30% of future Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions, In-Plan Roth Rollover Contributions and After-Tax Contributions in the Oxy Stock Fund, but no new Rollover Contributions or Roth Rollover Contributions may be invested in the Oxy Stock Fund. Notwithstanding any provision to the contrary, a Participant may not transfer any investment into the Oxy Stock Fund if the amount a Participant holds under the Oxy Stock Fund exceeds 30% of the Participant’s total Plan balance.

Each Participant may make the designation described above by making an election in accordance with procedures established by the Administrative Committee upon becoming a Participant and may change such election at any time by making another election in accordance with procedures established by the Administrative Committee. Any such election shall take effect as of the first available pay period after the election was received by the Administrative Committee.

The selection of any Investment Fund is the sole and exclusive responsibility of each Participant, and it is intended that the selection of an Investment Fund by each Participant be within the parameters of section 404(c) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) and the regulations thereunder. Neither the Employer, Administrative Committee, Investment Committee nor any of the directors, officers, agents or Employees of the Employer are empowered to or shall be permitted to advise a Participant as to the manner in which his Accounts shall be invested or changed. No liability whatsoever shall be imposed upon the Employer, the Trustees, any Committee member, or any director, officer, agent or Employee of the Employer for any loss resulting to a Participant’s account because of any sale or investment directed by a Participant under this section or because of the Participant’s failure to take any action regarding an investment acquired pursuant to such elective investment.

In the event that a Participant fails, or continues to fail, to designate the Investment Fund in which Pre-Tax Deferrals, Roth Contributions, After-Tax Contributions, Adjustment Contributions, Catch-Up Contributions, Rollover Contributions, Roth Rollover Contributions, After-Tax Rollover Contributions, In-Plan Roth Rollover Contributions, loan repayments, or amounts merged into the Plan that are to be invested, such amounts shall be invested in the default Investment Fund, which shall be the target date fund offered as an Investment Fund under the Plan that applies to the

Any amount previously defaulted into a default Investment Fund due to a Participant’s failure to designate an Investment Fund shall not be re-designated or transferred, unless the Participant otherwise transfers such amount in accordance with Plan section 9.2(a). The default Investment Fund described above is the Plan’s qualified investment alternative, as this term is defined in Department of Labor Regulations section 2550.404c-5(e).

Matching Contributions made on behalf of a Participant shall be invested in the Oxy Stock Fund.

9.2 Transfers of Existing Balances

(a)General Rules. Subject to any investment limitation or restriction imposed by the Investment Fund and except as provided in Plan section 9.5, each Participant, including Inactive Participants and Former Participants, as well as each Alternate Payee or spousal Beneficiary with an Account under the Plan may elect to transfer, in accordance with procedures established by the Administrative Committee, amounts invested in any Investment Fund to one or more Investment Funds then available in increments of 1 percent of the amount being transferred. If the election is received by the Administrative Committee by 4 p.m. (Central Time) on an Accounting Date, the transfer will be processed on that Accounting Date. Each election made under this Plan section shall be effective as of the first Accounting Date after the date in which notice thereof is received by the Administrative Committee. If the election is received by the Administrative Committee after 4 p.m. (Central Time) or on a date other than an Accounting Date, the transfer will be processed on the next Accounting Date. The Administrative Committee may impose such Investment Fund transfer fees as it deems reasonable and appropriate to defray the administrative expenses of the Plan. Any transfer of existing balances made under this Plan section does not affect the investment of future contributions, including loan repayments and amounts merged into this Plan, which will be invested as provided under Plan section 9.1 and the last investment election of the Participant filed thereunder.

(b)Oxy Stock Fund Transfers. A vested Participant may not transfer any investment into the Oxy Stock Fund if the amount a Participant holds under the Oxy Stock Fund exceeds 30% of the Participant’s total Plan balance.

(c)Qualified Plan Transfers. Nothing contained in this Plan section shall be construed as preventing a Participant, including Inactive Participants and Former Participants, from having amounts allocated to his or her Account in any Investment Fund transferred to one or more other Investment Funds for the purpose of facilitating an asset transfer to the trustee of a Qualified Plan sponsored by a purchaser or the subsidiary of a purchaser as a result of a transaction involving the sale by the Company or an Affiliate of either all or substantially all of the outstanding common stock of an Affiliate or all or

substantially all of the assets of a facility, under circumstances where the Participant or Inactive Participant is employed by the Affiliate or at the facility that is the subject of the sale.

9.3 Transfer of Assets

The Administrative Committee shall direct the Trustee to transfer monies or other property between Investment Funds as soon as is practicable after each Accounting Date to the extent required to carry out the aggregate contribution and transfer transactions as of such Accounting Date after the necessary entries have been made in the Accounts and offsetting transfer elections have been reconciled, in accordance with uniform rules established by the Administrative Committee.

9.4 Reserved

9.5 Matching Account Diversification Rights After August 1, 2004

This section is effective August 2, 2004 and shall apply notwithstanding any contrary provision of this Plan.

(a)Diversification Elections After August 1, 2004. A Qualified Participant shall have the right to transfer to other available Investment Funds, in accordance with Plan section 9.2, up to 100 percent of the current market value of the number of Units in the Oxy Stock Fund credited to his Matching Account.

(b)No Reinvestment. For the period from July 1, 2006 through March 30, 2007, the number of Units in a Qualified Participant’s Matching Account that have been transferred out of the Oxy Stock Fund as described in subsection (a) above may not be reinvested the Oxy Stock Fund.

(c)Election Procedures. Elections to transfer amounts from the Oxy Stock Fund among available Investment Funds shall be made pursuant to procedures established by the Administrative Committee. Each election made under this section shall be effective as of the first Accounting Date after the date on which the Administrative Committee properly receives the election.

(d)Authority. The Investment Committee shall have the authority to take any actions as may be appropriate or necessary to ensure the proper operation of the Plan and investment in the Oxy Stock Fund consistent with the provisions of this section.

(e)Qualified Participant. For purposes of this section, a “Qualified Participant” means:

(1)Effective August 2, 2004, a Participant, who has completed at least 10 years of Service under the Plan and has attained age 55;

(2)Effective January 1, 2005, a Participant, who has completed at least 10 years of Service under the Plan and has attained age 50;

(3)Effective March 1, 2005, a Participant, who has completed at least 5 years of Service under the Plan and has attained age 50;

(4)Effective July 1, 2006, a Participant, who has completed at least 5 years of Service under the Plan; and

(5)Effective January 1, 2007, a Participant, who has completed at least 3 years of Service under the Plan.

(6)Effective January 1, 2015, any Active Participant, regardless of the individual’s years of Service under the Plan.

Until July 1, 2006, the Service requirement described in paragraphs (1) through (4) must be met on or before a Participant incurs a Separation from Service. As of July 1, 2006, a Qualified Participant includes a Former Participant who has incurred a Separation from Service but only with respect to the portion of the vested portion of the Participant’s Matching Account as of his Separation from Service.

Article 10. Participant Accounts and Records of the Plan

10.1 Accounts and Records

The Participant’s Pre-Tax Account, Roth Account, Matching Account, After-Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account shall be assigned a subaccount for each Investment Fund in which the Account is invested. Each such subaccount shall be maintained and valued separately from all other subaccounts. The Administrative Committee shall maintain records relative to a Participant’s Accounts so that there may be determined as of any Accounting Date the current market value of his Accounts in the Trust Fund.

Each Participant, Alternate Payee and Beneficiary with an Account shall be advised from time to time, at least once each Plan Year, as to the value of his or her Account and the portions thereof attributable to his or her Matching Account and the sum of his or her Pre-Tax Account, Roth Account, Matching Account, After-Tax Account, Rollover Account, Roth Rollover Account, After- Tax Rollover Account and In-Plan Roth Rollover Account and to the various Investment Funds.

10.2 Account Value

As of any given date for which determination of the value of an Account is required, such value shall equal the sum of the value of Pre-Tax Account, Roth Account, Matching Account, After-Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account as of the preceding Accounting Date plus any additional contributions withheld or paid and less the amount of any withdrawals from such Account after the Accounting Date and prior to the date of determination.

10.3 Investment Funds

The Trust Fund shall consist of the Investment Funds, and each Account invested in an Investment Fund shall have an undivided proportionate interest in that Investment Fund. The Investment Committee shall have the right to determine the number of Investment Funds to be maintained by the Plan, and to increase or decrease that number from time to time as it deems appropriate. The Investment Committee shall establish additional Investment Funds or eliminate existing Investment Funds. In so doing, the Investment Committee shall implement and carry out investment objectives and policies which it shall establish and maintain.

10.4 Unit Value of Investment Funds

As of each Accounting Date, the Trustee shall determine the fair market value of the assets of each Investment Fund and shall notify the Administrative Committee of the value so determined. Assets for which there is a readily ascertainable market shall be valued by the Trustee at their fair market value, determined by the last known public sale on the Accounting Date as of which the market value is determined. In the absence of a sale on the Accounting Date, the fair market value of such assets, as well as other

assets for which there is no readily ascertainable fair market value, shall be determined by the Trustee in such consistent manner as the Trustee shall consider appropriate.

10.5 Calculation of Unit Value

The Trustee shall divide the aggregate value of the assets of each Investment Fund, as so determined, by the total number of outstanding Units in such Investment Fund on the Accounting Date. The result obtained shall be the new value of each Unit, or “Unit value,” as of the Accounting Date. The Unit value for all Investment Funds shall be ten dollars on the first Accounting Date in 1999.

10.6 Valuation Adjustments

As of each Accounting Date, after the Units in each Investment Fund have been revalued, the Administrative Committee shall adjust the balances in the Accounts in the respective Investment Funds of the Trust Fund, upward or downward, in proportion to the Account balance in the Investment Fund as of the previous Accounting Date. As a result, the sum of such Account balances will equal the net value of each Investment Fund of the Trust Fund as of that Accounting Date. The subaccounts shall then, when appropriate, be credited with additional Units by dividing the dollar amount of contributions, fund transfers, loan repayments, and dividends paid with respect to Oxy Stock to be allocated to each subaccount on that Accounting Date by the newly calculated value of a Unit in the Investment Fund.

10.7 Debiting of Accounts upon Distribution, Withdrawal, Loan or Charge

Any Units distributed or withdrawn from an Account (including any Units debited as a result of an Investment Fund transfer fee or redemption fee imposed pursuant to Plan section 9.2) shall be charged to the respective subaccounts in each Investment Fund as of the date the benefit or charge is payable. The amount distributable or chargeable to the Account shall be equal to the number of Units distributed or charged from the Account multiplied by the Unit value determined as of the Accounting Date immediately preceding the date as of which the distribution or charge is payable.

10.8 Unit Value upon Transfer of Investment Funds

Participants, Alternate Payees and Beneficiaries electing to transfer from one Investment Fund to another under Plan section 9.2 shall, as of the Accounting Date of the transfer, have their Accounts in the Investment Fund from which the transfer is made charged and their Accounts in the Investment Fund to which the transfer is made credited, based upon the applicable Investment Fund Unit values in effect as of the Accounting Date.

10.9 Oxy Stock Fund Valuation

The balance of each Matching Account and, separately, any other portion of the Account invested in the Oxy Stock Fund shall be maintained in full and fractional Units.

All Oxy Stock acquired by the Oxy Stock Fund, including, but not by way of limitation,

Oxy Stock contributed directly by the Employer or purchased with the contributions, Oxy Stock purchased with cash dividends paid in respect of Oxy Stock, Oxy Stock acquired from stock dividends and stock splits, and Oxy Stock purchased with the proceeds of the sale or exchange of warrants, rights or dividends in kind distributed in respect of Oxy Stock, shall be allocated to the Accounts based on the portion of the Account invested in the Oxy Stock Fund as of the Accounting Date in which the Oxy Stock is acquired.

For the purpose of valuing an Account in connection with any withdrawal or loan under the provisions of the Plan or for the purpose of any distribution in kind or partly in kind, shares of Oxy Stock shall be valued as of the Accounting Date of the withdrawal, loan, or distribution based on the closing quotation on the New York Stock Exchange on the Accounting Date in which such withdrawal, loan, or distribution is made; provided, however, that if shares of Oxy Stock are sold in connection with such a withdrawal, loan, or distribution, the shares sold shall be valued at the net proceeds received from such sale. If the closing price of such Oxy Stock shall not be so quoted or if so quoted shall not be available to the Administrative Committee, a composite index price or other price which shall be generally accepted for the establishment of fair market value shall be used for the purpose of so valuing the Account.

For the purpose of valuing an Account in connection with any transfer under the provisions of the Plan, shares of Oxy Stock shall be valued as of the effective date of the transfer based on the closing quotation on the New York Stock Exchange on the Accounting Date in which such transfer is made; provided, however, that if shares of Oxy Stock are sold in connection with such transfer, the shares sold shall be valued at the net proceeds received from such sale. If the closing price of such Oxy Stock shall not be so quoted or if so quoted shall not be available to the Administrative Committee, a composite index price or other price which shall be generally accepted for the establishment of fair market value shall be used for the purpose of so valuing the Account.

With respect to the warrants received by the Plan in August 2020, the Account of each Participant whose Account held an interest in the Oxy Stock Fund at the close of business on July 6, 2020 will be allocated a proportionate interest in all the warrants received by the Plan based on the Participant’s Oxy Stock Fund units on July 6, 2020. Such proportionate interest will be allocated to each Participant in a separate warrant account established on behalf of each Participant. If the investment manager appointed by the Investment Committee with respect to the warrants sells the warrants for cash or exercises the warrants to purchase additional Oxy Stock, any proceeds from the sale or exercise will be allocated to the Participant’s Account and invested in the Oxy Stock Fund.

10.10 Value of Accounts

The value of the balance of any Account as of any Accounting Date shall equal:

(a)The number of Units credited to the Account as of that date, including Units credited on that date pursuant to Plan section 10.6, multiplied by the Unit value determined as of the Accounting Date, plus

(b)Any uninvested cash in the Account.

10.11 Cost Account

The Trustee shall maintain records so that the cost or “basis” (for tax purposes) of the Oxy Stock allocated to an Account may be determined as of any Accounting Date. Whenever shares of Oxy Stock are distributed from the Account, such shares shall be assigned a cost equal to the average cost of all shares allocated at the same time in accordance with rules and procedures adopted for the purpose by the Administrative Committee.

10.12 Rollover and Roth and After-Tax Rollover Contributions

(a)Subject to the Administrative Committee’s approval and in accordance with uniform and nondiscriminatory procedures adopted by the Administrative Committee, Active or Inactive Participants may contribute, under the conditions specified in this Plan section, to this Plan any of the amounts specified as Rollover Contributions, Roth Rollover Contributions or, on and after January 1, 2020, After-Tax Rollover Contributions. Rollover Contributions will be held in the Participant’s Rollover Account. Roth Rollover Contributions will be held in the Participant’s Roth Rollover Account. After-Tax Rollover Contributions will be held in the Participant’s After-Tax Rollover Account.

(b)The amount must have been received by or on behalf of the Participant as an eligible rollover distribution, as defined in Code section 402(c)(4).

(1)In the case of direct rollovers, the distribution must be received directly from:

(A)A Qualified Plan;

(B)An annuity plan described in Code section 403(a);

(C)An annuity contract described in Code section 403(b);

(D)An eligible plan under Code section 457(b) which is maintained by a state, a political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state; or

(E)An individual retirement account described in Code section 408(a) consisting of amounts eligible as Rollover Contributions.

(2)In the case of a Rollover Contribution or Roth Rollover Contribution by the Participant, as opposed to a direct rollover, the contribution must meet the requirements established by the Administrative Committee and the requirements of Code section 402(c)(3); provided that any Roth amounts must be received as a direct rollover from another designated Roth account in a Qualified Plan.

(3)On a uniform and nondiscriminatory basis, the Administrative Committee or the Company may permit direct rollovers of promissory notes in connection with a loan under a Qualified Plan pursuant to Treasury Regulations section 1.401(a)(31)–1, Q&A–16. The Administrative Committee may establish such reasonable procedures as it deems necessary to facilitate the direct rollover of the promissory notes and to ensure that after the rollover, each loan under the Plan complies with Code section 72(p), ERISA section 408(b)(1), and the regulations thereunder. By way of illustration and not limitation, the Administrative Committee may reamortize directly rolled over loans to accommodate repayment of the loans in conjunction with the payroll schedules of an Employer so as to comply with the maximum permitted term of the loan, or may require a Participant to execute such modification to an existing loan that is rolled over, as the Administrative Committee deems, in its sole discretion, necessary to comply with Code section 72(p), ERISA section 408(b)(1), or the regulations thereunder.

(c)Before accepting an amount as a Rollover, Roth Rollover or After-Tax Rollover Contribution, the Administrative Committee may require such information and documents it deems necessary or appropriate to establish that the contribution will satisfy the requirements of this Plan section and that receipt of the contribution will not adversely affect the qualified status of this Plan. To the extent deemed necessary or appropriate by the Administrative Committee, such information may include copies of one or more of the following: IRS Form 1099, a distribution statement, the distribution check, certifications from the Participant, and statements from the administrator of the transferor plan that such plan had received a favorable determination letter from the Internal Revenue Service.

(d)Rollover, Roth Rollover and After-Tax Rollover Contributions, other than a promissory note evidencing a Participant loan that is rolled over, shall be invested in such Investment Funds as the Participant shall select, in accordance with such rules as are provided in Article 9, or in accordance with other procedures approved by the Administrative Committee. Rollover, Roth Rollover and After-Tax Rollover Contributions to this Plan will not be accepted unless the Participant has made an affirmative investment election with respect to his or her Rollover, Roth Rollover or After-Tax Rollover Account under Article 9. Notwithstanding the foregoing, in no event shall Rollover, Roth Rollover or After-Tax Rollover Contributions be invested in the Oxy Stock Fund.

(e)If a Rollover, Roth Rollover or After-Tax Rollover Contribution is made to this Plan and the Administrative Committee later determines that the contribution did not satisfy the requirements of this Plan section, then the Rollover, Roth Rollover or After-Tax Rollover Contribution, plus any earnings attributable to the Rollover, Roth Rollover or After-Tax Rollover Contribution, shall be

distributed to the Participant, within a reasonable time after the Administrative Committee’s determination. The Administrative Committee may use any reasonable method to determine the amount of earnings attributable to the Rollover, Roth Rollover or After-Tax Rollover Contribution.

(f)The balance in a Participant’s Rollover, Roth Rollover or After-Tax Rollover Account shall be distributed at the same time and in the same manner as other amounts in the Participant’s Account. Any questions concerning entitlement to a distribution of a Rollover, Roth Rollover or After-Tax Rollover Account shall be resolved by adding the term “and Rollover, Roth Rollover or After-Tax Rollover Account” in each place where the term “Account” appears in Article 7.

10.13 Merger of the THUMS Long Beach Company Savings and Investment Plan

Effective as of October 31, 2011, the THUMS Long Beach Company Savings and Investment Plan is merged with and into this Plan. The entire interest of each individual, who was a participant in the THUMS Long Beach Company Savings and Investment Plan on October 28, 2011, shall be transferred to this Plan and Appendix G shall control the treatment of such interest as stated therein.

Article 11. Financing

11.1 Trust Fund

The Company shall maintain a trust to finance the benefits under the Plan, by entering into one or more Trust Agreements or insurance contracts approved by the Company, or by causing insurance contracts to be held under a Trust Agreement. Any Trust Agreement is designated as and shall constitute a part of this Plan, and all rights which may accrue to any person under this Plan shall be subject to all the terms and provisions of such Trust Agreement.

After March 25, 2020, the Administrative Committee shall have the sole authority to appoint, remove, or replace the Trustee with a successor Trustee or Trustees, to enter into one or more Trust Agreements, and to modify any Trust Agreement from time to time to accomplish the purposes of the Plan. By entering into such Trust Agreements, the Administrative Committee shall vest in the Trustee, or in one or more investment managers (as defined under ERISA) appointed under the terms of the Trust Agreement from time to time by action of the Investment Committee, responsibility for the management and control of the Trust Fund. In the event the Investment Committee appoints any such investment manager, the Trustee shall not be liable for the acts or omissions of the investment manager or have any responsibility to invest or otherwise manage any portion of the Trust Fund subject to the management and control of the investment manager. The Investment Committee from time to time shall establish a funding policy which is consistent with the objectives of the Plan and shall communicate it to the Trustee and each investment manager so that they may coordinate investment policies with such funding policy.

11.2 Oxy Stock Fund

(a)General Rules. The Oxy Stock Fund shall consist of shares of Oxy Stock and cash or cash equivalents that are held pending investment in Oxy Stock. Investment in such shares shall be made from time to time by a direct issue of Oxy Stock from the Company or by purchase from securities dealers or by private purchase at such prices and in such amounts as the Trustee may determine in its absolute and complete discretion. However, no private purchase of such shares shall be made at a total cost greater than the total cost (including brokers’ fees and other expenses of purchase) of purchasing such shares at the then prevailing price of such shares on the open market, such prevailing price to be determined by the Trustee as nearly as practicable based on the most recent public trading prices for the Oxy Stock. The Trustee may match purchases and sales to satisfy investment elections, withdrawals, loans and distributions of Participants.

The Trustee in its discretion may limit the daily volume of its purchases or sales of Oxy Stock to safeguard interest of Participants or comply with legal or exchange requirements. If the Trustee limits daily volume then the purchase

prices or sale proceeds, as the case may be, during the period of volume limitations, shall be averaged, and the average per share price or sale proceeds shall be used in determining the cost or proceeds to be applied in satisfaction of any order of a Participant which requires the Trustee to purchase or sell Oxy Stock during such period.

All Oxy Stock purchased by the Trustee shall be registered in the name of the Trustee or its nominee, and legal title to such Oxy Stock shall remain in the Trustee until the Participant shall become entitled to distribution thereof pursuant to this Plan.

The Trustee in its own discretion may invest funds awaiting investment in Oxy Stock in short-term obligations, including obligations of the United States of America or any agency or instrumentality thereof, trust and participation certificates, beneficial interests in any trust, and such other short-term obligations as the Trustee deems to be appropriate for such interim investment purposes.

In the event any option, right or warrant is received by the Trustee on Oxy Stock, the independent fiduciary designated by the Investment Committee shall sell the same at public or private sale and at such price and upon such other terms as it may determine, unless the independent fiduciary shall determine that such option, right or warrant should be exercised, in which case the independent fiduciary shall exercise the same upon such terms and conditions it may prescribe.

(b)Election Restrictions for Officers. Investment elections of Company officers shall be limited, if necessary, so that the beneficial interest in the Oxy Stock held by the Trust Fund for their Accounts shall not exceed, in the aggregate, 20 percent of the total value of all securities and other assets held by the Trust Fund in all Investment Funds. For purposes of this section, the term “officers” shall have the same meaning as set forth in Regulations section 240.3-b-2 promulgated pursuant to section 3(b) of the Securities Exchange Act of 1934.

(c)Voting Rights. Before each annual or special meeting of the shareholders of the Company, and at such other times when shareholder action is required, the Company or Trustee (as determined under the applicable Trust Agreement) shall send to each Participant, Beneficiary and Alternate Payee who has an investment in Oxy Stock through the Oxy Stock Fund, the proxy or consent solicitation materials that are sent to the Company’s shareholders of record. Each such Participant, Beneficiary and Alternate Payee shall have the right to instruct the Trustee confidentially as to the method of voting the shares of Oxy Stock allocated to the Account (through investment in the Oxy Stock Fund) as of the record date for determining the shares that are entitled to vote at the meeting of shareholders or that are entitled to give or withhold consent to corporate action. The Trustee in accordance with the instructions received from the Participant, Beneficiary, or Alternate Payee shall vote such full and fractional shares of Oxy Stock. The Administrative Committee shall instruct the Trustee as to the method

of voting shares of Oxy Stock for which timely voting instructions are not received from Participants, Beneficiaries or Alternate Payees. The Trustee shall not vote shares of Oxy Stock for which it does not receive voting instructions from Participants, Beneficiaries, Alternate Payees or the Administrative Committee. The Company shall ensure that the requisite voting forms, together with all information distributed to shareholders regarding the exercise of voting rights, are furnished to the Trustee and by the Trustee to such Participants, Beneficiaries and Alternate Payees within a reasonable time before such voting rights are to be exercised with respect to Oxy Stock held in the Oxy Stock Fund.

(d)Distribution or Reinvestment of Cash Dividends. In accordance with procedures set forth in this subsection, as implemented by the Administrative Committee, each Participant who is a Participant in the ESOP portion of this Plan may make the dividend pass-through election described in this subsection with respect to dividends paid on or after June 1, 2002 on Oxy Stock held in the Oxy Stock Fund attributable to the Participant’s Matching Account and with respect to dividends paid on or after July 19, 2007 on all Oxy Stock held in the Oxy Stock Fund. The dividends on which the dividend pass-through election may be made are referred to as Eligible Dividends. Cash dividends that are not Eligible Dividends and cash proceeds from any other distribution received on Oxy Stock shall be invested in Oxy Stock.

(1)Pass-Through Election. With respect to Eligible Dividends, the Participant may elect between:

(A)Either:

(i)The cash payment of Eligible Dividends directly to the Participant; except effective August 8, 2016, if the amount of Eligible Dividends is less than $10.00, then the Eligible Dividends will be reinvested pursuant to Subsection (B) below; or

(ii)If permitted by the Administrative Committee, the payment of Eligible Dividends to the Participant’s Matching Account, Pre-Tax Account, Roth Account, After-Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account (based on the subaccount from which the Eligible Dividend is derived) followed by the distribution of Eligible Dividends in cash to the Participant not later than 90 days after the close of the Plan Year in which the Eligible Dividends were paid by the Company; and

(B)The payment of Eligible Dividends to the Participant’s Matching Account, Pre-Tax Account, Roth Account, After-Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account (based on the

subaccount from which the Eligible Dividend is derived) and reinvestment in Oxy Stock through the Oxy Stock Fund.

If the Participant does not make an affirmative election, he shall be deemed to have elected the reinvestment of Eligible Dividends pursuant to subparagraph (B). Any earnings on Eligible Dividends shall not be distributed pursuant to subparagraph (A)(ii), but any losses on such Eligible Dividends shall reduce the amount that can be distributed to the Participant under such provision. The Participant’s election in effect on the ex-dividend date for the Eligible Dividend shall control. A Participant may not split his election between subparagraph (A) and subparagraph (B) with respect to any single Eligible Dividend payment date.

(2)Election Requirements. The dividend pass-through election shall meet the following minimum requirements:

(A)A Participant must be given a reasonable opportunity before Eligible Dividends are paid or distributed in which to make the election.

(B)A Participant must have a reasonable opportunity to change a dividend election at least annually.

(C)If there is a change in the Plan terms governing the manner in which Eligible Dividends are paid or distributed, a Participant must be given a reasonable opportunity to make an election under the new Plan terms prior to the date on which the first Eligible Dividend subject to the new Plan terms is paid or distributed.

(D)No election shall be applied retroactively; elections shall apply only to future dividend allocations.

(3)Treatment of Eligible Dividends. Eligible Dividends shall be treated as follows for purposes of the Plan:

(A)A Participant shall at all times be fully vested in any Eligible Dividends with respect to which the Participant is offered a dividend pass-through election. The Participant shall be fully vested regardless of whether the Eligible Dividends are paid in cash or reinvested in Oxy Stock allocated to the Participant’s Account and regardless of whether the Participant is vested or nonvested in other amounts held in his Matching Account.

(B)Eligible Dividends, whether paid in cash to the Participant or reinvested in the Plan, do not constitute an Annual Addition. In addition, reinvested Eligible Dividends do not constitute elective deferrals, within the meaning of Code section 402(g)(3), and shall not be treated as Pre-Tax Deferrals, Roth Contributions or other elective deferrals, under the ADP Test, or After-Tax Contributions, Adjustment Contributions or Matching Contributions under the ACP Test.

(C)Eligible Dividends that are reinvested in Oxy Stock pursuant to a Participant’s election under this subsection are treated as earnings in the same manner as dividends with respect to which a Participant is not provided a dividend pass- through election.

(D)Eligible Dividends paid in cash pursuant to a Participant’s election under this subsection:

(i)Are not subject to the consent requirements of Code section 411(a)(11) or the restrictions on the distributions of elective deferrals under Code section 401(k)(2)(B), notwithstanding any Plan provision to the contrary; and

(ii)Do not constitute an Eligible Rollover Distribution (as determined under Plan section 7.7(b)(4)), even if the dividends are distributed at the same time as amounts that do constitute an Eligible Rollover Distribution.

(4)Alternate Payees and Beneficiaries. Subject to such rules as the Administrative Committee may prescribe, Alternate Payees and Beneficiaries shall be treated as Participants for purposes of this subsection.

11.3 Forfeitures

The Administrative Committee may use forfeitures occurring in any processing period to pay the reasonable costs of administering the Plan to the maximum extent permitted by ERISA or to reduce Matching Contributions of all Employers without regard to whether the forfeitures are attributable to persons employed by any individual Employer for such processing period or future processing periods. If the amount of allocable forfeitures occurring in a processing period exceeds the amount of Employer contributions for such processing period, then the excess shall be deposited in a separate account. Effective December 1, 2016, or as soon as practicable thereafter but in no event later than December 31, 2016, such amounts will be deposited into a separate “Forfeiture Account,” invested in the Stable Value Fund or such other Investment Fund as determined within the discretion of the Administrative Committee, and such amounts will be considered Plan assets and allocated in lieu of Employer contributions in succeeding pay periods, used to pay the reasonable expenses of administering the Plan or allocated among Participants as additional contributions. If the Plan terminates while a balance in the Forfeiture Account exists, the balance shall be allocated to Participants per capita to the extent of the maximum amount permitted under Plan section 6.6. Forfeitures shall be used before the end of the Plan Year in which the forfeitures occurred to the extent administratively feasible. Effective on and after January 1, 2025, any amounts allocated to the Forfeiture Account shall be used in lieu of Employer contributions, and, if any amounts in the Forfeiture Account remain outstanding after the full required Employer contribution is made under Article 5 for a Plan Year for each eligible Participant, the Administrative Committee shall use any remaining forfeitures

to pay the reasonable costs of administering the Plan to the maximum extent permitted by ERISA.

11.4 Non-Reversion

Anything in this Plan to the contrary notwithstanding, it shall be impossible at any time for the contributions of the Employer or any part of the Trust Fund to revert to the Company or an Affiliate or to be used for or diverted to any purpose other than the exclusive benefit of Participants or their Beneficiaries, except that:

(a)If a contribution or portion thereof is made by the Employer by a mistake of fact, upon written request to the Administrative Committee, such contribution or such portion, reduced by losses but not increased by earnings, shall be returned to the Employer within one year after the date of payment; and

(b)In the event that a deduction for any contributions made by the Employer is disallowed by the Internal Revenue Service in any Plan Year, then that portion of the Employer contribution that is not deductible shall be returned to the Employer within one year from the date of receipt of notice by the Internal Revenue Service of the disallowance of the deduction.

11.5 Direct Transfer of Assets from Plans of Acquired Entities

The Trust Agreement shall permit the direct receipt of assets which are transferred directly to the Trust Fund from the trustees of any other Qualified Plan sponsored, at the time of the applicable transaction, by entities which are the subject of purchase transactions made by the Company or an Affiliate.

11.6 Pension Expense Reimbursement Account (“PERA”)

The Administrative Committee in its discretion may decide to use revenue sharing payments (i.e., float income earned on uninvested cash and all other revenue, if any, received from the investments in the Plan (other than operating expenses paid by mutual fund shareholders generally, whether via rebates or otherwise, that are reflected in the net asset values of such mutual fund shares)) for approved ERISA expenses. Such amounts as well as Participant-paid fees and Plan-imposed excessive trading fees will be deposited into a separate “ERISA Account,” invested in the Stable Value Fund, or such other fund as determined within the discretion of the Administrative Committee, and such amounts will be considered Plan assets. Amounts in the ERISA Account must be used for the direct benefit of Plan Participants, and any balances remaining in the ERISA Account at year end must be used by the end of the first quarter of the next Plan Year. Alternatively, the year-end balance must be allocated to Participant Accounts after this deadline. Approved ERISA expenses will include those reasonable, necessary and direct expenses incurred by the Plan for services provided by the Plan’s Trustee, recordkeeper or other service providers.

Article 12. Administration

12.1 The Administrative Committee

The Plan shall be administered by an Administrative Committee appointed by the Board; after March 25, 2020, the Administrative Committee shall be appointed by the Fiduciary Appointment Officer. The Administrative Committee shall be the Plan Administrator. The Administrative Committee shall be composed of as many members as the Board or, if after March 25, 2020, the Fiduciary Appointment Officer, may appoint from time to time, but not fewer than three members, and shall hold office at the discretion of the Fiduciary Appointment Officer.

Any member of the Administrative Committee may resign by delivering his or her written resignation to the Administrative Committee Secretary. Such resignation shall be effective no earlier than the date of the written notice.

Vacancies in the Administrative Committee arising by resignation, death, removal, or otherwise, shall be filled by the Fiduciary Appointment Officer. The Administrative Committee shall be a fiduciary under the Plan, in accordance with ERISA.

After March 25, 2020, the Fiduciary Appointment Officer shall have the sole authority to appoint, remove, replace, and monitor members of the Administrative Committee.

12.2 Chairperson, Secretary, and Employment of Specialists

The Fiduciary Appointment Officer shall appoint, from the members of each of the Investment Committee and Administrative Committee, a Chairperson and the members shall elect a Secretary who may, but need not, be a member of such Committee. In the event the Fiduciary Appointment Officer does not appoint a Chairperson, the members of each Committee shall select a Chairperson of their respective Committee. They may authorize one or more of their number or any agent to execute or deliver any instrument or instruments on their behalf, and may employ such counsel, auditors, and other specialists and such clerical, medical, actuarial, and other services as they may require in carrying out the provisions of the Plan.

12.3 Compensation and Expenses

The members of the Investment Committee and Administrative Committee who are Employees shall serve without compensation for services as a member of such Committee. Any member of a Committee may receive reimbursement by the Company of expenses properly and actually incurred.

All expenses of administration may be paid out of the Trust Fund, to the maximum extent permitted by ERISA, unless paid by the Company. Such expenses shall include any expenses incident to the functioning of the Administrative Committee and the Investment Committee, including but not limited to, fees of accountants, counsel, and other specialists and their agents, and other costs of administering the Plan. Until paid, the expenses shall constitute a liability of the Trust Fund. However, the Company may reimburse the Trust Fund for any administration expense incurred. The Company reserves the right to charge the Accounts for reasonable expenses incurred in the

administration of their Accounts. Any such charges shall be used to pay the costs of administering this Plan in the manner described in Plan section 11.3. The Company will make full disclosure of the amount and nature of any such charge prior to its imposition.

12.4 Manner of Action

A majority of the members of the Investment Committee and Administrative Committee at the time in office shall constitute a quorum for the transaction of business. All resolutions adopted, and other actions taken by a Committee at any meeting shall be by the vote of a majority of those present at any such meeting. Upon obtaining the written consent of a majority of the members at the time in office, action of a Committee may be taken otherwise than at a meeting.

12.5 Subcommittees

Each of the Investment Committee and Administrative Committee may appoint one or more subcommittees and delegate such of its power and duties as it deems desirable to any such subcommittee, in which case every reference herein made to such Committee shall be deemed to mean or include the subcommittees as to matters within their jurisdiction. The members of any such subcommittee shall consist of such officers or other Employees of the Company and such other persons as such Committee may appoint.

12.6 Other Agents

Each of the Board, the Company, the Administrative Committee and the Investment Committee may also appoint one or more persons or agents to aid it in carrying out its duties as fiduciary or nonfiduciary, and delegate such of its powers and duties as it deems desirable to such person or agents.

12.7 Records

All resolutions, proceedings, acts, and determinations of each of the Administrative Committee and the Investment Committee shall be recorded by the Secretary thereof or under the Secretary’s supervision, and all such records, together with such documents and instruments as may be necessary for the administration of the Plan, shall be preserved in the custody of the Secretary.

12.8 Rules

Subject to the limitations contained in the Plan, each of the Administrative Committee and the Investment Committee shall be empowered from time to time in its discretion to adopt by-laws and establish rules for the conduct of its affairs and the exercise of the duties imposed upon it under the Plan.

12.9 Administrative Committee’s Powers and Duties

Except as otherwise provided in this Plan, the Company shall have responsibility for any settlor powers, functions or duties, including, without limitation, the right to amend or terminate the Plan as set forth in Plan section 13.1. The Administrative Committee shall have responsibility for the general administration of the Plan and for carrying out the Plan’s provisions. The Administrative Committee shall have such powers and duties

as may be necessary to discharge its functions hereunder, including, but not limited to, the following:

(a)To construe and interpret the Plan, to supply all omissions from, correct deficiencies in and resolve ambiguities in the language of the Plan and Trust; to decide all questions of eligibility and determine the amount, manner, and time of payment of any benefits hereunder;

(b)To make a determination as to the right of any person to an allocation, and the amount thereof;

(c)To obtain from the Employees such information as shall be necessary for the proper administration of the Plan and, when appropriate, to furnish such information promptly to the Trustee or other persons entitled thereto;

(d)To prepare and distribute, in such manner as the Company determines to be appropriate, information explaining the Plan;

(e)To establish and maintain such accounts in the name of each Participant as are necessary;

(f)To instruct the Trustee with respect to the payment of benefits hereunder;

(g)To provide for any required bonding of fiduciaries and other persons who may from time to time handle Plan assets;

(h)To prepare and file any reports required by ERISA;

(i)To engage an independent public accountant to conduct such examinations and to render such opinions as may be required by ERISA;

(j)To select, engage, monitor and terminate the performance of third-party administrators and other service providers and develop policies with respect to service provider contracts to ensure that fees paid are reasonable;

(k)To allocate contributions, loan repayments and Trust Fund gains or losses to the Accounts of Participants;

(l)To take all steps it deems reasonable to correct any references or omissions that may arise in the operation of the Plan, which include taking any and all steps permitted under the Employee Plans Compliance Resolution System, the Voluntary Fiduciary Correction Program, or any other program of correction;

(m)To designate Affiliates as Employers as described in Plan section 14.1;

(n)To serve as the Plan Administrator for the Plan;

(o)To have the authority, in coordination with the Investment Committee, to appoint, remove or replace, the recordkeeper for the Plan;

(p)To have the authority to monitor the Trustee in connection with payments from the Trust Fund, including the payment of benefits; and

(q)To have the authority to appoint, remove, or replace the Trustee.

12.10 Investment Responsibilities

The Investment Committee shall have the authority and responsibility to direct and monitor the Trustee with respect to the investment and management of the Trust Fund, to appoint an investment manager, as defined in ERISA section 3(38), for the Plan’s Investment Funds, including the Oxy Stock Fund, and to establish a funding policy and method consistent with the objectives of the Plan and the requirements of ERISA. Except as otherwise provided in ERISA, the Investment Committee may delegate such authority and responsibility to direct and monitor the Trustee or any person who acknowledges in writing that it is a fiduciary with respect to the Plan and who provides the Investment Committee with a written affirmation that it is qualified to act as an investment manager within the meaning of ERISA. If the Investment Committee delegates to an investment manager the authority and responsibility to so direct and monitor the Trustee, such investment manager, and not the Investment Committee or the Trustee, shall have sole responsibility for the investment and management of so much of the Trust Fund as has been entrusted to his management and control, and, except to the extent otherwise required by ERISA, such delegation shall relieve the Investment Committee and the members thereof of all duties and responsibilities with respect to the authority and responsibility so delegated.

12.11 Administrative Committee’s Decisions Conclusive

The Administrative Committee shall have the exclusive right and discretionary authority to interpret the terms and provisions of the Plan, apply the facts to the terms of the Plan, and resolve all questions arising hereunder, including the right to resolve and remedy ambiguities, inconsistencies, or omissions in the Plan, provided, however, that the construction necessary for the Plan to conform to the Code and ERISA shall in all cases control. The Administrative Committee also shall have discretionary authority to make any factual determinations under the Plan. Benefits under this Plan will be paid only if the Administrative Committee decides in its discretion that the applicant is entitled to them. The Administrative Committee shall endeavor to act in such a way as not to discriminate in favor of any class of Employees, Participants, or other persons. Any and all disputes with respect to the Plan that may arise involving Participants, Beneficiaries or Alternate Payees shall be referred to the Administrative Committee and its decisions shall be final, conclusive, and binding. All findings of fact, interpretations, determinations, and decisions of the Administrative Committee in respect of any matter or question arising under the Plan shall be final, conclusive, and binding upon all persons, including, without limitation, Employees, Participants, Beneficiaries, Alternate Payees, and any and all other persons having, or claiming to have, any interest in or under the Plan. The factual determinations and decisions of the Administrative Committee shall be given the maximum possible deference allowed by law.

12.12 Indemnity

(a)To the extent permitted by the Company’s bylaws and applicable law, the Company shall indemnify and hold harmless each of the following persons (“Indemnified Persons”) under the terms and conditions of subsection (b):

(1)Each Affiliate;

(2)Each member of the Administrative Committee

(3)Each member of the Investment Committee; and

(4)Each Employee or member of the Board who has responsibility (whether by delegation from another person, an allocation of responsibilities under the terms of this Plan document, or otherwise) for a fiduciary duty, a nonfiduciary settlor function (such as deciding whether to approve a plan amendment), or a nonfiduciary administrative task relating to the Plan.

(b)The Company shall indemnify and hold harmless each Indemnified Person against any and all claims, losses, damages, and expenses, including reasonable attorney’s fees and court costs, incurred by that person on account of his good faith actions or failures to act with respect to his responsibilities relating to the Plan. The Company’s indemnification shall include payment of any amounts due under a settlement of any lawsuit or investigation, but only if the Company agrees to the settlement.

(1)An Indemnified Person shall be indemnified under this section only if he notifies an Appropriate Person at the Company of any claim asserted against or any investigation of the Indemnified Person that relates to the Indemnified Person’s responsibilities with respect to the Plan.

(A)A person is an “Appropriate Person” to receive notice of the claim or investigation if a reasonable person would believe that the person notified would initiate action to protect the interests of the Company in response to the Indemnified Person’s notice.

(B)The notice may be provided orally or in writing. The notice must be provided to the Appropriate Person promptly after the Indemnified Person becomes aware of the claim or investigation. No indemnification shall be provided under this section to the extent that the Plan or Company is materially prejudiced by the unreasonable delay of the Indemnified Person in notifying an Appropriate Person of the claim or investigation.

(2)An Indemnified Person shall be indemnified under this section with respect to attorneys’ fees, court costs or other litigation expenses or any settlement of such litigation only if the Indemnified Person agrees to permit the Company to select counsel and to conduct the defense of the lawsuit and agrees not to take any action in the lawsuit that the Company believes would be prejudicial to the interests of the Company.

(3)No Indemnified Person, including an Indemnified Person who had a Separation from Service, shall be indemnified under this section unless he makes himself reasonably available to assist the Company with respect to the matters in issue and agrees to provide whatever

documents, testimony, information, materials, or other forms of assistance that the Company shall reasonably request.

(4)No Indemnified Person shall be indemnified under this section with respect to any action or failure to act that is judicially determined to constitute or be attributable to the gross negligence or willful misconduct of the Indemnified Person.

(5)Payments of any indemnity under this section shall be made only from the assets of the Company and shall not be made directly or indirectly from assets of the Plan. The provisions of this section shall not preclude such further indemnities as may be available under insurance purchased by the Company or as may be provided by the Company under any by-law, agreement or otherwise, provided that no expense shall be indemnified under this section that is otherwise indemnified by an insurance contract purchased by the Company.

12.13 Fiduciaries

The fiduciaries named in this Article shall have only those specific powers, duties, responsibilities, and obligations as are specifically given them under this Plan or the Trust or otherwise delegated by the Board. The Employers shall have the sole responsibility for making the contributions required under Article 4 and Article 5, and the Company shall have the sole authority to appoint and remove the Trustee until March 25, 2020, and to amend or terminate, in whole or in part, this Plan or the Trust. After March 25, 2020, the Administrative Committee shall have the sole authority to appoint and remove the Trustee. The Administrative Committee shall have the sole responsibility for the administration of this Plan, which responsibility is specifically described in this Plan and the Trust Agreement or otherwise delegated by the Board. The officers and Employees of the Company shall have the responsibility of implementing the Plan and carrying out its provisions as the Administrative Committee shall direct. The Investment Committee, the Trustee, and any investment manager shall have the sole responsibility for the administration of the Trust Fund and the management of the assets held under the Trust Fund, to the extent provided in the Trust Agreement. A fiduciary may rely upon any direction, information, or action of another fiduciary as being proper under this Plan or the Trust Agreement, and is not required under this Plan or the Trust Agreement to inquire into the propriety of any such direction, information, or action. It is intended under this Plan and the Trust Agreement that each fiduciary shall be responsible for the proper exercise of his or its own powers, duties, responsibilities, and obligations under this Plan and the Trust Agreement and shall not be responsible for any act or failure to act of another fiduciary. No fiduciary guarantees the Trust Fund in any manner against investment loss or depreciation in asset value. Any party may serve in more than one fiduciary capacity with respect to the Plan or Trust Agreement.

Whether or not a particular activity performed by the Fiduciary Appointment Officer, Administrative Committee, Investment Committee, a Committee member, or delegate is considered to rise to the level of a fiduciary duty shall depend on whether the person or

entity is, when performing the activity, exercising the discretion with respect to the administration of the Plan, which under ERISA, if applicable, requires a fiduciary standard of conduct. In the absence of an activity involving such an exercise of discretion with respect to the Plan’s administration, the activity shall be considered ministerial, rather than fiduciary, in nature. If and when a Committee member or delegate is performing a “settlor” activity, under ERISA, including, by way of example, the adoption of an amendment to or decision to establish or terminate a plan, then such activity shall be deemed to be an exercise of “settlor” or sponsor responsibility and shall be subject to ordinary business judgment and not an exercise of fiduciary duty. The Fiduciary Appointment Officer, Administrative Committee, and Investment Committee will not be subject to fiduciary liability or standards for any settlor or non-fiduciary responsibilities and/or duties delegated to it by the Board.

12.14 Notice of Address

Each person entitled to benefits from the Plan must file with the Administrative Committee or its agent, in writing, his post office address and each change of post office address. Any communication, statement, or notice addressed to such a person at his latest reported post office address will be binding upon him for all purposes of the Plan, and neither the Administrative Committee nor the Company or any Trustee shall be obliged to search for or ascertain his whereabouts.

12.15 Data

All persons entitled to benefits from the Plan must furnish to the Company such documents, evidence, or information, including information concerning marital status, as the Company considers necessary or desirable for the purpose of administering the Plan; and it shall be a condition of the Plan that each such person must furnish such information and sign such documents as the Company may require before any benefits become payable from the Plan. The Administrative Committee shall be entitled to distribute benefits to a non-Spouse beneficiary in reliance upon the signed statement of the Participant that he is unmarried without any further liability to a Spouse if such statement is false.

12.16 Benefit Claims Procedures

The provisions of this section shall be subject to, and shall apply to, the extent required under Department of Labor Regulations section 2560.503-1 (relating to the requirements of claims procedures). All decisions made under the procedures described in this section shall be final and there shall be no further right of appeal. No lawsuit may be initiated by any person before fully pursuing the procedures set out in this section, including the appeal permitted pursuant to subsection (d).

(a)The right of a Participant, Beneficiary, Alternate Payee, or any other person entitled to claim a benefit under the Plan shall be determined by the Administrative Committee, provided, however, that the Administrative Committee may delegate its responsibility to any person. All persons entitled to claim a benefit under the Plan shall be referred to as a “Claimant” for purpose of this section. The term “Claimant” shall also include, where appropriate to the

context, any person authorized to represent the Claimant under procedures established by the Administrative Committee.

(1)The Claimant may file a claim for benefits by written notice to the Administrative Committee.

(2)Any claim for benefits under the Plan, pursuant to this section, shall be filed with the Administrative Committee no later than eighteen months after the date that a transaction occurred, or should have occurred, with respect to a Claimant’s Account (e.g., two years after benefits were credited, or should have been credited, to a Claimant’s Account, or eighteen months after any withdrawal or distribution occurred or should have occurred). The Administrative Committee in its sole discretion shall determine whether this limitation period has been exceeded.

(3)Notwithstanding anything to the contrary in this Plan, the following shall not be a claim for purposes of this section:

(A)A request for determination of eligibility, enrollment, or participation under the Plan without an accompanying claim for benefits under the Plan. The determination of eligibility, enrollment, or participation under the Plan may be necessary to resolve a claim, in which case such determination shall be made in accordance with the claims procedures set forth in this section.

(B)Any casual inquiry relating to the Plan, including an inquiry about benefits or the circumstances under which benefits might be paid under the Plan.

(C)A claim that is defective or otherwise fails to follow the procedures of the Plan (e.g., a claim that is addressed to a party, other than the Administrative Committee, or an oral claim).

(D)An application or request for benefits under the Plan.

(b)If a claim for benefits is wholly or partially denied, the Administrative Committee shall, within a reasonable period of time, but no later than 90 days after receipt of the claim (or 45 days after receipt of the claim in the case of a disability claim), notify the Claimant of the denial of benefits. In the case of a claim other than a disability claim, if special circumstances justify extending the period up to an additional 90 days, the Claimant shall be given written notice of this extension within the initial 90-day period, and such notice shall set forth the special circumstances and the date on which a decision is expected. In the case of a disability claim, the Administrative Committee may give the Claimant written notice before the end of the initial 45-period that it needs an additional 30 days to review the claim, provided that such notice shall set forth the circumstances beyond the control of the Administrative Committee justifying extending the period and the date on which a decision is expected. If special circumstances beyond the control of the Administrative Committee’s control justify extending

the claim review period for an additional 30 days, the Claimant shall be provided written notice of this extension within the first 30-day period.

(c)A notice of denial:

(1)Shall be written in a manner calculated to be understood by the Claimant; and

(2)Shall contain:

(A)The specific reasons for denial of the claim;

(B)Specific reference to the Plan provisions on which the denial is based;

(C)A description of any additional material or information necessary for the Claimant to perfect the claim, along with an explanation as to why such material or information is necessary; and

(D)An explanation of the Plan’s claim review procedures and the time limits applicable to such procedures, including a statement of the Claimant’s right to bring a civil action under ERISA section 502(a) following an adverse determination on review.

(d)Within 60 days of the receipt by the Claimant of the written denial of his or her claim (or within 180 days of receipt in the case of a disability claim) or, if the claim has not been granted, within a reasonable period of time (which shall not be less than the applicable time period specified in subsection (b)), the Claimant may file a written request with the Administrative Committee that it conduct a full review of the denial of the claim. In connection with the Claimant’s appeal, upon request, the Claimant may review and obtain copies of all documents, records and other information relevant to the Claimant’s claim for benefits, but not including any document, record or information that is subject to any attorney-client or work-product privilege or whose disclosure would violate the privacy rights or expectations of any person other than the Claimant. The Claimant may submit issues and comments in writing and may submit written comments, documents, records, and other information relating to the claim for benefits. All comments, documents, records, and other information submitted by the Claimant shall be taken into account in the appeal without regard to whether such information was submitted or considered in the initial benefit determination.

(e)The Administrative Committee shall deliver to the Claimant a written decision on the claim promptly, but no later than 60 days (or 45 days in the case of a disability claim) after the receipt of the Claimant’s request for such review, unless special circumstances exist that justify extending this period up to an additional 60 days (or 45 days in the case of a disability claim). If the period is extended, the Claimant shall be given written notice of this extension during the initial 60-day period (or 45-day period in the case of a disability claim) and such notice shall set forth the special circumstances and the date a decision is expected. The decision on review of the denial of the claim:

(1)Shall be written in a manner calculated to be understood by the Claimant;

(2)Shall include specific reasons for the decision;

(3)Shall contain specific references to the Plan provisions on which the decision is based;

(4)Shall contain a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and other information relevant to the Claimant’s claim for benefits; and

(5)Shall contain a statement of the Claimant’s right to bring a civil action under ERISA section 502(a) following an adverse determination on review.

(f)No legal action may be commenced after the later of:

(1)180 days after receiving the written response of the Administrative Committee to an appeal, or

(2)365 days after the Claimant’s original application for benefits.

(g)Any legal action in connection with the Plan must be filed in Harris County, Texas or the U.S. District Court for the Southern District of Texas. Notwithstanding the preceding sentence, in the event that the Administrative Committee exercises its right to initiate an interpleader action pursuant to Section 12.16(h), the Administrative Committee may in its discretion file such interpleader action in (i) a court in the state in which the Participant resides (or, in the event of the Participant's death, resided at the time of his death), (ii) a court in the state in which at least one claimant of the Participant's benefit resides or (iii) a court described in the first sentence of this Section 12.16(g).

(h)The Administrative Committee reserves the right, in its sole discretion, to initiate an interpleader action to resolve any competing claims for a benefit under the Plan or to determine the proper beneficiary of any benefit under the Plan.

12.17 Member’s Own Participation

No member of the Administrative Committee or the Investment Committee may act, vote or otherwise influence a decision of the committee on which he or she serves specifically relating to his or her own participation under the Plan.

Article 13. Amendment and Termination

13.1 Amendment and Termination

The Company expects the Plan to be permanent and to continue indefinitely; however, this Plan is purely voluntary on the part of the Company and each Employer. The Company must necessarily and does hereby reserve the right to amend, modify, or terminate the Plan at any time by action of its Board. After March 25, 2020, the Plan Amendment Officer shall have the authority to amend or modify the Plan on behalf of the Company in its plan sponsor capacity as long as the amendment or modification (i) is necessary or appropriate to qualify or maintain the Plan’s tax-qualified status or to comply with other legal requirements or (ii) does not significantly decrease benefits or significantly increase costs to the Company and its Affiliates.

13.2 Distribution on Termination

Upon termination of the Plan in whole or in part, or upon complete discontinuance of contributions to the Plan by the Company, the value of the proportionate interest in the Trust Fund of each Participant affected by such termination shall be determined by the Administrative Committee as of the date of such termination or discontinuance. The Accounts of such Participants shall be fully vested and nonforfeitable, and thereafter distribution shall be made to such Participants as directed by the Administrative Committee.

Upon the partial termination of the Plan, the Board may in its sole discretion determine the timing of a distribution of the balance of the affected Participants’ Accounts.

13.3 Successors

In case of the merger, consolidation, liquidation, dissolution or reorganization of an Employer, or the sale by an Employer of all or substantially all of its assets, provision may be made by written agreement between the Company and any successor corporation acquiring or receiving a substantial part of the Employer’s assets, whereby the Plan and the Trust Agreement will be continued by the successor. If the Plan is to be continued by the successor, then effective as of the date of the reorganization or transfer, the successor corporation shall be substituted for the Employer under the Plan and the Trust Agreement. The substitution of a successor corporation for an Employer will not in any way be considered a termination of the Plan.

13.4 Plan Merger or Transfer

This Plan shall not merge or consolidate with, or transfer assets and liabilities to, or accept a transfer from, any other employee benefit plan unless each Participant, Beneficiary, or Alternate Payee in this Plan will (if the Plan had then terminated) receive a benefit immediately after the merger, consolidation, or transfer which is not less than the benefit the Participant, Beneficiary, or Alternate Payee would have been entitled to receive immediately before the merger, consolidation, or transfer of assets (if this Plan had then terminated). Subject to these limitations, the Plan may transfer assets and liabilities to, or accept a transfer of assets and liabilities from, any other employee benefit plan which is

qualified under Code section 401(a) where such a transfer has been authorized by agreement between the Company and the sponsor of the other employee benefit plan and is not prohibited by law.

Article 14. Participating Affiliates

14.1 Adoption of the Plan

The Board or, if authorized by the Board, the Administrative Committee may designate any Affiliate as an Employer under this Plan. The Affiliate shall become an Employer and a party to this Plan and the Trust Agreement upon acceptance of such designation effective as of the date specified by the Board or Administrative Committee.

14.2 Conditions of Participation

By accepting such designation or continuing as a party to the Plan and Trust, each Employer acknowledges that:

(a)It is bound by such terms and conditions relating to the Plan as the Company or the Administrative Committee may reasonably require;

(b)It must comply with all qualification requirements and employee benefit rules of the Code, ERISA and related regulations and hereby acknowledges the authority of the Company, the Administrative Committee, and the Investment Committee to review the Affiliate’s compliance procedures and to require changes in such procedures to protect the Plan’s qualification;

(c)It has authorized the Company, the Administrative Committee, and the Investment Committee to act on its behalf with respect to Employer matters pertaining to the Plan and the Trust Fund;

(d)It will cooperate fully with the Plan officials and their agents by providing such information and taking such other actions, as they deem appropriate for the efficient administration of the Plan and the Trust Fund; and

(e)Its status as an Employer under the Plan is expressly conditioned on its being and continuing to be an Affiliate of the Company.

14.3 Termination of Participation

(a)Withdrawal by Affiliate. Subject to the concurrence of the Board or Administrative Committee, any Affiliate may withdraw from the Plan and Trust, and end its status as an Employer hereunder, by communicating in writing to the Administrative Committee its desire to withdraw. The withdrawal shall be effective as of the date agreed to by the Board or Administrative Committee, as the case may be, and the Affiliate. Upon such withdrawal, the Plan shall not terminate.

(b)Termination by Company. The Company, acting through the Board or, if authorized by the Board, the Administrative Committee, reserves the right, in its sole discretion and at any time, to terminate the participation in this Plan of any Employer. Such termination shall be effective immediately, upon the notice of such termination from the Company to the Trustee and the Employer being terminated, whichever occurs first, or such later effective date agreed to by the Company. Upon such termination, this Plan shall not terminate.

14.4 Consequences of the Termination of an Employer

If an Employer ceases to participate in this Plan, for whatever reason, and the Plan is not terminated then, unless otherwise directed by the Board, the Administrative Committee shall elect, in its discretion, which of the following shall apply:

(a)The Administrative Committee may elect that the portion of the Plan attributable to the former Employer shall become a separate plan effective as of the date on which the Employer’s participation in this Plan terminates. The Administrative Committee shall inform the Trustee of the portion of the Trust Fund that is attributable to the participation of the terminated Employer. As soon thereafter as is administratively feasible, the Trustee shall set apart that portion of the Trust Fund as a separate trust fund that shall be part of the separate plan of the terminated Employer. Thereafter, the administration, control, and operation of the separate plan, with respect to the terminated Employer, shall be on a separate basis, in accordance with the terms of this Plan except that:

(1)The terminated Employer, not the Company or the Administrative Committee, shall be the sponsor and administrator of the separate plan and shall have all duties, responsibilities, and powers that the Company, Administrative Committee and Investment Committee have under this Plan; and

(2)The terminated Employer, not the Company, shall have the power to amend and terminate the separate plan, in accordance with the provisions of Plan section 13.1.

(b)Alternatively, the Administrative Committee may elect to maintain the Accounts of Participants employed by the terminated Employer as follows:

(1)Except as provided in paragraph (5), all Participants employed by the terminated Employer on the date on which the entity ceases participation in this Plan shall become Inactive Participants or Former Participants, as applicable.

(2)The Pre-Tax Deferral, Roth Contribution, Catch-Up Contribution and After-Tax Contribution elections of an Active Participant under Article 4 shall only apply to Earnings for the portion of the Plan Year ending on the Employer’s termination date.

(3)The terminated Employer shall transfer to the Trust Fund the Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions, Matching Contributions and After-Tax Contributions required under the Plan relating to Earnings through the effective date of the Employer’s termination of participation in this Plan.

(4)For purposes of being eligible to receive a distribution of his or her Account, an Inactive Participant described in paragraph (1) shall not be treated as having a Separation from Service unless and until the

Administrative Committee determines that the Participant is eligible to receive a distribution under the provisions of Code section 401(k)(2)(B)(i).

(5)If a Participant described in paragraph (1) becomes an Employee of another Employer immediately after the effective date of the prior Employer’s termination of participation in this Plan, then the Participant shall be treated under the Plan as having transferred employment from one Employer to another.

(6)Should the Administrative Committee elect to take alternative action under this Section 14.4(b), the name of the terminated Employer and the effective date of such action will be set forth on Appendix H.

(c)With the consent of the Employer that is no longer participating in the Plan, the Company or Administrative Committee may take such other actions with respect to the Accounts of Participants employed by that Employer as are permitted under the Code and ERISA.

Article 15. Top-Heavy Provisions

15.1 Application of Top-Heavy Provisions

The provisions of this Article shall be interpreted and administered in accordance with the requirements of Code section 416 and related Treasury Regulations. The provisions of this Article shall apply for the Plan Year if, as of the Determination Date for that Plan Year, the Top-Heavy Ratio exceeds 60 percent.

15.2 Definitions Applicable to this Article

In addition to the terms defined in Plan section 2.1 or elsewhere in this Plan, whenever used in this Article, the following terms shall have the respective meanings set forth below, unless expressly provided otherwise. When the defined meaning is intended, the term is capitalized.

(a)“Aggregation Group” means each Qualified Plan of the Company or any Affiliate in which a Key Employee is a participant and any other Qualified Plan which enables a Qualified Plan of the Company or any Affiliate covering a Key Employee to meet the requirements of Code sections 401(a)(4) or 410. On behalf of the Company, the Administrative Committee may elect to include within the Aggregation Group any other Qualified Plan, together with the Qualified Plans referenced in the preceding sentence, provided that such expanded Aggregation Group continues to satisfy the requirements of Code sections 401(a)(4) and 410(b) for the Plan Year.

(b)“Determination Date” means the last day of the preceding Plan Year.

(c)“Key Employee” means, effective for Plan Years beginning after 2001, any Employee or a former Employee (including any deceased Employee) who, at any time during the Plan Year, is one of the following:

(1)An officer of the Company or any Affiliate whose Section 415 Compensation exceeds $130,000, as adjusted under Code section 416(i)(1) for Plan Years commencing after 2002, provided however, that the number of Employees included as Key Employees under this paragraph shall not exceed the lesser of:

(A)50 Employees; or

(B)The greater of three Employees or 10 percent of all Employees of the Company and all Affiliates.

(2)A five-percent owner of the Company or any Affiliate.

(3)A one-percent owner of the Company or any Affiliate whose Section 415 Compensation exceeds $150,000.

Only Section 415 Compensation attributable to services performed during the Plan Year for the Company or an Affiliate shall be included.

Ownership shall be determined in accordance with Code section 318 (as modified by Code section 416(i)(1)(B)(iii)). A Beneficiary or Alternate Payee whose rights under the Plan derive from a Key Employee shall also be treated as a Key Employee.

(d)“Non-Key Employee” means any Employee who is not a Key Employee.

(e)“Top-Heavy Ratio” means the ratio determined under Plan section 15.3.

15.3 Determination of Top-Heavy Ratio

The Top-Heavy Ratio for a Plan Year shall be determined as follows:

(a)General Rule. The numerator of the Top-Heavy Ratio is the sum of the amounts described in subsection (b) under all Qualified Plans in the Aggregation Group for each Key Employee. The denominator of the Top-Heavy Ratio is the sum of the amounts described in subsection (b) under all Qualified Plans in the Aggregation Group for all Employees.

(b)Included Amounts. When determining the Top-Heavy Ratio, the following amounts shall be included:

(1)The Employee’s total Account balance as of the Determination Date under this Plan;

(2)The Employee’s total account balance as of the Determination Date under all other Qualified Plans that are defined contribution plans included in the Aggregation Group;

(3)The present value as of the Determination Date of the Employee’s accrued benefit under all Qualified Plans that are defined benefit plans included in the Aggregation Group.

(c)Special Rules. For purposes of computing the Top-Heavy Ratio and included amounts, the following rules shall apply:

(1)The present value of accrued benefits shall be determined using reasonable actuarial assumptions.

(2)In the case of a distribution made for a reason other than severance from employment, death, or Disability (e.g., in-service withdrawals), this provision shall be applied by substituting “five-year period” for “one-year period.”

(3)Any Rollover, Roth Rollover or After-Tax Rollover Contribution (or similar transfer) initiated by the Employee and made after December 31, 1983, to a Qualified Plan in the Aggregation Group shall be excluded when determining account balances with respect to the transferee plan.

(4)Account balances and accrued benefits shall be taken into account only to the extent attributable to contributions by the Company or Affiliate and

contributions by the Employee while employed by the Company or an Affiliate.

(5)The present values of accrued benefits and account balances of any individual who has not performed services for the Company or any Affiliate during the one-year period ending on the Determination Date shall not be taken into account when determining the Top-Heavy Ratio.

(6)Account balances or accrued benefits of an Employee shall not be taken into account if the Employee is not a Key Employee for the Plan Year being tested but was a Key Employee in a prior Plan Year.

(7)To the extent required by Code section 416(e), contributions and benefits relating to Social Security or similar programs under federal or state law shall not be taken into account in determining the Top-Heavy Ratio.

15.4 Required Minimum Allocations

If the provisions of this Article apply for the Plan Year because the Top-Heavy Ratio exceeds 60 percent, then with respect to the defined contribution minimum allocation required by Code section 416(c)(2) and related Treasury Regulations, the contributions shall be made under the Retirement Plan on behalf of each Non-Key Employee who is a Participant who has not incurred a Separation from Service as of the last day of the Plan Year (regardless of whether the Non-Key Employee has less than 1,000 hours of service (or the equivalent) and regardless of the Non-Key Employee’s level of Section 415 Compensation), in an allocation for that Plan Year of not less than the lesser of:

(a)Three percent of the Participant’s Section 415 Compensation, or

(b)The percentage equal to the largest contribution, expressed as a percentage of Section 415 Compensation, received by any Key Employee under all defined contribution plans in the Aggregation Group.

For purposes of satisfying the requirements of this section, Pre-Tax Deferrals and Roth Contributions shall not be included, for any Employee who is a Non-Key Employee, but shall be included for any Participant who is a Key Employee. Effective for Plan Years beginning after 2001, the allocation of Matching Contributions shall be included for all Employees. If any Qualified Plan in the Aggregation Group is a defined benefit plan, then any Participant who participates both in a defined benefit plan and would otherwise be entitled to a minimum contribution under this section shall receive the defined benefit minimum prescribed under Code section 416(c)(1) and related Treasury Regulations under the defined benefit plan and shall not receive the minimum allocation under this section.

15.5 Required Minimum Vesting

If the provisions of this Article apply for the Plan Year because the Top-Heavy Ratio exceeds 60 percent, then each Participant who has not incurred a Separation from Service as of the last day of the Plan Year shall continue to vest in his or her Matching

Account and any defined contribution minimum allocation, as described in Plan section 15.4, for the Plan Year in accordance with the provisions of Plan section 3.5, which provides for vesting that is in all cases equal to or more rapid than required by Code section 416(b).

15.6 Employees Covered by Collective Bargaining Agreement

Notwithstanding any provision of this Article to the contrary, the provisions of Plan sections 15.4 and 15.5 shall not apply with respect to any Represented Employee covered by a collective bargaining agreement where retirement benefits were the subject of good faith bargaining between the Employer and the union.

Article 16. Miscellaneous Provisions

16.1 No Enlargement of Employment Rights

This Plan is strictly a voluntary undertaking on the part of the Company and the Employers and shall not be deemed to constitute a contract between the Employers and any Employee or Participant, Beneficiary, or Alternate Payee, or to be consideration for, or an inducement to, or a condition of, the employment of any Employee. Nothing contained in this Plan or any modification of the same or act done in pursuance hereof shall be construed as giving any person any legal or equitable right against the Employer, the Trustee, or the Trust Fund, unless specifically provided herein, or as giving any person a right to be retained in the employ of the Employer. All Participants shall remain subject to assignment, reassignment, promotion, transfer, layoff, reduction, suspension, and discharge to the same extent as if this Plan had never been established. No Participant, Beneficiary, or Alternate Payee, before satisfying all conditions for receiving benefits, shall have any right or interest in or to any portion of the Trust Fund. No one shall have any right to benefits, except to the extent provided in this Plan.

16.2 No Examination or Accounting

Neither this Plan nor any action taken thereunder shall be construed as giving any person the right to an accounting or to examine the books or affairs of the Company or any Affiliate.

16.3 Investment Risk

The Participants and their Beneficiaries shall assume all risks in connection with any decrease in the value of any assets or funds which may be invested or reinvested in the Trust Fund which supports this Plan.

16.4 Non-Alienation

(a)Except as otherwise permitted by the Plan, no benefit payable at any time under the Plan shall be subject to the debts or liabilities of a Participant or his or her Beneficiary. Any attempt to alienate, sell, transfer, assign, pledge, or otherwise encumber any such benefit, whether presently or thereafter payable, shall be void. Except as provided in this section, no benefit under the Plan shall be subject in any manner to attachment, garnishment, or encumbrance of any kind.

(b)Payment may be made from a Participant’s Account to an Alternate Payee, pursuant to a Qualified Domestic Relations Order.

(1)The Administrative Committee shall establish reasonable written procedures for reviewing court orders made, pursuant to state domestic relations law (including a community property law), relating to child support, alimony payments, or marital property rights of a Spouse, former Spouse, child, or other dependent of a Participant and for notifying Participants and Alternate Payees of the receipt of such orders and of the Plan’s procedures for determining if the orders are Qualified

Domestic Relations Orders and for administering distributions under Qualified Domestic Relations Orders.

(2)Except as may otherwise be required by applicable law, such Qualified Domestic Relations Orders may not require a retroactive transfer of all or part of a Participant’s Account to or for the benefit of an Alternate Payee without permitting an appropriate adjustment for earnings and investment gains or losses that have occurred in the interim, nor shall such orders require the Plan to provide rights to Alternate Payees that are not available to Beneficiaries generally.

(3)In cases in which a full and prompt payment of amounts assigned to an Alternate Payee will not be made, pursuant to this subsection, the assigned amounts will be transferred, within a reasonable time after determination that the order is a Qualified Domestic Relations Order, to a separate Account for the benefit of the Alternate Payee and invested in accordance with the Alternate Payee’s investment elections pursuant to Article 9.

(4)No amount that is segregated pending a determination of whether a domestic relations order is a Qualified Domestic Relations Order or transferred to a separate Account for the benefit of the Alternative Payee shall be taken into account when determining the amount that:

(A)A Participant may withdraw from his or her Account, pursuant to Plan section 7.2;

(B)A Participant may receive in a Plan loan, pursuant to Plan section 8.2; or

(C)A Participant (or his or her Beneficiary) may receive in a distribution, pursuant to Plan section 7.3 or 7.5.

(c)Payment may be made from an Account, to the extent required by a federal tax levy made pursuant to Code section 6331 or by the United States’ collection of a judgment resulting from an unpaid federal tax assessment. Payment may be made at the time required by the tax levy or judgment collection order, even if payment would not otherwise be made at that time under the terms of the Plan and payment from the Plan would not otherwise be permitted at that time under Code section 401(a), 401(k), or 411(a)(11).

(d)Payments from an Account may be offset to the extent permitted under Code section 401(a)(13)(C) (relating to offsets regarding breaches of duty with respect to the Plan).

(e)A Participant or Beneficiary may disclaim his or her Account, or a portion thereof, subject to the rules which may be modified from time to time by the Administrative Committee.

16.5 Incompetency

Every person receiving or claiming benefits under the Plan shall be conclusively presumed to be mentally competent and of age until the date on which the Administrative Committee (or its delegee) receives a written notice, in a form and manner acceptable to the Administrative Committee (or its delegee), that such person is incompetent or a minor, for whom a guardian or other person legally vested with the care of his or her person or estate has been appointed; provided, however, that if the Administrative Committee (or its delegee) shall find that any person to whom a benefit is payable under the Plan is unable to care for his or her affairs because of incompetency, or is a minor, any payment due (unless a prior claim therefore shall have been made by a duly appointed legal representative) may be paid to the Spouse, a child, a parent, a brother or sister, or to any person or institution deemed by the Administrative Committee (or its delegee) to have incurred expenses for such person otherwise entitled to payment. To the extent permitted by law, any such payment so made shall be a complete discharge of liability therefore under the Plan. In the event that a guardian of the estate of any person receiving or claiming benefits under the Plan shall be appointed by a court of competent jurisdiction or a person shall otherwise qualify as a guardian within the sole discretion of the Administrative Committee (or its delegee) and such guardian provides proper proof of appointment, qualification, or continuing qualification, as applicable, in a form and manner acceptable to the Administrative Committee (or its delegee), then, to the extent permitted by law:

(a)Such guardian may act for the Participant, Beneficiary, or Alternate Payee and make any election required of or permitted by the Participant, Beneficiary, or Alternate Payee under this Plan, and such action or election shall be deemed to have been taken by the Participant,

Beneficiary, or Alternate Payee; and

(b)Benefit payments may be made to such guardian, and any such payment so made shall be a complete discharge of any liability therefore under the Plan.

16.6 Records Conclusive

The records of the Company, Employers, the Administrative Committee, the Investment Committee and the Trustee shall be conclusive in respect to all matters involved in the administration of the Plan.

16.7 Counterparts

This Plan may be executed in any number of counterparts, each of which shall be deemed to be an original. All the counterparts shall constitute but one and the same instrument and may be sufficiently evidenced by any one counterpart.

16.8 Service of Legal Process

The Trustee, the members of the Administrative Committee, and the Secretary of the Company are hereby designated agents of the Plan for the purpose of receiving service of summons, subpoena, or other legal process.

16.9 Uncashed or Unclaimed Benefits

(a)Stale Checks. Effective on or after August 8, 2016 and through December 31, 2020, if a distribution check is issued under the Plan and such distribution check is not cashed within 6 months after issuance, the check will be characterized as stale, and the funds redeposited into a special account under the Plan. Such funds shall be characterized on an after-tax basis and effective December 1, 2016, or as soon as practicable thereafter but in no event later than December 31, 2016, such amounts will be invested in the Plan’s Stable Value Fund or such other fund as determined within the discretion of the Investment Committee. The check will be reissued upon request by the Participant pursuant to procedures established by the Administrative Committee. On and after January 1, 2021, distribution checks uncashed within 6 months after issuance shall be administered in accordance with procedures established by the Administrative Committee.

(b)Lost Participants. In the event that the Administrative Committee or its delegee, after having made a diligent search, is unable to locate a Participant, Beneficiary, or Alternate Payee who is entitled to benefits under this Plan, such benefits shall be treated as a forfeiture under Plan section 3.6. In the event that the Participant, Beneficiary, or Alternate Payee whose Account is subject to such forfeiture subsequently asserts a valid claim for benefits, the Account will be restored in the manner described in Plan section 3.6.

16.10 Qualified Military Service

Notwithstanding any provision of this Plan to the contrary, contributions, benefits and Service credit required with respect to qualified military service, within the meaning of Code section 414(u), will be provided in accordance with the mandatory provisions of Code section 414(u). In addition, in compliance with the Heroes Earnings Assistance and Relief Tax Act (“HEART), the following provisions shall apply notwithstanding any Plan provision to the contrary:

(a)Effective January 1, 2007, if the Participant dies while on qualified military service, the Participant’s Beneficiary shall be entitled to any benefit under the Plan (other than additional allocations related to the period of qualified military service) to the same extent that the Participant would have been entitled to such benefit had the Participant resumed employment and then incurred a Separation from Service on account of death.

(b)Effective January 1, 2009, Differential Wages shall be treated as Base Pay, as provided in Plan section 2.1(r)(2)(H), and Section 415 Compensation, as provided in

Plan section 2.1(sss)(2)(D), paid to an Active Participant by the Employer making the payment. For this purpose, Differential Wages means any payment made by an Employer with respect to any period during which the Employee is performing qualified military service and represents all or a portion of the wages the Employee would have received from the Employer if the Employee were performing service for the Employer.

(c)Effective January 1, 2009 and even if the Employee is receiving Differential Wages, a Participant performing qualified military service will be treated as having incurred a Separation from Service during the period of such qualified military service for purposes of Plan section 7.3, but only with respect to the Participant’s Pre-Tax Account and Roth Account. If the Participant elects to receive a distribution under this deemed Separation from Service, then such Participant shall not be permitted to make Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions or After-Tax Contributions during the six-month period beginning on the date of the distribution. Effective for withdrawals requested after August 8, 2016, if a Participant is suspended from making any Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions and/or After Tax Contributions in accordance with the sentence above, such contributions will be automatically reinstated upon expiration of the six-month suspension period at the Default Percentage, as applicable, or if the Participant was not subject to automatic enrollment or had opted out of automatic enrollment at the percentage in place prior to the suspension.

*    *    *

IN WITNESS WHEREOF, the Plan Amendment Officer hereby executes this amended and restated Plan this 22nd day of January, 2026.

Occidental Petroleum Corporation

/s/ Mark Grommesh

Mark Grommesh,

Vice President, Joint Ventures Occidental Petroleum Corporation

114

Document

Exhibit 21

OCCIDENTAL PETROLEUM CORPORATION

SUBSIDIARIES MORE THAN 50% OWNED OR OTHERWISE CONTROLLED

AS OF DECEMBER 31, 2025

COMPANY NAME	JURISDICTION
1PointFive Asia Pte. Ltd.	Singapore
1PointFive International G.K.	Japan
1PointFive International, LLC	Delaware
1PointFive Magnolia Holdco, LLC	Delaware
1PointFive Magnolia Opco, LLC	Delaware
1PointFive Marketing, LLC	Delaware
1PointFive P1 Sequestration, LLC	Delaware
1PointFive P2, LLC	Delaware
1PointFive Pelican Holdco, LLC	Delaware
1PointFive Pelican Opco, LLC	Delaware
1PointFive Sequestration, LLC	Delaware
1PointFive Stratos Holdings, LLC	Delaware
1PointFive Stratos II, LLC	Delaware
1PointFive Stratos Investment, LLC	Delaware
1PointFive Stratos Marketing, LLC	Delaware
1PointFive Stratos RWTU, LLC	Delaware
1PointFive Stratos, LLC	Delaware
1PointFive USA, LLC	Delaware
1PointFive, LLC	Delaware
4374607 Nova Scotia Company*	Nova Scotia
Amarok Gathering, LLC	Delaware
Anadarko 20-25 Company	Cayman Islands
Anadarko 20-36 Company	Cayman Islands
Anadarko Algeria Block 406B Company	Cayman Islands
Anadarko Brazil Investment I LLC	Delaware
Anadarko Brazil Investment II LLC	Delaware
Anadarko Canada E&P Limited	British Columbia
Anadarko Caribbean Limited	Cayman Islands
COMPANY NAME	JURISDICTION
---	---
Anadarko China Holdings 2 Company	Cayman Islands
Anadarko Colombia Company	Cayman Islands
Anadarko Consolidated Holdings LLC	Delaware
Anadarko Cote d'Ivoire Block 103 Company	Cayman Islands
Anadarko Cote d'Ivoire Company	Cayman Islands
Anadarko DBMOS Operator, LLC	Texas
Anadarko Development Company	Cayman Islands
Anadarko E&P Onshore LLC	Delaware
Anadarko Egypt Holdings Company	Delaware
Anadarko Energy Services Company	Delaware
Anadarko Exploracao e Producao de Petroleo e Gas Natural Ltda.	Brazil
Anadarko Finance Company	Nova Scotia
Anadarko Gabon Company	Cayman Islands
Anadarko Ghana Mahogany-1 Company	Cayman Islands
Anadarko Global Energy S.a.r.l	Luxembourg
Anadarko Global Funding 1 Company	Cayman Islands
Anadarko Global Funding II Ltd.	Bahamas
Anadarko Guyana Company	Cayman Islands
Anadarko Holding Company	Utah
Anadarko International Development S.a.r.l	Luxembourg
Anadarko International Energy Company	Delaware
Anadarko International Trading Corporation	Delaware
Anadarko Jordan Company	Delaware
Anadarko Land Corp.	Nebraska
Anadarko Midkiff/Chaney Dell BR Corp.	Delaware
Anadarko Midkiff/Chaney Dell LLC	Delaware
Anadarko Natural Gas Company LLC	Delaware
Anadarko Offshore Holding Company, LLC	Delaware
Anadarko Offshore Well Containment Company LLC	Delaware
Anadarko OGC Company	Delaware

Page 2

COMPANY NAME	JURISDICTION
Anadarko Oil & Gas 5, LLC	Delaware
Anadarko Peru Limited	Cayman
Anadarko Petroleum Corporation	Delaware
Anadarko Realty, LLC	Texas
Anadarko Rockies LLC	Delaware
Anadarko Royalty Holdings Company	Delaware
Anadarko US Offshore LLC	Delaware
Anadarko US Offshore Receivables, LLC	Delaware
Anadarko USH1 Corporation	Delaware
Anadarko Venezuela Company	Cayman Islands
Anadarko Venezuela LLC	Delaware
Anadarko Venezuela, Srl	Venezuela
Anadarko West Texas BR Corp.	Delaware
Anadarko West Texas LLC	Delaware
APC Aviation, Inc.	Delaware
APC International Holdings LLC	Delaware
APC Midstream Holdings, LLC	Delaware
APC Venezuela, Srl	Venezuela
Aventine LLC	New Mexico
Baseball Merger Sub 2, Inc.	Delaware
Bear Branch Exploration, LLC	Delaware
BHER TL Tech, LLC	Delaware
Big Island Trona Company	Delaware
Bitter Creek Coal Company	Utah
Bluebonnet Sequestration Hub, LLC	Delaware
Bravo Pipeline Company	Delaware
Canvasback Properties, LLC	Texas
Carbon Engineering ULC	British Columbia
Carbon Finance Labs, LLC	Delaware
CE Land Holdings Ltd.	British Columbia

Page 3

COMPANY NAME	JURISDICTION
Concord Petroleum Corporation	Panama
Conn Creek Shale Company	Delaware
Coral Holdings GP, LLC	Delaware
Coral Holdings LP, LLC	Delaware
CR Royalties Management, LLC	Delaware
CR Royalties, L.P.	Delaware
D.S. Ventures, LLC	Texas
Deerwood Exploration, LLC	Delaware
DMM Financial LLC*	Delaware
Downtown Plaza II	Oklahoma
East Louisiana Sequestration Hub, LLC	Delaware
Environmental Resource Holdings, LLC	Texas
FLAG Development, LLC	Delaware
Fosters Mill Exploration, LLC	Delaware
FP Westport LLC	Delaware
FP Westport Services LLC	Delaware
FP Westport Trading LLC	Delaware
Glenn Springs Holdings, Inc.	Delaware
Grand Bassa Tankers, Inc.	Delaware
Granite Springs Properties, LLC	Delaware
Grupo OxyChem de Mexico, S.A. de C.V.*	Mexico
Hereford Carbon Solutions, LLC	Delaware
Holocene Climate Corporation	Delaware
Houndstooth Resources, LLC	Texas
INDSPEC Chemical Corporation	Delaware
INDSPEC Holding Corporation	Delaware
Ingleside Cogeneration GP, LLC*	Delaware
Ingleside Cogeneration Limited Partnership*	Delaware
Interore Trading Ltd.	Liberia
Joslyn Partnership	Alberta

Page 4

COMPANY NAME	JURISDICTION
Kerr-McGee Corporation	Delaware
Kerr-McGee Natural Gas, Inc.	Delaware
Kerr-McGee of Canada Northwest Ltd.	Alberta
Kerr-McGee Oil & Gas Onshore LP	Delaware
Kerr-McGee Shared Services Company LLC	Delaware
Kerr-McGee Stored Power Corporation	Nevada
Kerr-McGee U.K. Energy Corporation	Delaware
Kerr-McGee Worldwide Corporation	Delaware
Kleberg Sequestration Hub, LLC	Delaware
KM BM-C-Seven Ltd.	Cayman Islands
Laguna Petroleum EOR, LLC	Delaware
Laguna Petroleum, LLC	Texas
Land HoldCo 1 LLC	Delaware
Land HoldCo LLC	Delaware
Liwa Oil & Gas Ltd.	Bermuda
Lumini, LLC	Delaware
Magnolia Sequestration Hub, LLC	Delaware
Mariana Properties, Inc.	Delaware
Marico Exploration, Inc.	New Mexico
MC2 Technologies LLC	Delaware
Miller Springs Remediation Management, Inc.	Delaware
New OPL, LLC	Delaware
NGL Ventures LLC	Delaware
Oakwood Exploration, LLC	Delaware
Occidental (Bermuda) Ltd.	Bermuda
Occidental (East Shabwa), LLC	Nevis
Occidental Advance Sale Finance, Inc.	California
Occidental Al Hosn Holding Limited	Bermuda
Occidental Al Hosn, LLC	Delaware
Occidental Angola Holdings Ltd.	Bermuda

Page 5

COMPANY NAME	JURISDICTION
Occidental Canada Holdings ULC*	Nova Scotia
Occidental Chemical Asia, Limited*	Japan
Occidental Chemical Belgium BV*	Belgium
Occidental Chemical Chile Limitada*	Chile
Occidental Chemical Corporation*	Texas
Occidental Chemical de Mexico, S.A. de C.V.*	Mexico
Occidental Chemical Export Sales, LLC*	Delaware
Occidental Chemical Far East Limited*	Hong Kong
Occidental Chemical Holding, LLC	Texas
Occidental Chemical International, LLC*	California
Occidental Chemical Receivables, LLC	Delaware
Occidental Chemicals Canada Holdings, LLC*	Delaware
Occidental Chile Investments, LLC*	Delaware
Occidental Chile Minority Holder, LLC*	Delaware
Occidental CIS Services, Inc.	Delaware
Occidental Colombia (Series G) Ltd.	Bermuda
Occidental Colombia (Series J) Ltd.	Bermuda
Occidental Colombia (Series K) Ltd.	Bermuda
Occidental Colombia (Series L) Ltd.	Bermuda
Occidental Colombia (Series M) Ltd.	Bermuda
Occidental Colombia (Series N) Ltd.	Bermuda
Occidental Colombia (Series O) Ltd.	Bermuda
Occidental Crude Sales, Inc. (Canada)	Delaware
Occidental Crude Sales, Inc. (International)	Delaware
Occidental Dolphin Holdings Ltd.	Bermuda
Occidental Economic Opportunity Zone Investments, LLC	Delaware
Occidental Energy Marketing, Inc.	Delaware
Occidental Energy Ventures LLC	Delaware
Occidental Exploradora del Peru Ltd.	Bermuda
Occidental Exploration and Production Company	California

Page 6

COMPANY NAME	JURISDICTION
Occidental Hafar, LLC	Delaware
Occidental International (Libya), Inc.	Delaware
Occidental International Corporation	Delaware
Occidental International Exploration and Production Company, LLC	California
Occidental International Holdings Ltd.	Bermuda
Occidental International Oil and Gas Ltd.	Bermuda
Occidental International Services, Inc.	Delaware
Occidental Joslyn GP 2 Co.	Nova Scotia
Occidental Joslyn Holdings, LLC	Delaware
Occidental LNG (Malaysia) Ltd.	Bermuda
Occidental MENA Manager Ltd.	Bermuda
Occidental Middle East Development Company	Delaware
Occidental Midland Basin, LLC	Delaware
Occidental Mukhaizna, LLC	Delaware
Occidental of Abu Dhabi (Bab) Ltd.	Bermuda
Occidental of Abu Dhabi (Shah) Ltd.	Bermuda
Occidental of Abu Dhabi Holdings Ltd.	Bermuda
Occidental of Abu Dhabi Ltd.	Bermuda
Occidental of Abu Dhabi, LLC	Delaware
Occidental of Algeria E&P Company	Cayman Islands
Occidental of Algeria LLC	Delaware
Occidental of Algeria Oil & Gas Company	Cayman Islands
Occidental of Bahrain Ltd.	Bermuda
Occidental of Bangladesh, Inc.	Delaware
Occidental of Colombia (Chipiron), Inc.	Nevis
Occidental of Colombia (Cosecha), Inc.	Nevis
Occidental of Colombia (Medina), Inc.	Nevis
Occidental of Colombia (Putumayo) Ltd.	Bermuda
Occidental of Colombia (Teca) Ltd.	Bermuda
Occidental of Dubai, Inc.	Nevis

Page 7

COMPANY NAME	JURISDICTION
Occidental of Iraq Holdings Ltd.	Bermuda
Occidental of Iraq, LLC	Delaware
Occidental of Oman, Inc.	Nevis
Occidental of Russia Ltd.	Bermuda
Occidental of South Africa (Offshore), Inc.	Nevis
Occidental of Yemen (Block 75), LLC	Delaware
Occidental Oil and Gas (Oman) Ltd.	Nevis
Occidental Oil and Gas Corporation	Texas
Occidental Oil and Gas International Inc.	Delaware
Occidental Oil and Gas International, LLC	Delaware
Occidental Oil and Gas of Peru, LLC	Delaware
Occidental Oil and Gas Pakistan LLC	Nevis
Occidental Oil Asia Pte. Ltd.	Singapore
Occidental Oil Shale, Inc.	California
Occidental Oman (Block 27) Holdings Ltd.	Bermuda
Occidental Oman Block 51 Holding Ltd.	Bermuda
Occidental Oman Block 51, LLC	Delaware
Occidental Oman Block 65 Holding Ltd.	Bermuda
Occidental Oman Block 65, LLC	Delaware
Occidental Oman Block 72 Holding Ltd.	Bermuda
Occidental Oman Block 72, LLC	Delaware
Occidental Oman Gas Company LLC	Delaware
Occidental Oman Gas Holdings Ltd.	Bermuda
Occidental Oman North Holdings, Ltd.	Bermuda
Occidental Oriente Exploration and Production Ltd.	Cayman Islands
Occidental Peninsula II, Inc.	Nevis
Occidental Peninsula, LLC	Delaware
Occidental Permian EOR, LLC	Delaware
Occidental Permian Ltd.	Texas
Occidental Permian Manager LLC	Delaware

Page 8

COMPANY NAME	JURISDICTION
Occidental Permian Services, Inc.	Delaware
Occidental Peruana, Inc.	California
Occidental Petrolera del Peru (Block 101), Inc.	Nevis
Occidental Petrolera del Peru (Block 103), Inc.	Nevis
Occidental Petroleum (Pakistan), Inc.	Delaware
Occidental Petroleum Corporation	Delaware
Occidental Petroleum Corporation Political Action Committee	California
Occidental Petroleum de Venezuela, S.A.	Venezuela
Occidental Petroleum of Oman Ltd.	Nevis
Occidental Petroleum of Qatar Ltd.	Bermuda
Occidental Power Marketing, L.P.	Delaware
Occidental Power Services, LLC*	Delaware
Occidental PVC, LLC*	Texas
Occidental Qatar Energy Company LLC	Delaware
Occidental Red Sea Development, LLC	Nevis
Occidental Research Corporation	California
Occidental Resource Recovery Systems, Inc.	California
Occidental Resources Company	Cayman Islands
Occidental Shah Gas Holdings Ltd.	Bermuda
Occidental South America Finance, LLC	Delaware
Occidental Specialty Marketing, Inc.	Delaware
Occidental Tower Corporation	Delaware
Occidental Transportation Holding Corporation	Delaware
Occidental West Texas Overthrust, Inc.	Texas
Occidental Yemen Ltd.	Bermuda
Occidental Yemen Sabatain, Inc.	Nevis
Oceanic Marine Transport Ltd.	Bermuda
OEVC Energy, LLC	Texas
OEVC Midstream Projects, LLC	Delaware
OIH, LLC*	Delaware

Page 9

COMPANY NAME	JURISDICTION
OLCV Canada Holdings, LLC	Delaware
OLCV Canada Investment Holdings, Inc.	Delaware
OLCV CE US Holdings, Inc.	Delaware
OLCV Cemvita Holdings, LLC	Delaware
OLCV CUT Holdings, LLC	Delaware
OLCV DAC Technology, LLC	Delaware
OLCV Development Holdings, LLC	Delaware
OLCV Development LLC	Delaware
OLCV Land Holdings, LLC	Delaware
OLCV Net Power, LLC	Texas
OLCV Newlight HoldCo, LLC	Delaware
OLCV P1 Development, LLC	Delaware
OLCV PL Holdings, LLC	Delaware
OLCV Services LLC	Delaware
OLCV Stratos Development, LLC	Delaware
OLCV Technology Ventures, LLC	Delaware
OOG Partner LLC	Delaware
OOOI Chem Sub, LLC*	Delaware
OOOI Chile Holder, LLC*	Delaware
OOOI Ecuador Management, LLC	Delaware
OOOI Oil and Gas Sub, LLC	Delaware
OOOI South America Management, LLC	Delaware
Opcal Insurance, Inc.	Hawaii
OPM GP, Inc.	Delaware
OPM Holdco, LLC	Delaware
Orca 1 LLC	Delaware
Orca 2 LLC	Delaware
Orca 3 LLC	Delaware
Oryx Crude Trading & Transportation, Inc.	Delaware
OTV IOTA Holdings, LLC	Delaware

Page 10

COMPANY NAME	JURISDICTION
OTV RayGen Holdings, LLC	Delaware
Oxy BMEC Holdings, LLC	Delaware
Oxy BridgeTex Limited Partnership	Texas
Oxy C & I Bulk Sales, LLC	Delaware
OXY CA, LLC	Delaware
OXY Campus, LLC	Delaware
Oxy Canada Sales, Inc.*	Delaware
Oxy Carbon Solutions, LLC	Texas
Oxy Carbon Storage, LLC	Delaware
Oxy Climate Ventures, Inc.	Delaware
Oxy Cogeneration Holding Company, LLC	Delaware
Oxy Colombia Holdings, LLC	Delaware
Oxy Colombia TopCo Ltd.	Bermuda
OXY CV Pipeline LLC	Delaware
Oxy Delaware Basin Plant, LLC	Delaware
Oxy Delaware Basin, LLC	Texas
Oxy Dolphin E&P, LLC	Nevis
Oxy Dolphin Pipeline, LLC	Nevis
Oxy Energy Canada, Inc.	Delaware
Oxy Energy Services, LLC	Delaware
Oxy EOR Carbon Management, LLC	Delaware
Oxy Expatriate Services, Inc.	Delaware
Oxy FFT Holdings, Inc.	Delaware
Oxy Fund Holdings, LLC	Delaware
Oxy Holding Company (Pipeline), Inc.	Delaware
OXY Inc.	California
Oxy International Ventures Ltd.	Bermuda
Oxy Levelland Pipeline Company, LLC	Delaware
Oxy Levelland Terminal Company, LLC	Delaware
OXY Libya E&P Area 35 Ltd.	Bermuda

Page 11

COMPANY NAME	JURISDICTION
OXY Libya E&P Concession 103 Ltd.	Bermuda
OXY Libya E&P EPSA 1981 Ltd.	Bermuda
OXY Libya E&P EPSA 1985 Ltd.	Bermuda
OXY Libya Exploration, SPC	Cayman Islands
OXY Libya, LLC	Delaware
OXY Little Knife, LLC	Delaware
Oxy Low Carbon Ventures Canada, ULC	British Columbia
Oxy Low Carbon Ventures, LLC	Delaware
OXY LPG LLC	Delaware
Oxy LPG Terminal, LLC	Delaware
OXY Mexico Holdings I, LLC	Delaware
OXY Mexico Holdings II, LLC	Delaware
OXY Middle East Holdings Ltd.	Bermuda
Oxy Midstream Strategic Development, LLC	Delaware
OXY of Saudi Arabia Ltd.	Cayman Islands
OXY Oil Partners, Inc.	Delaware
Oxy Oleoducto SOP, LLC	Delaware
Oxy Overseas Services Ltd.	Bermuda
OXY PBLP Manager, LLC	Delaware
Oxy Permian Plaza, LLC	Delaware
Oxy Petroleum de Mexico, S. de R.L. de C.V.	Mexico
Oxy Renewable Energy LLC	Texas
Oxy Salt Creek Pipeline LLC	Delaware
OXY Support Services, LLC	Delaware
Oxy Taft Hub, LLC	Texas
Oxy Technology Ventures, Inc.	Delaware
Oxy Technology Ventures, LLC	Delaware
Oxy TL, LLC	Delaware
Oxy Transport I Company, LLC	Delaware
OXY Tulsa Inc.	Delaware

Page 12

COMPANY NAME	JURISDICTION
OXY USA EOR, LLC	Delaware
OXY USA Inc.	Delaware
OXY USA WTP EOR, LLC	Delaware
OXY USA WTP LP	Delaware
Oxy Vinyls Canada Co.*	Nova Scotia
Oxy Vinyls Export Sales, LLC*	Delaware
Oxy Vinyls, LP*	Delaware
OXY VPP Investments, LLC	Delaware
OXY West, LLC	Texas
Oxy Westwood Corporation	California
Oxy Y-1 Company	New Mexico
Oxy Y-1 EOR, LLC	Delaware
OxyChem do Brasil Ltda.*	Brazil
OxyChem Ingleside Ethylene Holdings, Inc.*	Delaware
OxyChile Investments, LLC	Delaware
OXYMAR*	Texas
OxyRock Operating, LLC	Delaware
OxyRock, L.P.	Delaware
Permian Basin EOR, LLC	Delaware
Permian Basin JV Tax Matters Member LLC	Delaware
Permian Basin Limited Partnership	Delaware
Permian VPP Holder, LP	Delaware
Permian VPP Manager, LLC	Delaware
Placid Oil EOR, LLC	Delaware
Placid Oil, LLC	Delaware
Ramlat Oxy Ltd.	Bermuda
Rio de Viento, Inc.	Wyoming
Rodeo Midland Basin, LLC	Delaware
San Patricio Pipeline LLC	Delaware
Scanports Shipping, LLC	Delaware

Page 13

COMPANY NAME	JURISDICTION
Scissortail Finance, Inc.	Delaware
Sequoia Sequestration Hub, LLC	Delaware
Stetson Exploration, LLC	Delaware
Sun Offshore Gathering Company	Delaware
Swiflite Aircraft Corporation	New Jersey
Taft Carbon Capture, LLC	Delaware
TerraLithium LLC	Delaware
TL BHER Ex-IV, LLC	Delaware
TL BHER Holdings, LLC	Delaware
TL Drilling, LLC	Delaware
Transok Properties, LLC	Delaware
Troy Potter, Inc.	Texas
Tuscaloosa Holdings, Inc.	Delaware
TxMRock Holdings, LLC	Delaware
UP Petroleo III Ltd.	Bermuda
Upland Industries Corporation	Nebraska
Venezuela US SRL	Barbados
Vintage Gas, Inc.	Oklahoma
Vintage Petroleum Argentina Ltd.	Cayman Islands
Vintage Petroleum Boliviana, Ltd.	Bermuda
Vintage Petroleum International Ventures, Inc.	Cayman Islands
Vintage Petroleum International, LLC	Delaware
Vintage Petroleum Italy, Inc.	Oklahoma
Vintage Petroleum South America Holdings, Inc.	Cayman Islands
Vintage Petroleum South America, LLC	Oklahoma
Vintage Petroleum Turkey, Inc.	Cayman Islands
Wardner Ranch, Inc.	Delaware
Western Gas Resources, Inc.	Delaware
Western Gas Resources-Westana, Inc.	Delaware
Western Midstream Holdings, LLC	Delaware

Page 14

COMPANY NAME	JURISDICTION
WGR Asset Holding Company LLC	Delaware
WGR Canada, Inc.	New Brunswick
Woodlands International Insurance Ltd.	Bermuda
YT Ranch LLC	Colorado

* Entity sold effective January 2, 2026, as part of the OxyChem Transaction.

Page 15

Document

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statements (Nos. 333-83124, 333-142705, 333-203801, 333-207413, 333-224691, 333-237414 and 333-239236) on Form S-8 and the registration statements (Nos. 333-55404, 333-288999, 333-235445 and 333-281228) on Form S-3 of our reports dated February 18, 2026, with respect to the consolidated financial statements of Occidental Petroleum Corporation and subsidiaries and the effectiveness of internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 18, 2026

Document

EXHIBIT 23.2

TBPELS REGISTERED ENGINEERING FIRM F-1580

1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the (i) inclusion in the Occidental Petroleum Corporation (“Occidental”) Form 10-K for the year ended December 31, 2025 (“Form 10-K”), and the incorporation by reference in Occidental's registration statements (No. 333-55404, 333-83124, 333-142705, 333-203801, 333-207413, 333-224691, 333-288999, 333-235445, 333-237414, 333-239236 and 333-281228) (the “Registration Statements”), of references to our name and to our letter dated January 26, 2026, relating to our review of the methods and procedures used by Occidental for estimating its oil and gas proved reserves (our “Letter”), (ii) filing of our Letter with the Securities and Exchange Commission as Exhibit 99.1 to the Form 10-K and (iii) incorporation by reference of our Letter in the Registration Statements.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

Houston, Texas

February 18, 2026

SUITE 2800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799

633 17TH STREET, SUITE 1700    DENVER, COLORADO 80202    TEL (303) 339-8110

Document

EXHIBIT 31.1

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

PURSUANT TO §302 OF THE SARBANES-OXLEY ACT OF 2002

I, Vicki Hollub, certify that:

1.I have reviewed this annual report on Form 10-K of Occidental Petroleum Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 18, 2026

/s/ Vicki Hollub
Vicki Hollub
President and Chief Executive Officer

Document

EXHIBIT 31.2

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

PURSUANT TO §302 OF THE SARBANES-OXLEY ACT OF 2002

I, Sunil Mathew, certify that:

1.I have reviewed this annual report on Form 10-K of Occidental Petroleum Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 18, 2026

/s/ Sunil Mathew
Sunil Mathew
Senior Vice President and Chief Financial Officer

Document

EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO

18 U.S.C. § 1350,

AS ADOPTED PURSUANT TO

§ 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Occidental Petroleum Corporation (the “Company”) for the fiscal period ended December 31, 2025, as filed with the Securities and Exchange Commission on February 18, 2026 (the “Report”), Vicki Hollub, as Chief Executive Officer of the Company, and Sunil Mathew, as Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of her or his knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Vicki Hollub
Name:	Vicki Hollub
Title:	President and Chief Executive Officer
Date:	February 18, 2026
	/s/ Sunil Mathew
---	---
Name:	Sunil Mathew
Title:	Senior Vice President and Chief Financial Officer
Date:	February 18, 2026

A signed original of this written statement required by Section 906 has been provided to Occidental Petroleum Corporation and will be retained by Occidental Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

Document

Exhibit 99.1

OCCIDENTAL PETROLEUM CORPORATION

Process Review

of the

Estimated

Future Proved Reserves and Income

Attributable to Certain

Leaseholds and Interests

SEC Parameters

As of

December 31, 2025

/s/ Herman G. Acuña
Herman G. Acuña, P.E.
TBPELS License No. 92254
President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPELS REGISTERED ENGINEERING FIRM F-1580

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

January 26, 2026

Occidental Petroleum Corporation

5 Greenway Plaza, Suite 110

Houston, Texas 77046

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has conducted a process review of the methods and analytical procedures utilized by the engineering and geological staff of Occidental Petroleum Corporation (Occidental) for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications for the reviewed properties as of December 31, 2025, based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) Title 17, Code of Federal Regulations, “Modernization of Oil and Gas Reporting, Final Rule” released January 14, 2009 in the Federal Register (SEC regulations). The results of our third party reserves process review, completed on January 26, 2026 and presented herein, were prepared for public disclosure by Occidental in filings made with the SEC in accordance with the disclosure requirements set forth under Section 229.1202(a)(8) of the SEC regulations.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the proved reserves classification for the reviewed properties are appropriate for the purpose thereof, and comply with the SEC regulations as of December 31, 2025. Ryder Scott has not been engaged to render an opinion as to the reasonableness of the proved reserves quantities reported by Occidental.

Properties Reviewed

The proved reserves reviewed herein are attributable to the leasehold and royalty interests of Occidental in certain properties located in the United States offshore Gulf of America and onshore in the states of Texas, New Mexico and Colorado.

SUITE 2800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799

555 17TH STREET, SUITE 985    DENVER, COLORADO 80202    TEL (303) 339-8110

Occidental Petroleum Corporation

January 26, 2026

Page 2

The properties reviewed herein were selected by Occidental. Ryder Scott and Occidental concur that these properties are a valid representation of Occidental’s total net proved reserves portfolio as of December 31, 2025. Based on the estimates prepared by Occidental, the portion of total company net liquid and net gas reserves reviewed by us are expressed as a percentage and presented in summary form on the following page. At Occidental’s request and as provided by Occidental, we have also presented the portion of the total company net proved reserves reviewed by us as a percentage on a barrel of oil equivalent (BOE) basis.

Percentage of Total Company Estimated Net Reserves

Reviewed by Ryder Scott

SEC Parameters

Occidental Petroleum Corporation

As of December 31, 2025
	Oil/Condensate	NGL	Total Liquid Hydrocarbons	Gas	Equivalent<br><br>BOE
---	---	---	---	---	---
Total Proved Developed	31.4%	45.8%	36.4%	43.8%	38.5%
Total Proved Undeveloped	42.1%	38.1%	40.7%	36.9%	39.7%
Total Company Proved	34.5%	43.6%	37.6%	42.0%	38.9%

The net liquid hydrocarbons reviewed are comprised of oil, condensate and natural gas liquids (NGL) and are based on standard 42 gallon barrels. All net gas volumes reviewed are based on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. Reserves reviewed and noted herein on a BOE basis are based on converting natural gas on the basis of relative energy content using a factor of 6,000 cubic feet of natural gas per one BOE. It should be noted that barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a BOE basis is, and has been substantially lower than the corresponding price for crude oil currently and for a number of years.

Reserves Process Review Discussion

A process review, according to Paragraph 2.2(i) contained in the Society of Petroleum Engineers (SPE) “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” (SPE auditing standards), is “the result of an investigation by a person who is qualified by experience and training equivalent to that of a QRA [Qualified Reserves Auditor] to address the adequacy and effectiveness of an entity’s internal processes and controls relative to Reserves estimation.”

In order to arrive at our conclusions and to substantiate our opinion relative to Occidental’s internal reserves estimation process and controls, we conducted our investigation in a manner that closely conforms to the SPE auditing standards for a reserves audit. Under Paragraph 2.2(g) of the SPE auditing standards, a reserves audit includes “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of Reserves and/or Reserves information prepared by others and the rendering of an opinion about the appropriateness of the methodologies used, the adequacy and quality of the data relied upon, the depth and thoroughness of

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Occidental Petroleum Corporation

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the Reserves estimation process, the categorization of Reserves appropriate to the relevant definitions used, and the reasonableness of the estimated Reserves quantities and/or the Reserves information.”

Our process review, however, differs from an SPE reserves audit in that we have not conducted our investigation with sufficient rigor to express an opinion as to “the reasonableness of the estimated Reserves quantities and/or the Reserves information” as required under Paragraph 2.2(g) of the SPE auditing standards for a reserves audit. Our review should not be construed to be a complete and comprehensive appraisal of the subject properties or deemed to convey the same level of information contained in a third party reserves audit or reserves evaluation report.

Applicable Petroleum Reserves Definitions

The determination of the proved reserves classifications as discussed herein are based on the definitions as set forth in the SEC’s Regulations Part 210.4-10(a) released January 14, 2009 in the Federal Register, Volume 74, pages 2158 through 2197.

Reserves and Uncertainty

The SEC defines reserves as the “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of this data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty as to their recoverability.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty that the estimates of the quantities actually recovered are “much more likely to be achieved than not.” The SEC defines probable reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines possible reserves as “those additional reserves that are less certain to be recovered than probable reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

The reserves for the properties reviewed by us were estimated by Occidental using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach,

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Occidental Petroleum Corporation

January 26, 2026

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discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. At Occidental’s request, this reserves process review addresses only the proved reserves attributable to the properties reviewed herein.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves quantities and their associated reserves categories may be revised due to other factors such as the results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.

Reserves Process Review Procedure

Certain technical personnel responsible for the preparation of Occidental’s proved reserves estimates presented the data, methods and procedures used in 1) estimating the reserves volumes as of December 31, 2025; 2) documenting the changes in reserves from prior estimates; 3) preparing the economic evaluations associated with the estimated December 31, 2025 reserves; and 4) determining the reserves classifications for each of the subject properties reviewed. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review. Furthermore, if in the course of our examination something came to our attention which brought into question the appropriateness of the methodologies employed, the adequacy of the data relied upon or the documentation of the reserves estimation process, additional clarification was requested from Occidental until we had satisfactorily resolved our questions relating thereto.

Methodology and Procedure Employed by Occidental for Estimating Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the SEC’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

We describe next the methodology employed by Occidental to estimate proved reserves in the properties reviewed.

Approximately 86 percent of the proved developed producing reserves were estimated by performance-based methods including decline curve analysis, dimensionless scaling analysis of performance and reservoir modeling, which utilized extrapolations of historical production and pressure data in those cases where such data were considered to be definitive. Approximately 13 percent of the

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

January 26, 2026

Page 5

proved developed producing reserves were estimated by type well profiles supported by analogs to 1) estimate those reserves where there were inadequate historical performance data to establish a definitive producing trend and 2) estimate the incremental reserves attributable to enhanced/improved oil recovery. The remaining 1 percent of the proved developed producing reserves were estimated by other methods.

Approximately 66 percent of the proved developed non-producing reserves were estimated by performance-based methods including decline curve analysis, dimensionless scaling analysis of performance and reservoir modeling. Approximately 30 percent of the proved developed non-producing reserves were estimated by type well profiles supported by analogs. The remaining 4 percent of the proved developed non-producing reserves were estimated by volumetric analysis or other methods.

Approximately 81 percent of the proved undeveloped reserves were estimated by type well profiles supported by analogs. Approximately 9 percent of the proved undeveloped reserves were estimated by performance-based methods including decline curve analysis, dimensionless scaling analysis of performance and reservoir modeling. The remaining 10 percent of the proved undeveloped reserves were estimated by other methods, including volumetric analysis.

Occidental uses the latest available production, new well and seismic data in its reserves estimation process. Typically, the production and new well data is from the third quarter of the year for which reserves are estimated, though material data is considered whenever it becomes available prior to finalization of reserves estimates. The data used by Occidental in their analysis of the proved reserves for the properties reviewed by us was considered sufficient for the purpose thereof.

Primary Economic Assumptions Employed by Occidental for Estimating Reserves

To estimate economically recoverable proved reserves and related future net cash flows, Occidental considered many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC Regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Occidental relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices in effect on December 31, 2025 for the properties reviewed were determined by Occidental using the unweighted 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold and adjustments for differentials as described herein. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.

The table below summarizes Occidental’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Occidental’s “average realized

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January 26, 2026

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prices.” The average realized prices shown in the table below were determined from Occidental’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Occidental’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for the North America geographic area reviewed by us.

Geographic Area	Product	Price<br><br>Reference	Average<br><br>Benchmark<br><br>Prices	Average Realized<br><br>Prices
North America
	Oil/Condensate	WTI Cushing	$65.34/bbl	$64.00/bbl
United States	NGLs	Mt. Belvieu	$31.79/bbl	$18.02/bbl
	Gas	Henry Hub	$3.39/MMbtu	$1.58/Mcf

As indicated above, the product prices that were used by Occidental to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and distance from market, referred to herein as “differentials.” The differentials used by Occidental were accepted as factual data. We have not conducted an independent verification of the differentials used by Occidental.

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration by Occidental in this process and omitted by us in conducting this review.

Accumulated gas production imbalances, if any, were not taken into account in the proved reserves estimates of gas reviewed. The proved gas volumes estimated by Occidental attribute gas consumed in operations as reserves for those fields where the inclusion of such volumes was appropriate.

Operating costs used by Occidental are based on the operating expense reports of Occidental and include only those costs directly applicable to the leases, contract areas and wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases, contract areas and wells. The operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs used by Occidental were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating costs used by Occidental.

Development costs used by Occidental are based on authorizations for expenditure (AFE) for the proposed work or actual costs for similar projects. The development costs used by Occidental were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the development costs used by Occidental.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us were incorporated by Occidental in accordance with Occidental’s plans to develop these reserves as of December 31, 2025. The implementation of Occidental’s development plans as presented to us is

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Occidental Petroleum Corporation

January 26, 2026

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subject to the approval process adopted by Occidental’s management. As a result of our inquiries during the course of our review, Occidental has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Occidental’s management at the appropriate local, regional and corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to partner AFE processes, Joint Operating Agreement requirements or other administrative approvals external to Occidental. Additionally, Occidental has informed us that they are not aware of any existing laws or regulations that would require the company to significantly alter their current development plans. While these plans could change from those under existing economic conditions as of December 31, 2025, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Future Production Rate Assumptions Employed by Occidental for Estimating Reserves

Occidental’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Occidental to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date determined by Occidental. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Occidental’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing or recompleting wells and constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated by Occidental because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity or other operating conditions, market demand and allowables or other constraints set by regulatory bodies.

Possible Effects of Regulation on Occidental’s Estimate of Reserves

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Occidental operates or has interests. Occidental’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the quantities estimated by Occidental as reviewed herein.

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Occidental Petroleum Corporation

January 26, 2026

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We have not made any field examination of the properties. No consideration was given in this review to potential environmental liabilities that may exist nor to any costs for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Occidental has informed us that they are not aware of any existing laws or regulations that would materially impact their ability to recover the estimated proved reserves for the properties reviewed by us.

Data Reviewed in Conducting the Third Party Reserves Process Review

Occidental has informed us that they have furnished or otherwise made available to us all of the material accounts, records, geological and engineering data, and reports and other data required for this review. In conducting our process review of Occidental’s estimates of proved reserves and forecasts of future production and income, we have reviewed data used by Occidental with respect to property interests owned or otherwise held, production and well tests from examined wells, normal direct costs of operating the wells, leases and contract areas, other costs such as transportation and processing fees, ad valorem and production taxes, recompletion and development costs, development plans, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data utilized by Occidental. We consider the factual data utilized by Occidental to be appropriate and sufficient for the purpose of our review of the methods and analytical procedures utilized by the engineering and geological staff of Occidental for estimating the proved reserves volumes and preparing the economic evaluations.

Reserves Process Review Opinion

We found no bias in the utilization and analysis of data in proved reserves estimates for these properties. Furthermore, we found the estimation process incorporated all pertinent data, utilized a thorough and detailed analytical approach and was supported by a well documented audit trail.

We consider the assumptions, data, methods and analytical procedures used by Occidental and as reviewed by us appropriate for the purpose thereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties comply with the SEC regulations as of December 31, 2025. Ryder Scott has not been engaged to render an opinion as to the reasonableness of the proved reserves quantities reported by Occidental.

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Occidental Petroleum Corporation

January 26, 2026

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Standards of Independence and Professional Qualification

Ryder Scott is an employee-owned independent petroleum engineering consulting firm. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. No single client or job represents a material portion of our annual revenue. These factors allow us to maintain our independence and objectivity in the performance of our services.

Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Occidental. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on the results of our review.

The results of the reserves process review, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party reserves process review, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and are intended for public disclosure as an exhibit in filings made with the SEC by Occidental.

Occidental makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Occidental has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Occidental of the references to our name as well as to the references to our third party report for Occidental, which will appear in the December 31, 2025 annual report on Form 10-K of Occidental, the inclusion in that Form 10-K of such references and the filing of such report as an exhibit to such Form 10-K. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Occidental.

We have provided Occidental with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Occidental and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

January 26, 2026

Page 10

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

/s/ Herman G. Acuña

Herman G. Acuña, P.E.

TBPELS License No. 92254

President

[SEAL]

HGA/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Herman G. Acuña was the primary technical person responsible for overseeing the estimation of the reserves, future production and income to render the audit conclusions of the report.

Mr. Acuña, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1997, currently serves as President and Board Member. Among his responsibilities, he coordinates and supervises staff and consulting engineers of the company in ongoing evaluation studies worldwide. Before joining Ryder Scott, Mr. Acuña served in a number of engineering positions with Exxon. For more information regarding Mr. Acuña’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com.

Mr. Acuña earned a Bachelor (Cum Laude) and a Masters (Magna Cum Laude) of Science degree in Petroleum Engineering from The University of Tulsa in 1987 and 1989 respectively. He is a registered Professional Engineer in the State of Texas and a member of the Association of International Petroleum Negotiators (AIPN) and the Society of Petroleum Engineers (SPE).

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Acuña fulfills. Mr. Acuña has attended formalized training and conferences including dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register and the 2018 SPE-PRMS definitions. Mr. Acuña routinely teaches various company reserves evaluation workshops and schools around the world and the U.S.A. Mr. Acuña has participated in various capacities in reserves conferences in the United States and globally. Mr. Acuña currently serves as chair of the SPE’s Oil and Gas Reserves Committee (OGRC).

Based on his educational background, professional training and over 35 years of practical experience in petroleum engineering and the estimation and evaluation of petroleum reserves, Mr. Acuña has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations took effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible

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PETROLEUM RESERVES DEFINITIONS

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displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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PETROLEUM RESERVES DEFINITIONS

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(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

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Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)completion intervals that are open at the time of the estimate but which have not yet started producing;

(2)wells which were shut-in for market conditions or pipeline connections; or

(3)wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS