OCCIDENTAL PETROLEUM CORP /DE/

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 oftwo 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, CO 2 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 Note 3 -Inve stments 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 Note 3 - Investment and Related-Party Transactions for further information.

NONCONTROLLING INTEREST

The Company and BlackRock formed a joint venture for the continued development of the first commercial scale direct air capture facility. The joint venture is a VIE and the Company consolidates the VIE as it is the primary beneficiary. BlackRock’s investment is accounted for as an NCI. Each party has committed to make additional investments towards the completion of the direct air capture facility. As of December 31, 2025, BlackRock has invested $500 million of its total commitment of $550 million. In addition, the Company has entered into agreements with the joint venture related to project management, operations and maintenance and carbon removal offtake. The Company may incur additional payments to the joint venture if certain construction and operational thresholds are not met.

The Company may call the NCI on June 30, 2035 or earlier if the plant does not achieve commercial operations or ceases and permanently discontinues operations. Dividends from the joint venture will be distributed preferentially to the NCI up to a return threshold, then preferentially to the Company thereafter. The NCI receives preferential distributions in liquidation.

Because distributions from the joint venture will not be consistent over time, or with the initial investments or ownership interest, the Company has determined that the appropriate methodology for attributing income and loss from the joint venture is the hypothetical liquidation at book value method. Under this method, the amounts of income and loss attributed

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.

In October 2025, the Company announced entry into a purchase and sale agreement with Berkshire Hathaway (the Purchase Agreement) to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion, subject to customary purchase price adjustments. The OxyChem Transaction closed on January 2, 2026.

An Occidental subsidiary will retain environmental liabilities relating to legacy sites. Additionally, under the Purchase Agreement, there are post-closing indemnification obligations for (i) legacy environmental liabilities and (ii) pre-closing liabilities of OxyChem, including pre-closing environmental liabilities, in each case, subject to certain limitations and procedures.

Certain Occidental subsidiaries entered into other definitive agreements with OxyChem following the close of the transaction, including, among others, (i) a Transition Services Agreement, pursuant to which the Company will provide certain transition services for a period of time, and (ii) a Remediation Management Agreement, pursuant to which an Occidental subsidiary will manage certain remedial projects. Occidental also entered into a guaranty in favor of Berkshire Hathaway, pursuant to which Occidental guarantees the indemnification obligations of its subsidiaries under the Purchase Agreement.

As a result of our agreement to sell OxyChem, the following changes in our basis of presentation have occurred:

■In accordance with ASC 205, Discontinued Operations, intersegment sales from our oil and gas and midstream and marketing segments to the chemical segment are no longer eliminated as intercompany transactions. All periods presented have been retrospectively adjusted to reflect this change.

■Beginning October 1, 2025, in accordance with ASC 360, Property, Plant, and Equipment (PP&E), depreciation and amortization were no longer recorded for the chemical segment’s PP&E and right of use lease assets.

Unless otherwise indicated, information presented in the Notes to Consolidated Financial Statements relates only to the Company’s continuing operations. Additional information related to discontinued operations is included in Note 4 - Acquisitions, Divestitures and Other Transactions and in some instances, where appropriate, is included as a separate disclosure within the individual Notes to Consolidated Financial Statements.

RISKS AND UNCERTAINTIES

The process of preparing Consolidated Financial Statements in conformity with GAAP requires the Company’s management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of the Company’s financial statements. The Company establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets is dependent upon the Company generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.

The accompanying Consolidated Financial Statements include assets of approximately $7.8 billion as of December 31, 2025 and net sales of approximately $4.2 billion in 2025 relating to the Company’s operations in countries outside North America. The Company is exposed to various risks, because certain of its international operations are located in countries which could be affected by political or civil instability, OPEC production restrictions, equipment import restrictions and sanctions. Exposure to such risks may increase if a greater percentage of the Company’s future oil and gas production or revenue comes from international sources. The Company attempts to conduct its affairs so as to mitigate its exposure to such risks and would seek compensation in the event of nationalization.

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.

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:

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:

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.

The Company performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to significant and prolonged declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include estimates of future production, product prices, contractual prices, estimates of risk-adjusted oil and gas proved and unproved reserves and estimates of future operating and development costs. It is reasonably possible that prolonged declines in commodity prices, reduced capital spending in response to lower prices, or increases in operating costs could result in additional impairments. See Note 8 - Fair Value Measurements and below for further discussion of asset impairments.

Net capitalized costs attributable to unproved properties were $7.7 billion and $10.2 billion as of December 31, 2025 and 2024, respectively. The unproved amounts are not subject to DD&A until they are classified as proved properties. Individually insignificant unproved properties are combined and amortized on a group basis based on factors such as geographic location, lease terms, success rates and other factors to provide for full amortization upon lease expiration or abandonment.

Significant unproved properties are assessed individually for impairment and, when events or circumstances indicate that the carrying value of property may not be recovered, a valuation allowance is provided if an impairment is indicated. The Company periodically reviews significant unproved properties for impairments. When assessing for impairments, several factors are considered, including, but not limited to, availability of funds for future exploration and development activities, current exploration and development plans, favorable or unfavorable exploration activity on the property or the adjacent property, geologists’ evaluation of the property, the current and projected political and regulatory climate, contractual conditions and the remaining lease term for the properties. If an impairment is indicated, the Company will first determine whether a comparable transaction for similar properties or implied acreage valuation derived from market participants is available and will adjust the carrying amount of the unproved property to its fair value using the market approach. In situations where the market approach is not observable and unproved reserves are available, undiscounted future net cash flows used in the impairment analysis are determined based on management’s risk-adjusted estimates of unproved reserves, future commodity prices and future costs to produce the reserves. If undiscounted future net cash flows are less than the carrying value of the unproved property, the future net cash flows are discounted and compared to the carrying value for determining the amount of the impairment loss to record. The Company utilizes the same methodology discussed above for cash flows associated with proved properties.

MIDSTREAM AND MARKETING

The Company’s midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, which range from 3 years to 40 years, using the straight-line method.

The Company performs impairment tests on its midstream and marketing assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

IMPAIRMENTS AND OTHER CHARGES

In 2024, the Company recorded a pre-tax impairment of $334 million related to certain wells in the Gulf of America whose future net cash inflows did not indicate that the asset value is recoverable.

In 2023, the Company recorded a pre-tax impairment of $180 million related to undeveloped acreage in the northern non-core area of the Powder River Basin where the Company has decided not to pursue future exploration and appraisal activities. In 2023, impairment expense also included $29 million related to an equity method investment in Black Butte Coal Company.

INTANGIBLES AND GOODWILL

As of December 31, 2025, the Company had $954 million of other intangible assets primarily related to OLCV included in the midstream and marketing segment other long-term assets. These assets are amortized between 9 and 25 years on a straight-line basis. The Company performs impairment tests on its finite-lived intangible assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

As of December 31, 2025, the Company had $668 million of goodwill related to its ownership in Carbon Engineering included in the midstream and marketing segment other long-term assets. Goodwill is subject to annual impairment testing

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.

ACCRUED LIABILITIES - CURRENT

Accrued liabilities-current consisted of the following line items as of December 31, 2025 and 2024:

ACCRUED LIABILITIES - NON-CURRENT

Accrued liabilities non-current consisted of the following line items as of December 31, 2025 and 2024:

(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

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:

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 Note 7 - 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.

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:

(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:

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

differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). See Note 9 - Income Taxes 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:

(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 fromone month toone 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.

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.

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:

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.

NOTE 3 - INVESTMENTS AND RELATED-PARTY TRANSACTIONS

INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

(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:

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:

RELATED-PARTY TRANSACTIONS

The Company sells oil, NGL, natural gas and power to and purchases oil and NGL from its equity method investees and other related parties. The Company is charged service fees primarily related to gathering, processing and treatment of oil, NGL and natural gas by certain of its equity investees and other related parties. Berkshire Hathaway is a related party of the Company due to its ownership of Occidental’s common stock. The Company has, from time to time, contracted with Berkshire Hathaway for the provision of electricity and insurance. On January 2, 2026, the Company completed the sale of OxyChem to Berkshire Hathaway. As a result, OxyChem’s results of operations, cash flows and the related retained liabilities and indemnification obligations are reported as discontinued operations in the Company’s Consolidated Statements of Operations and Cash Flows for all periods presented, with its assets and liabilities reclassified as held for sale in the Company’s Consolidated Balance Sheets. For more information, refer to Note 4 - Acquisition, Divestitures and Other Transactions. The Company entered into the following related-party transactions and had the following amounts due from or to its related parties for the years ended December 31:

(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

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.

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.

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:

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.

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.

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:

During the third quarter of 2024, the Company sold non-core assets in the Powder River Basin with near- to intermediate-term lease expirations and certain Delaware Basin assets in Texas and New Mexico for combined net proceeds of $769 million, subject to customary purchase price adjustments. The Company recognized a pre-tax loss of $479 million on the asset sales. In addition, the Company sold 19.5 million of its limited partner units in WES for proceeds of $697 million resulting in a pre-tax gain of $489 million; see Note 3 - Investments and Related-Party Transactions.

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 inthree approximately equal annual payments, with the first payment made at closing. This transaction closed on November 3, 2023, and the Company made the first payment of $349 million. The second payment of $318 million was made in the fourth quarter of 2024, and the last payment was made in the fourth quarter of 2025.

Throughout 2023, the Company entered into non-monetary exchange agreements, primarily in the Permian Basin. These exchanges were recorded as acquisitions and divestitures at a total combined fair value of $120 million. The difference in the assets’ net book value was treated as a recovery of cost and normal retirement, which resulted in no gain or loss being recognized.

In September 2023, the Company sold 5.1 million limited partner units of WES for proceeds of approximately $128 million, resulting in a gain of $51 million; see Note 3 - Investments and Related-Party Transactions.

In September 2023, the Company sold certain non-core proved and unproved properties in the Permian Basin for $202 million and recorded a gain on sale of assets of $142 million.

OxyChem

In October 2025, the Company announced a purchase and sale agreement with Berkshire Hathaway to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion. The sale was completed on January 2, 2026, resulting in an estimated gain of $3.2 billion, net of taxes and subject to post-closing adjustments. The OxyChem Transaction is subject to customary adjustments for cash, indebtedness, and changes in working capital relative to a predetermined target. For information related to the presentation of financials for discontinued operations, see Note 1 - Summary of Significant Accounting Policies.

The OxyChem Transaction marks a strategic change in the Company’s operations. Refer to Note 5 Long-Term 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.

The following table presents the amounts reported in discontinued operations, net of income taxes, for the years ended December 31:

The following table presents a reconciliation of major classes of assets and liabilities classified as held for sale as of December 31:

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:

(a) Of these amounts, $116 million, $117 million and $102 million in 2025, 2024 and 2023, respectively, were classified as current.

NOTE 5 - LONG-TERM DEBT

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

DEBT ACTIVITY AND DEBT MATURITIES

The following table summarizes the Company’s debt activity in 2025:

Subsequent to December 31, 2025, but before the date of this filing, the Company used proceeds from the OxyChem Transaction to pay or satisfy and discharge the remaining balance of the term loan of $1.3 billion, additional current maturities of $270 million, and long-term maturities of $3.8 billion. As of the date of this filing, the principal debt outstanding was approximately $15 billion, of which $24 million is due in 2026, $48 million in 2027, $14 million in 2028, $367 million in 2029 and $14.6 billion due in 2030 and thereafter.

The Company terminated its receivables securitization facility on September 26, 2025.

FAIR VALUE OF DEBT

The Company estimates the fair value of fixed-rate debt based on the quoted market prices for those instruments or on quoted market yields for similarly rated debt instruments, taking into account such instruments’ maturities. The estimated fair values of the Company’s debt as of December 31, 2025 and 2024, the majority of which were classified as Level 1, were approximately $20.8 billion and $24.0 billion, respectively. The Company’s exposure to changes in interest rates relates primarily to its variable-rate, long-term debt obligations. As of December 31, 2025 and 2024, variable-rate debt constituted approximately 6.5% and 11%, respectively, of the Company’s total debt.

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 hadno drawn amounts under the RCF. In 2025, the Company paid average annual facility fees of 0.20% on the total commitment amount.

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:

(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:

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:

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.

(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:

(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.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash, cash equivalents, restricted cash, restricted cash equivalents and other financial instruments, other than fixed-rate debt, approximate fair value. See Note 5 - Long-Term Debt for the fair value of long-term debt.

NOTE 9 - INCOME TAXES

RECENT TAX LEGISLATION

The OBBBA was enacted on July 4, 2025 and introduced provisions expected to benefit the Company including accelerated depreciation for newly acquired and constructed assets, favorable adjustments to interest expense limitation, immediate deduction of research and development costs, and increased tax credit values for qualified CO 2 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:

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

The following summarizes income taxes paid (net of refunds received) on continuing operations for the years ended December 31:

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:

(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.

The following summarized the tax effects of temporary differences resulting in deferred income taxes as of December 31:

(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.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

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 wereno 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.

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:

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:

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:

COMPONENTS OF NET PERIODIC BENEFIT COSTS

The following table sets forth the components of net periodic benefit costs for the years ended December 31:

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:

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,

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:

(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:

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

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.

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 tofour 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.

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 asone 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 overten totwenty 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.

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.

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 - Enviro nmental Liabilities and Expendi tures. 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.

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, CO 2, 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.

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:

(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.

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:

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 wereno 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:

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

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 ifthree 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 fromone tothree 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:

TOTAL SHAREHOLDER RETURN INCENTIVE AWARDS

Certain executives are awarded TSRIs that vest at the end of athree-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.

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:

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

(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 wereno 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:

There wereno 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 athree-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.

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:

(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.

NOTE 15 - INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

The Company conducts its operations throughtwo 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 Note 4 - Acquisitions, Divestitures and Other Transactions for related disclosure.

The Company’s President and CEO is ultimately responsible for allocating resources and assessing the performance of each operating segment and is the Company’s CODM. The CEO may be assisted in this function by other members of the Company’s executive management including, but not limited to, the Chief Financial Officer and Chief Operating Officer. While other executives are responsible for the performance of their individual areas, the CEO is solely responsible for allocating resources across the Company as a whole.

For both reporting segments, the CODM utilizes segment income (loss) from continuing operations before income taxes to measure performance, as well as allocate resources (including financial or capital resources) for each segment, predominantly in the annual budget and forecasting process.

The following table reconciles segment income from continuing operations before taxes to net income attributable to common shares:

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.

Other segment expenses include asset impairments and other charges, selling, general and administrative expense and exploration expense:

Other segment expenses include asset impairments and other charges, transportation expense, taxes other than on income, and selling, general and administrative expense:

SEGMENT INVESTMENTS AND EXPENDITURES

The following table includes segment-level balance sheet information:

GEOGRAPHIC AREAS

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