Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


INDEX TO CONSOLIDATED FINANCIAL STATEMENTS			PAGE
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements			55
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting			57
Consolidated Balance Sheets			58
Consolidated Statements of Operations			60
Consolidated Statements of Comprehensive Income			61
Consolidated Statements of Equity			62
Consolidated Statements of Cash Flows			63
Notes to Consolidated Financial Statements			65
Note 1 - Summary of Significant Accounting Policies			65
Note 2 - Revenue			73
Note 3 - Investments and Related-Party Transactions			76
Note 4 - Acquisitions, Divestitures and Other Transactions			77
Note 5 - Long-term Debt			82
Note 6 - Lease Commitments			85
Note 7 - Derivatives			86
Note 8 - Fair Value Measurements			87
Note 9 - Income Taxes			88
Note 1 0 - Retirement and Postretirement Benefit Plans			93
Note 1 1 - Environmental Liabilities and Expenditures			97
Note 1 2 - Lawsuits, Claims, Commitments and Contingencies			99
Note 1 3 - Stockholders’ Equity			101
Note 1 4 - Stock-Based Incentive Plans			103
Note 1 5 - Industry Segments and Geographic Areas			106
Supplemental Quarterly Financial Data (Unaudited)			109
Supplemental Oil and Gas Information (Unaudited)			110


54			OXY 2025 FORM 10-K


			table of contents			FINANCIAL STATEMENTS REPORT

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Occidental Petroleum Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 18, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Assessment of the estimated proved oil and gas reserves on the determination of depletion expense related to proved oil and gas properties.

As discussed in Note 1 to the consolidated financial statements, the Company determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. Under this method, capitalized costs are amortized over estimated proved reserves. For the year ended December 31, 2025, the Company recorded depreciation and depletion expense related to proved oil and gas properties of $7.1 billion.

We identified the assessment of the estimated proved oil and gas reserves on the determination of depreciation and depletion expense related to proved oil and gas properties as a critical audit matter. Complex auditor judgment was required to assess the Company’s estimate of proved oil and gas reserves, which is a key input for the determination of depreciation and depletion expense. Estimating proved oil and gas reserves requires the expertise of professional petroleum reservoir engineers. The key assumptions included estimated future production quantities and estimated operating and capital costs.


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			table of contents			FINANCIAL STATEMENTS REPORT

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depreciation and depletion process, including the estimation of proved oil and gas reserves. We analyzed and assessed the determination of depreciation and depletion expense for compliance with industry and regulatory standards. We assessed compliance of the methodology used by the Company’s engineering and technical staff to estimate proved oil and gas reserves with industry and regulatory standards. We read the findings of the independent reservoir engineering specialist’s review of the methods and procedures used by the Company in estimating the proved reserves for compliance with industry and regulatory standards. To assess the Company’s ability to accurately estimate future production quantities, we compared the future production quantity assumptions used by the Company in prior periods to the actual production amounts. We compared the estimated future production quantities used by the Company in the current period to historical production rates. We evaluated the operating and capital cost assumptions used by the Company by comparing them to historical costs incurred. We evaluated the professional qualifications and the knowledge, skills, and ability of the Company’s internal reserve engineers and the independent reservoir engineering specialists engaged by the Company.

/s/ KPMG LLP

We have served as the Company’s auditor since 2002.

Houston, Texas

February 18, 2026


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			table of contents			FINANCIAL STATEMENTS REPORT

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Occidental Petroleum Corporation:

Opinion on Internal Control Over Financial Reporting

We have audited Occidental Petroleum Corporation and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 18, 2026 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Assessment of and Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Houston, Texas

February 18, 2026


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			table of contents			FINANCIAL STATEMENTS


Consolidated Balance Sheets			Occidental Petroleum Corporation and Subsidiaries


	December 31,
millions	2025		2024
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,968	$	2,125
Trade receivables	2,575		2,839
Joint interest receivables	684		720
Inventories	1,823		1,756
Assets held for sale	1,176		1,140
Other current assets	601		490
Total current assets	8,827		9,070

PROPERTY, PLANT AND EQUIPMENT
Oil and gas	126,896		121,874
Midstream and marketing	9,638		8,593
Corporate	1,219		1,163
	137,753		131,630
Accumulated depreciation, depletion and amortization	(74,110)		(65,767)
Total property, plant and equipment, net	63,643		65,863

NON-CURRENT ASSETS
Operating lease assets	908		755
Investments in unconsolidated entities	2,475		2,646
Non-current assets held for sale	5,344		4,430
Other long-term assets	2,989		2,681
Total non-current assets	11,716		10,512


TOTAL ASSETS	$	84,186	$	85,445

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


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			table of contents			FINANCIAL STATEMENTS


Consolidated Balance Sheets			Occidental Petroleum Corporation and Subsidiaries


	December 31,
millions except share and per-share amounts	2025		2024
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt	$	1,773	$	1,138
Accounts payable	3,285		3,472
Accrued liabilities	3,592		4,248
Liabilities held for sale	778		663
Total current liabilities	9,428		9,521

LONG-TERM DEBT, NET	20,623		24,979

DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes, net	5,636		5,394
Asset retirement obligations	4,172		3,923
Non-current liabilities held for sale	418		333
Other deferred credits and liabilities	7,311		6,815
Total deferred credits and other liabilities	17,537		16,465

EQUITY
Preferred stock, at $1.00 per share par value, issued shares: 2025 — 84,897 and 2024 — 84,897	8,287		8,287
Common stock, $0.20 per share par value, authorized shares: 1.5 billion, issued shares: 2025 — 1,214,337,600 and 2024 — 1,166,769,167	243		233
Treasury stock: 2025 — 228,311,184 shares and 2024 — 228,311,184 shares	(15,597)		(15,597)
Additional paid-in capital	21,008		19,868
Retained earnings	21,891		21,189
Accumulated other comprehensive income	202		179
Total stockholders’ equity	36,034		34,159
Noncontrolling interest	564		321
Total equity	36,598		34,480

TOTAL LIABILITIES AND EQUITY	$	84,186	$	85,445

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


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			table of contents			FINANCIAL STATEMENTS


Consolidated Statements of Operations			Occidental Petroleum Corporation and Subsidiaries


	Years Ended December 31,
millions except per-share amounts	2025		2024		2023
REVENUES AND OTHER INCOME
Net sales	$	21,593	$	22,019	$	23,156
Interest, dividends and other income	219		192		153
Gains (losses) on sales of assets and other, net	263		(16)		522
Total	22,075		22,195		23,831

COSTS AND OTHER DEDUCTIONS
Oil and gas lease operating expense	4,681		4,738		4,677
Transportation and gathering expense	1,660		1,608		1,481
Purchased commodities and midstream cost of sales	176		431		2,116
Selling, general and administrative expense	986		960		987
Other operating and non-operating expense	1,556		1,319		1,165
Taxes other than on income	1,030		1,039		1,087
Depreciation, depletion and amortization	7,533		6,951		6,449
Asset impairments and other charges	60		356		209
Acquisition-related costs	13		84		26
Exploration expense	249		275		441
Interest and debt expense, net	1,079		1,169		957
Total	19,023		18,930		19,595
Income before income taxes and other items	3,052		3,265		4,236
OTHER ITEMS

Income from equity investments and other	76		759		426
Total	76		759		426
Income from continuing operations before income taxes	3,128		4,024		4,662
Income tax expense	(1,021)		(1,158)		(1,330)
Income from continuing operations	2,107		2,866		3,332
Income from discontinued operations, net of tax	262		212		1,364

NET INCOME	2,369		3,078		4,696
Less: Net income attributable to noncontrolling interest	(43)		(22)		—
Less: Preferred stock dividends and redemption premiums	(679)		(679)		(923)
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	1,647	$	2,377	$	3,773

PER COMMON SHARE
Income from continuing operations—basic	$	1.38	$	2.36	$	2.69
Discontinued operations—basic	0.27		0.23		1.53
Net income attributable to common stockholders—basic	$	1.65	$	2.59	$	4.22

Income from continuing operations—diluted	$	1.35	$	2.23	$	2.49
Discontinued operations—diluted	0.26		0.21		1.41
Net income attributable to common stockholders—diluted	$	1.61	$	2.44	$	3.90

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


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			table of contents			FINANCIAL STATEMENTS


Consolidated Statements of Comprehensive Income			Occidental Petroleum Corporation and Subsidiaries


	Years Ended December 31,
millions	2025		2024		2023
Net income	$	2,369	$	3,078	$	4,696
Other comprehensive income (loss) items:

Gains (losses) on derivatives	(15)		(5)		44
Pension and postretirement gains (losses)	38		(89)		34
Other	—		(2)		2
Other comprehensive income (loss), net of tax	23		(96)		80
Comprehensive income	2,392		2,982		4,776
Less: Comprehensive income attributable to noncontrolling interest	(43)		(22)		—
Comprehensive income attributable to preferred and common stockholders	$	2,349	$	2,960	$	4,776

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


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			table of contents			FINANCIAL STATEMENTS


Consolidated Statements of Equity			Occidental Petroleum Corporation and Subsidiaries


			Equity Attributable to Common Stock
	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total Equity

Balance, December 31, 2022	$	9,762	$	220	$	(13,772)	$	17,181	$	16,499	$	195	$	—	$	30,085
Net income	—		—		—		—		4,696		—		—		4,696
Other comprehensive income, net of tax	—		—		—		—		—		80		—		80
Dividends on common stock, $0.72 per share	—		—		—		—		(646)		—		—		(646)
Dividends on preferred stock, $8,000 per share	—		—		—		—		(736)		—		—		(736)
Preferred stock redemption – face value	(1,511)		—		—		—		—		—		—		(1,511)
Preferred stock redemption – premium	—		—		—		—		(151)		—		—		(151)
Preferred stock redemption – amortization of carrying value	36		—		—		—		(36)		—		—		—
Shareholder warrants exercised	—		1		—		98		—		—		—		99
Options exercised	—		—		—		13		—		—		—		13
Issuance of common stock and other, net	—		1		—		130		—		—		—		131
Purchases of treasury stock	—		—		(1,810)		—		—		—		—		(1,810)
Noncontrolling interest contributions, net	—		—		—		—		—		—		99		99
Balance, December 31, 2023	$	8,287	$	222	$	(15,582)	$	17,422	$	19,626	$	275	$	99	$	30,349
Net income	—		—		—		—		3,056		—		22		3,078
Other comprehensive income, net of tax	—		—		—		—		—		(96)		—		(96)
Dividends on common stock, $0.88 per share	—		—		—		—		(814)		—		—		(814)
Dividends on preferred stock, $8,000 per share	—		—		—		—		(679)		—		—		(679)



Shareholder warrants exercised	—		5		—		554		—		—		—		559
Issuance of common stock and other, net	—		—		—		143		—		—		—		143
Purchases of treasury stock	—		—		(15)		—		—		—		—		(15)
Common stock issued for CrownRock acquisition	—		6		—		1,749		—		—		—		1,755
Noncontrolling interest contributions, net	—		—		—		—		—		—		200		200
Balance, December 31, 2024	$	8,287	$	233	$	(15,597)	$	19,868	$	21,189	$	179	$	321	$	34,480
Net income	—		—		—		—		2,326		—		43		2,369
Other comprehensive loss, net of tax	—		—		—		—		—		23		—		23
Dividends on common stock, $0.96 per share	—		—		—		—		(945)		—		—		(945)
Dividends on preferred stock, $8,000 per share	—		—		—		—		(679)		—		—		(679)
Shareholder warrants exercised	—		9		—		921		—		—		—		930
Issuance of common stock and other, net of cancellations	—		1		—		219		—		—		—		220


Noncontrolling interest contributions, net	—		—		—		—		—		—		200		200
Balance, December 31, 2025	$	8,287	$	243	$	(15,597)	$	21,008	$	21,891	$	202	$	564	$	36,598

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


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			table of contents			FINANCIAL STATEMENTS


Consolidated Statements of Cash Flows			Occidental Petroleum Corporation and Subsidiaries


	Years Ended December 31,
millions	2025		2024		2023
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	2,369	$	3,078	$	4,696
Adjustments to reconcile net income to net cash from operating activities:
Discontinued operations, net	(262)		(212)		(1,364)
Depreciation, depletion and amortization of assets	7,533		6,951		6,449
Deferred income tax provision (benefit)	127		(265)		54
Other noncash charges to income	420		454		133
Asset impairments	21		355		209
Losses (gains) on sales of assets and other, net	(263)		60		(522)
Undistributed losses (earnings) from equity investments	619		(83)		141
Dry hole expense	109		106		299
Changes in operating assets and liabilities:
(Increase) decrease in trade receivables	252		(116)		931
(Increase) decrease in inventories	12		(27)		(84)
(Increase) decrease in joint interest receivables and other current assets	(62)		286		(350)
Decrease in accounts payable and accrued liabilities	(964)		(540)		(423)
Increase (decrease) in current domestic and foreign income taxes	(305)		472		66
Operating cash flow from continuing operations	9,606		10,519		10,235
Operating cash flow from discontinued operations	926		920		2,073
Net cash provided by operating activities	10,532		11,439		12,308

CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures	(6,427)		(6,263)		(5,696)
Change in capital accrual	32		100		(22)
Purchases of assets, businesses and equity investments, net	(280)		(9,117)		(713)
Proceeds from sale of assets and equity investments, net	2,278		1,673		447
Equity investments and other, net	(286)		(214)		(479)
Investing cash flow from continuing operations	(4,683)		(13,821)		(6,463)
Investing cash flow from discontinued operations	(1,116)		(769)		(517)
Net cash used by investing activities	(5,799)		(14,590)		(6,980)
CASH FLOW FROM FINANCING ACTIVITIES
Draws on receivables securitization facility	—		—		283
Payment of receivables securitization facility	—		—		(283)
Proceeds from long-term debt, net	—		9,612		(46)
Payments of long-term debt, net	(3,754)		(4,514)		(22)

Redemption of preferred stock	—		—		(1,661)
Purchases of treasury stock	—		(27)		(1,798)
Cash dividends paid on common and preferred stock	(1,594)		(1,446)		(1,365)
Proceeds from issuance of common stock	966		584		135
Contributions from noncontrolling interest	200		200		100
Deferred payments for purchases of assets and businesses	(417)		(318)		—
Other financing, net	(236)		(242)		(229)
Financing cash flow from continuing operations	(4,835)		3,849		(4,886)
Financing cash flow from discontinued operations	(9)		(5)		(4)
Net cash provided (used) by financing activities	(4,844)		3,844		(4,890)

Increase (decrease) in cash, cash equivalents, restricted cash and restricted cash equivalents	(111)		693		438
Cash, cash equivalents, restricted cash and restricted cash equivalents — beginning of year	2,157		1,464		1,026
Cash, cash equivalents, restricted cash and restricted cash equivalents — end of year	$	2,046	$	2,157	$	1,464

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


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			table of contents			FINANCIAL STATEMENTS


Consolidated Statements of Cash Flows			Occidental Petroleum Corporation and Subsidiaries


	Years Ended December 31,
millions	2025		2024		2023
CASH, CASH EQUIVALENTS, RESTRICTED CASH AND RESTRICTED CASH EQUIVALENTS BALANCES FROM:
Continuing operations - beginning of year	$	2,150	$	1,451	$	1,006
Discontinued operations - beginning of year (a)	7		13		20
Less: discontinued operations - end of year (a)	41		7		13
Continuing operations - end of year	2,005		2,150		1,451

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

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


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES


Notes to Consolidated Financial Statements			Occidental Petroleum Corporation and Subsidiaries


NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

The Company conducts its operations through various subsidiaries and affiliates. The Company’s principal business consists of two reporting segments: oil and gas and midstream and marketing. The oil and gas segment explores for, develops and produces oil (which includes condensate), NGL and natural gas.

The midstream and marketing segment purchases, markets, gathers, processes, transports and stores oil (which includes condensate), NGL, natural gas, CO2 and power. It also optimizes its transportation and storage capacity, and invests in entities that conduct similar activities, such as WES. The midstream and marketing segment also includes OLCV. OLCV seeks to leverage the Company’s legacy of carbon management experience to develop CCUS projects, including the commercialization of DAC technology, and invests in other low-carbon technologies intended to reduce GHG emissions from the Company’s operations and strategically partner with other industries to help reduce their emissions.

PRINCIPLES OF CONSOLIDATION

The Consolidated Financial Statements have been prepared in conformity with GAAP and include the accounts of the Company, its subsidiaries, its undivided interests in oil and gas exploration and production ventures, and variable interest entities for which the Company was the primary beneficiary. The Company accounts for its share of oil and gas exploration and production ventures by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets, statements of operations and statements of cash flows.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

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 N ote 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 Not e 3 - Investment and Related-Party Transactions for further information.

NONCONTROLLING INTEREST

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

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

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


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to the NCI in the Consolidated Statements of Operations reflect changes in the amounts the NCI would hypothetically receive at each balance sheet date if the joint venture was liquidated. As of December 31, 2025, the VIE’s assets were comprised of $1.2 billion construction in progress. Noncontrolling interest as of December 31, 2025 was $564 million.

DISCONTINUED OPERATIONS

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

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

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

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

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

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

Unless otherwise indicated, information presented in the Notes to Consolidated Financial Statements relates only to the Company’s continuing operations. Additional information related to discontinued operations is included in 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.


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

INVENTORIES

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Oil, NGL and natural gas inventories are valued at the lower of cost or market.

Commodity inventory primarily represents oil, which is carried at the lower of weighted-average cost or net realizable value. Inventories consisted of the following as of December 31:


millions	2025		2024
Materials and supplies	$	1,222	$	1,219
Commodity inventory	601		537
Total	$	1,823	$	1,756

PROPERTY, PLANT AND EQUIPMENT

OIL AND GAS

The carrying value of the Company’s PP&E represents the cost incurred to acquire or develop the asset, including any AROs and capitalized interest, net of accumulated DD&A and any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. AROs and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.

The Company uses the successful efforts method to account for its oil and gas properties. Under this method, the Company capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:


millions	2025		2024		2023
Balance — beginning of year	$	262	$	405	$	276
Additions to capitalized exploratory well costs pending the determination of proved reserves	409		556		750
Reclassifications to property, plant and equipment based on the determination of proved reserves	(205)		(594)		(314)
Capitalized exploratory well costs charged to expense	(100)		(105)		(307)
Balance — end of year	$	366	$	262	$	405

The Company expenses annual lease rentals, the costs of injectants used in production and geological and geophysical costs as incurred.

The Company determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. It amortizes leasehold costs over total proved reserves and capitalized development and successful exploration costs over proved developed reserves.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved reserves include PUD reserves. PUD reserves are supported by a management-approved, detailed, field-level development plan where sufficient capital has been committed to develop those reserves. Only PUD reserves which are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the PUD reserves are expected to be developed beyond the five years and are tied to approved long-term development projects.


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

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

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

MIDSTREAM AND MARKETING

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

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

IMPAIRMENTS AND OTHER CHARGES

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

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

INTANGIBLES AND GOODWILL

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

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


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every April. The Company’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is likely impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill, the Company will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, future acquisitions or future divestitures.

FAIR VALUE MEASUREMENTS

FAIR VALUES - RECURRING

The Company primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. The Company utilizes the mid-point between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, the Company makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For assets and liabilities carried at fair value, the Company measures fair value using the following methods:

■The Company values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1.

■OTC bilateral financial commodity contracts, foreign exchange contracts, interest rate swaps, warrants, options and physical commodity forward purchase and sale contracts are generally classified as Level 2 and are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace.

■The Company values commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are generally unobservable in the marketplace or are observable but have been adjusted based upon various assumptions and the fair value is designated as Level 3 within the valuation hierarchy.

■The Company values debt using market-observable information for debt instruments that are traded on secondary markets. For debt instruments that are not traded, the fair value is determined by interpolating the value based on debt with similar terms and credit risk.

NON-FINANCIAL ASSETS

The Company uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When the Company is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows. The expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions.


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ACCRUED LIABILITIES - CURRENT

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


millions	2025		2024
Payroll and related expenses	$	620	$	590
Taxes other than on income	498		436
Accrued interest payable	386		446
Dividends payable	383		354
Asset retirement obligations	381		388
Operating lease liabilities	350		334
Income tax payable	159		471
Carbon Engineering acquisition payable	—		393
Other	815		836
Accrued liabilities - current	$	3,592	$	4,248

ACCRUED LIABILITIES - NON-CURRENT

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


millions	2025		2024
Long term tax liabilities (a)	2,393		2,204
Environmental remediation liabilities (b)	1,719		1,759
Pension and postretirement obligations	985		1,022
Operating lease liabilities	605		469
Other	1,609		1,361
Accrued liabilities - non-current	$	7,311	$	6,815

(a) See Note 12 - Lawsuits, Claims, Commitments and Contingencies for additional information.

(b) See Note 11 - Environmental Liabilities and Expenditures for additional information.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

The Company incurs environmental liabilities and expenditures with respect to both current operations and remediation of existing conditions from alleged past practices at Third-Party, Currently Operated, and Closed or Non-operated Sites, which categories may include NPL sites. Environmental liabilities for estimated remediation costs from alleged past practices and related charges and expenses are recorded when environmental remediation efforts are probable and the costs can be reasonably estimated. Environmental expenditures related to current operations are expensed or capitalized as appropriate. The Company discloses such remediation liabilities on a consolidated basis. In determining the environmental remediation liability and the range of reasonably possible additional losses, the Company refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. These environmental remediation liabilities are based on management’s estimate of the most likely cost to be incurred using the most cost-effective technology reasonably expected to achieve the remedial objective. The Company periodically reviews these environmental remediation liabilities and adjusts them as new information becomes available. The Company generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable.

Many factors could affect future remediation costs incurred by the Company and result in adjustments to environmental remediation liabilities and the range of reasonably possible additional losses. The most significant are: (i) cost estimates for remedial activities may vary from the initial estimate; (ii) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (iii) a regulatory agency may ultimately reject or modify remedial plans proposed by the Company; (iv) improved or alternative remediation technologies may change remediation costs; (v) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (vi) changes in allocation or cost-sharing arrangements may occur.

Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (i) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among the Company and other alleged potentially responsible parties; (ii) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (iii) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, the Company evaluates the financial viability of other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences of their failure to participate when estimating its


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ultimate share of liability. The Company records its environmental remediation liabilities at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at CERCLA NPL sites, the Company’s environmental remediation liabilities include management’s estimates of the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, the Company reviews and adjusts its environmental remediation liabilities accordingly.

ASSET RETIREMENT OBLIGATIONS

The Company recognizes the fair value of AROs in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, the Company capitalizes the cost by increasing the related PP&E balances. If the estimated future cost of the AROs changes, the Company records an adjustment to both the AROs and PP&E. Over time, the liability is increased, expense is recognized for accretion and the capitalized cost is depreciated over the useful life of the asset. Adjustments to AROs for oil and gas properties where the field has reached cessation of production are recorded as gain (loss) on ARO settlements and are included in gain (loss) on the sale of assets and other, net in the Consolidated Statements of Operations.

The Company’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties.

At a certain number of its facilities, the Company has identified conditional AROs that are related mainly to plant decommissioning. The Company does not know or cannot estimate when it may settle these obligations. Therefore, the Company cannot reasonably estimate the fair value of these liabilities. The Company will recognize these conditional AROs in the periods in which sufficient information becomes available to reasonably estimate their fair values.

The following table summarizes the activity of AROs for the years ended December 31:


millions	2025		2024
Beginning balance	$	4,311	$	3,964

Liabilities incurred – capitalized to PP&E	138		287
Liabilities settled and paid	(536)		(444)
Accretion expense	212		228
Acquisitions, divestitures and other, net	(24)		2

Revisions to previous estimates	452		274
Ending balance	$	4,553	$	4,311

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Fair value gains or losses are recognized in earnings in the current period. Gains and losses from derivative instruments are reported net in the Consolidated Statements of Operations. See 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 1 4 - Stock-Based Incentive Plans. A summary of the Company’s accounting policy for awards issued under the Plans is as follows.

For cash- and stock-settled RSUs and CROCEI awards, compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout on the grant date. The fair value of stock options is estimated using a Black-Scholes model. For TSRI awards, compensation value is initially measured on the grant date using the fair value derived from a Monte Carlo valuation model. Compensation expense for all awards is recognized on a straight-line basis over the requisite service periods, which is generally over the awards’ respective vesting or performance periods. The stock-settled awards are expensed using the initially measured compensation value. Liabilities resulting from cash settled awards and accrued dividends are remeasured at each reporting period. Dividends accrued on unvested awards are adjusted quarterly for any changes in the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable.


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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

The Company recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans, which are more fully described in Note 1 0 - Retirement and Postretirement Benefit Plans, in its financial statements using a December 31 measurement date.

The Company’s defined benefit pension and postretirement benefit plan obligations are actuarially determined based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. The Company estimates the rate of return on assets with regard to current market factors but within the context of historical returns. The Company funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.

Pension and any postretirement plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common and collective trusts are valued at the fund units’ NAV provided by the issuer, which represents the quoted price in a non-active market. Short-term investment funds are valued at the fund units’ NAV provided by the issuer.

SUPPLEMENTAL CASH FLOW INFORMATION

The following table represents production, property and other tax payments and interest paid related to continuing operations during the year ended December 31, 2025, 2024 and 2023, respectively:


millions	2025		2024		2023
Production, property and other tax payments	$	1,079	$	1,260	$	1,120
Interest paid (a)	$	1,250	$	1,052	$	1,017

(a) Net of capitalized interest of $179 million, $156 million and $82 million, for the years 2025, 2024 and 2023, respectively.

See Note 9 - Income Taxes for information on income taxes paid. During the year ended December 31, 2024, the Company issued 29.6 million shares as a portion of the purchase price for the CrownRock Acquisition, see Note 4 -Acquisitions, Divestitures, and Other Transactions for additional details.

CASH EQUIVALENTS AND RESTRICTED CASH EQUIVALENTS

The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents. The cash equivalents and restricted cash equivalents balance as of December 31, 2025 included investments in government money market funds in which the carrying value approximates fair value.

The following table provides a reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents as reported at the end of the period in the Consolidated Statements of Cash Flows for the year ended December 31, 2025 and 2024:


millions	2025		2024
Cash and cash equivalents	$	1,968	$	2,125
Cash and cash equivalents included in assets held for sale	41		7
Restricted cash and restricted cash equivalents	20		11
Restricted cash and restricted cash equivalents included in long-term receivables and other assets, net	17		14
Cash, cash equivalents, restricted cash and restricted cash equivalents	$	2,046	$	2,157

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of the Company’s international oil and gas operations is the U.S. dollar since cash flows are denominated principally in U.S. dollars. In the Company’s other operations, the Company’s use of non-United States dollar functional currencies was not material for all years presented. The effect of exchange rates on transactions in foreign currencies is included in periodic income. The Company reports the exchange rate differences arising from translating foreign-currency-denominated balance sheet accounts to the United States dollar as of the reporting date in OCI. Exchange-rate gains and losses for continuing operations were not material for all years presented.

INCOME TAXES

The Company files various U.S. federal, state and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state and foreign income taxes are provided on temporary


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differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). See 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 1 1 - Environmental Liabilities and Expenditures, the Company has disclosed its reserve balances for environmental remediation matters that satisfy this criteria. See also Note 1 2 - Lawsuits, Claims, Commitments and Contingencies.

The following table summarizes the activity of the environmental, litigation, tax and other reserves from continuing operations for the years ended December 31:


millions	2025		2024		2023
Balance - beginning of year	$	2,551	$	2,452	$	2,339
Charged to costs and expenses	95		105		275
Charged to other accounts	208		131		24
Payments	(81)		(137)		(186)
Balance - end of year (a)	$	2,773	$	2,551	$	2,452

(a) Of these amounts, $140 million, $109 million and $113 million in 2025, 2024 and 2023, respectively, were classified as current.

RECENT ACCOUNTING PRONOUNCEMENTS

In November 2024, FASB issued new guidance to provide more detailed information about expenses. Issuers are to disclose disaggregated expenses of certain captions in tabular form. The rule becomes effective for annual periods beginning after December 15, 2026. The Company is currently evaluating the impact of adopting this guidance on the consolidated financial statements.


NOTE 2 - REVENUE

Revenue from customers is recognized when obligations under the terms of a contract are satisfied; this generally occurs with the delivery of oil, NGL, gas or services such as transportation. Revenue from customers is measured as the amount of consideration the Company expects to receive in exchange for the delivery of goods or services. Contracts may last from one month to one year or more and may have renewal terms that extend indefinitely at the option of either party. Price is typically based on market indexes. Volumes fluctuate due to production and, in certain cases, customer demand and transportation availability.

The Company does not incur significant costs to obtain contracts. Incidental items that are immaterial in the context of the contract are recognized as expenses. The Company does not typically receive payment in advance of satisfying its obligations under the terms of its sales contracts with customers; therefore, liabilities related to such payment are immaterial to the Company. The Company does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations.


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OIL AND GAS SEGMENT

Revenue from oil and gas production is recognized when production is delivered and control passes to the customer. Revenues from the production of oil and gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net revenue interest.

MIDSTREAM AND MARKETING SEGMENT

Revenue from pipeline and gas processing is recognized upon the completion of the transportation or processing service. Revenue from power sales is recognized upon delivery. Net marketing revenue is recognized upon completion of contract terms that are a prerequisite to payment and upon title transfer for physical deliveries. Unless the normal purchases and sales exception has been elected, net marketing revenue is classified as a derivative, reported on a net basis and recorded at fair value. Changes in fair value are reflected in net sales and excluded from revenue from customers in the table below.

DISAGGREGATION OF REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table reconciles revenue from customers to total net sales for the years ended December 31:


millions	2025		2024		2023
Revenue from customers	$	21,569	$	22,710	$	23,230
All other revenues	24		(691)		(74)
Net sales	$	21,593	$	22,019	$	23,156


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES

The table below presents the Company’s revenue from customers by segment, product and geographical area. The oil and gas segment typically sells its oil, NGL and natural gas at the lease or concession area. Excluding net marketing revenue, midstream and marketing segment revenues are shown by the location of sale.


millions	United States		International		Eliminations		Total
Year ended December 31, 2025
Oil and gas
Oil	$	14,459	$	2,715	$	—	$	17,174
NGL	1,897		352		—		2,249
Gas	1,017		352		—		1,369
Other	105		5		—		110
Segment total	$	17,478	$	3,424	$	—	$	20,902
Midstream and marketing	$	546	$	709	$	—	$	1,255




Eliminations	$	—	$	—	$	(588)	$	(588)
Consolidated	$	18,024	$	4,133	$	(588)	$	21,569

Year ended December 31, 2024
Oil and gas
Oil	$	15,604	$	2,940	$	—	$	18,544
NGL	1,865		390		—		2,255
Gas	514		361		—		875
Other	29		2		—		31
Segment total	$	18,012	$	3,693	$	—	$	21,705
Midstream and marketing	$	1,164	$	413	$	—	$	1,577
Eliminations	$	—	$	—	$	(572)	$	(572)
Consolidated	$	19,176	$	4,106	$	(572)	$	22,710

Year ended December 31, 2023
Oil and gas
Oil	$	14,893	$	3,057	$	—	$	17,950
NGL	1,619		372		—		1,991
Gas	970		335		—		1,305
Other	36		2		—		38
Segment total	$	17,518	$	3,766	$	—	$	21,284
Midstream and marketing	$	2,098	$	409	$	—	$	2,507
Eliminations	$	—	$	—	$	(561)	$	(561)
Consolidated	$	19,616	$	4,175	$	(561)	$	23,230


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES


NOTE 3 - INVESTMENTS AND RELATED-PARTY TRANSACTIONS

INVESTMENTS IN UNCONSOLIDATED ENTITIES

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


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

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

The following table represents cumulative undistributed earnings and investments in excess of equity as of December 31, 2025 and 2024:


millions	2025		2024
Cumulative undistributed earnings	$	664	$	764
Investments in excess of equity
Investment in excess of equity allocated to PP&E and equity investments	$	279	$	316
Investment in excess of equity allocated to intangibles and other assets	$	93	$	105
Total investments in excess of equity	$	372	$	421

Dividends received from equity investments were $705 million, $682 million and $571 million to the Company in 2025, 2024 and 2023, respectively.

In 2025, the Company recorded its share of NET Power’s impairment losses of $401 million, bringing book value of its investment to zero. In the fourth quarter of 2025, WES acquired Aris Water Solutions, Inc. with a mix of stock and cash, and the Company recognized a gain of $301 million from its pro-rata ownership reduction in WES. In 2024 and 2023, the Company sold 19.5 million and 5.1 million of its limited partner units in WES, respectively, resulting in gains on sale of $489 million and $51 million, respectively.

The following table presents the summarized financial information of its equity-method investments combined for the years ended and as of December 31, 2025, 2024 and 2023:


millions	2025		2024		2023
Summarized Results of Operations
Revenues and other income	$	4,794	$	4,580	$	4,086
Costs and expenses	5,136		3,025		3,219
Net income	$	(342)	$	1,555	$	867

Summarized Balance Sheet
Current assets	$	4,086	$	4,643	$	4,493
Non-current assets	$	17,599	$	17,132	$	17,634
Current liabilities	$	2,279	$	2,183	$	2,462
Long-term debt	$	9,787	$	9,296	$	9,673
Other non-current liabilities	$	2,624	$	2,328	$	2,292
Equity	$	6,995	$	7,968	$	7,700


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RELATED-PARTY TRANSACTIONS

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


millions	2025		2024		2023
Sales (a)	$	128	$	146	$	153
Purchases (b)	$	4	$	28	$	159
Services (c)	$	1,505	$	1,415	$	1,156
Advances and amounts due from related parties	$	30	$	36	$	49
Amounts due to related parties	$	333	$	342	$	331

(a)In 2025, 2024 and 2023, sales of Company-produced oil and NGL to WES accounted for 53%, 58% and 63% of related party sales, respectively.

(b)In 2025, 2024 and 2023, purchases of gas and NGL marketed on behalf of WES accounted for all of the related party purchases.

(c)In 2025, 2024 and 2023, services primarily related to fees charged by WES to gather, process and treat the Company produced oil, NGL and natural gas.


NOTE 4 - ACQUISITIONS, DIVESTITURES AND OTHER TRANSACTIONS

ACQUISITIONS, DIVESTITURES AND OTHER TRANSACTIONS

2025

During 2025, the Company sold non-core assets for $2.3 billion which included working interests in the Permian Basin for proceeds of approximately $800 million, non-operated proved and unproved royalty and mineral interests in the DJ Basin for proceeds of approximately $840 million and certain gas gathering assets in the Permian Basin for approximately $580 million. The differences in the assets’ net book values and adjusted purchase prices were treated as a normal retirements, and as a result no gains or losses were recognized.

2024

In December 2023, the Company entered into an agreement to purchase CrownRock for total consideration of $12.4 billion, consisting of $9.4 billion of cash consideration (inclusive of certain working capital and other customary purchase price adjustments), 29.6 million shares of Occidental common stock, and the assumption of $1.2 billion of existing debt of CrownRock. The acquisition closed on August 1, 2024, adding to the Company’s oil and gas portfolio in the Permian Basin.


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The CrownRock Acquisition qualified as a business combination and was accounted for using the acquisition method of accounting. The following table summarizes the cash and common stock components of the purchase price:


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

The following table sets forth the allocation of the acquisition consideration. The Company finalized the purchase price allocation during the 12-month period following the acquisition date. Measurement period adjustments recorded were immaterial and did not result in a material impact to the statements of operations.


in millions	August 1, 2024
Fair value of assets acquired:
Cash and cash equivalents	$	589
Trade receivables, net	198

Other current assets	39

Property, plant and equipment, oil and gas	11,837


Amount attributable to assets acquired	$	12,663
Fair value of liabilities acquired:
Current maturities of long-term debt	$	868
Accounts payable	207
Accrued liabilities	22
Long-term debt	378
Asset retirement obligations	47
Amount attributable to liabilities acquired	$	1,522
Fair value of net assets acquired:	$	11,141

The aggregate purchase price noted above was allocated to the major categories of assets and liabilities acquired based upon their preliminary estimated fair values at the date of the acquisition. The valuation of certain assets, primarily property, was based on preliminary appraisals.

Unproved oil and gas properties were valued using a market approach based on comparable transactions for similar properties.

Proved oil and gas properties were valued using an income approach, which are considered Level 3 fair value estimates and include significant assumptions of future production and timing of production, commodity price assumptions, and operating and capital cost estimates, discounted using an 8.5% weighted average cost of capital. Taxes were based on current statutory rates. Future production and timing of production were based on internal reserves estimates and internal economic models for specific proved oil and gas assets. Price assumptions were based on a combination of market information and published industry resources adjusted for historical differentials. Price assumptions ranged from approximately $75 per barrel of oil increasing to approximately $97 per barrel of oil for the 15-year period, with an unweighted arithmetic average price of $84.79 for WTI indexed assets for the same period. Natural gas prices ranged from approximately $2.80 per Mcf to $5.10 per Mcf for the 15-year period, with an unweighted arithmetic average price of $4.34 for NYMEX based assets for the same period. Both oil and natural gas commodity prices were held flat after 2038 and were adjusted for location and quality differentials. Operating and capital cost estimates were based on current observable costs and were further escalated 2% in every period. The weighted average cost of capital was calculated based on industry peers and best approximates the cost of capital an external market participant would expect to obtain.


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES

The following summarizes the unaudited pro forma condensed financial information of the Company as if the CrownRock Acquisition had occurred on January 1, 2023 for the years ended December 31:


millions, except per-share amounts	2024		2023

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

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

2023

In August 2023, the Company entered into an agreement with Carbon Engineering Ltd., its equity method investee, to purchase the remaining 68% interest not already owned by the Company or its affiliates for total cash consideration of approximately $1.1 billion, resulting in Carbon Engineering becoming a wholly owned subsidiary of the Company. The transaction qualified as a business combination and was accounted for using the acquisition method of accounting. Because the Company acquired control of Carbon Engineering in the 2023 purchase, the Company remeasured its previously held 32% equity interest at its acquisition-date fair value and recognized the resulting gain of $283 million in accordance with GAAP. The purchase price was payable in three approximately equal annual payments, with the first payment made at closing. This transaction closed on November 3, 2023, and the Company made the first payment of $349 million. The second payment of $318 million was made in the fourth quarter of 2024, and the last payment was made in the fourth quarter of 2025.

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

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

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

DISCONTINUED OPERATIONS

OxyChem

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

The OxyChem Transaction marks a strategic change in the Company’s operations. Refer to Note 5 Long-Term Debt for the Company’s use of the after-tax sale proceeds.

Andes

As previously disclosed, on April 5, 2024, Andes and the Company entities named in the pending actions related to the Andes Arbitration executed a confidential final settlement in which the parties agreed to dismiss all pending legal actions. The settlement resulted in a gain of $182 million, net of taxes, in discontinued operations.


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES

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


millions	2025		2024		2023
Revenues and other income
Net Sales	$	4,368	$	4,706	$	5,101
Interest, dividends and other income	—		(21)		(14)
Gains on sales of assets and others, net	3		239		—
Total revenues and other income	4,371		4,924		5,087
Costs and other deductions
Chemical cost of sales	3,099		3,027		3,009
Selling, general and administrative expense	119		102		96
Other operating and non-operating expense	383		262		(81)
Depreciation, depletion and amortization	342		420		416
Asset impairments and other charges	—		925		—
Acquisition-related costs	22		—		—
Other expense, net	16		6		(12)
Total costs and other deductions	3,981		4,742		3,428
Income before income taxes and other items	390		182		1,659
Income from equity investments and other	105		103		108
Income before income taxes	495		285		1,767
Income tax expense	(233)		(73)		(403)
Income from discontinued operations, net of tax	$	262	$	212	$	1,364

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


millions	2025		2024
Assets
Cash and cash equivalents	$	41	$	7
Trade receivables, net	640		687
Inventories	383		339
Other current assets	112		107
Total current assets held for sale	1,176		1,140
Investments in unconsolidated entities	475		513
Property, plant and equipment, net	4,442		3,515
Operating lease assets	207		182
Other long-term assets	220		220
Total non-current assets held for sale	5,344		4,430
Total assets held for sale	$	6,520	$	5,570
Liabilities
Current maturities of long-term debt	$	6	$	—
Accounts payable	410		281
Accrued liabilities	362		382
Total current liabilities held for sale	778		663
Long-term debt, net	41		(1)
Asset retirement obligations	126		119
Other deferred credits and liabilities	251		215
Total non-current liabilities held for sale	418		333
Total liabilities held for sale	$	1,196	$	996


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES

The following table summarizes the activity of the environmental and litigation reserves related to the retained liabilities and indemnification obligations associated with the chemical business for the years ended December 31:


millions	2025		2024		2023
Balance - beginning of year	$	1,711	$	798	$	828
Charged to costs and expenses	375		1,007		52
Charged to other accounts	53		11		26
Payments	(176)		(105)		(108)
Balance - end of year (a)	$	1,963	$	1,711	$	798

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


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NOTE 5 - LONG-TERM DEBT

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


millions	2025	2024
5.875% senior notes due 2025	—	536
5.500% senior notes due 2025	—	465
5.550% senior notes due 2026	—	870
3.400% senior notes due 2026	—	284
Two-year term loan due 2026 (5.475% and 6.249% as of December 31, 2025 and 2024, respectively)	1,280	2,700
3.200% senior notes due 2026	182	182
7.500% debentures due 2026	112	112
8.500% senior notes due 2027	489	489
3.000% senior notes due 2027	216	216
7.125% debentures due 2027	150	150
7.000% debentures due 2027	48	48
5.000% senior notes due 2027	600	600
6.625% debentures due 2028	14	14
7.150% debentures due 2028	232	232
7.200% senior debentures due 2028	82	82
6.375% senior notes due 2028	578	578
7.200% debentures due 2029	135	135
7.950% debentures due 2029	116	116
8.450% senior debentures due 2029	116	116
3.500% senior notes due 2029	286	286
5.200% senior notes due 2029	1,200	1,200
Variable rate bonds due 2030 (4.450% and 5.710% as of December 31, 2025 and 2024, respectively)	68	68
8.875% senior notes due 2030	1,000	1,000
6.625% senior notes due 2030	1,449	1,449
6.125% senior notes due 2031	1,143	1,143
7.500% senior notes due 2031	900	900
7.875% senior notes due 2031	500	500
5.375% senior notes due 2032	1,000	1,000
5.550% senior notes due 2034	1,200	1,200
6.450% senior notes due 2036	1,727	1,727
Zero Coupon senior notes due 2036	285	673
0.000% loan due 2039 (CAD denominated)	17	18
4.300% senior notes due 2039	247	247
7.950% senior notes due 2039	325	325
6.200% senior notes due 2040	737	737
4.500% senior notes due 2044	191	191
4.625% senior notes due 2045	296	296
6.600% senior notes due 2046	1,117	1,117
4.400% senior notes due 2046	424	424
4.100% senior notes due 2047	258	258
4.200% senior notes due 2048	304	304
4.400% senior notes due 2049	280	280
(continued on next page)


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millions (continued)	2025		2024
6.050% senior notes due 2054	1,000		1,000
7.730% debentures due 2096	58		58
7.500% debentures due 2096	60		60
7.250% debentures due 2096	5		5
Total borrowings at face value	$	20,427	$	24,391
Adjustments to book value:
Unamortized premium, net	1,054		1,037
Debt issuance costs	(84)		(104)
Net book value of debt	$	21,397	$	25,324
Long-term finance leases	801		658
Current finance leases	198		135
Total debt and finance leases	$	22,396	$	26,117
Less current maturities of finance leases	(198)		(135)
Less current maturities of long-term debt	(1,575)		(1,003)
Long-term debt, net	$	20,623	$	24,979

DEBT ACTIVITY AND DEBT MATURITIES

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


millions	Borrowings at face value
Total borrowings at face value as of December 31, 2024	$	24,391

Repayments
5.875% senior notes due 2025	(536)
5.500% senior notes due 2025	(465)
5.550% senior notes due 2026	(870)
3.400% senior notes due 2026	(284)
Zero Coupon senior notes due 2036	(388)
Two-year term loan due 2026	(1,420)
Other	(1)
Total repayments	$	(3,964)

Total borrowings at face value as of December 31, 2025	$	20,427

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

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

FAIR VALUE OF DEBT

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


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DEBT RATINGS

As of December 31, 2025, the Company’s long-term debt was rated Baa3 by Moody’s Investors Service, BBB- by Fitch Ratings and BB+ by Standard and Poor’s. Any downgrade in credit ratings could impact the Company’s ability to access capital markets and increase its cost of capital. In addition, Occidental or its subsidiaries may be requested, elect to provide or in some cases be required to provide collateral in the form of cash, letters of credit, surety bonds or other acceptable support as financial assurance of their performance and payment obligations under certain contractual arrangements such as pipeline transportation contracts, oil and gas purchase contracts and certain derivative instruments; certain permits, including with respect to carbon capture, utilization and storage activities; and environmental remediation matters.

As of the date of this filing, the Company had provided required financial assurances through a combination of cash, letters of credit and surety bonds and had not issued any letters of credit under the RCF or other committed facilities.

REVOLVING CREDIT FACILITY

In February 2024, the Company entered into a Third Amended and Restated Credit Agreement for the RCF extending its maturity date to June 30, 2028. In May 2024, the Company amended the RCF to add an additional $150 million commitment, increasing the borrowing capacity to $4.15 billion. No amounts were drawn under the facility as of December 31, 2025.

Borrowings under the RCF bear interest at SOFR benchmark rates, plus a margin based on the Company’s senior debt ratings. The facility has similar terms to other debt agreements and does not contain material adverse change clauses or debt ratings triggers that could restrict the Company’s ability to borrow, or that would permit lenders to terminate their commitments or accelerate debt repayment. The facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. As of the date of this filing, the Company had no drawn amounts under the RCF. In 2025, the Company paid average annual facility fees of 0.20% on the total commitment amount.


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NOTE 6 - LEASE COMMITMENTS

Lease assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Lease assets include the discounted value of future lease payments, upfront payments and costs incurred to execute the lease and are amortized on a straight-line basis over the lease term. The Company assesses the likelihood of exercising renewal, termination and purchase options to determine the lease term. The Company uses its incremental borrowing rate at commencement date to determine the present value of lease payments. The Company separates lease and non-lease components for drilling rigs and vessels. The Company does not separate lease and non-lease components for the remainder of asset classes as the non-lease portions are not significant.

The Company has operating leases from continuing operations for drilling rigs of $273 million, office space of $251 million, vessels of $191 million, compressors of $130 million and $110 million of other assets. Operating leases related to discontinued operations of $211 million are included in liabilities held for sale.

The Company’s finance leases from continuing operations include compressors of $428 million, assets related to DAC operations of $292 million, office space of $208 million and $71 million of other assets. Finance leases related to discontinued operations of $47 million are included in liabilities held for sale. Property, plant and equipment included $972 million of finance lease assets as of December 31, 2025.

The following summarizes maturities of lease liabilities related to continuing operations as of December 31, 2025:


millions	Operating Leases (a)		Finance Leases (b)		Total
2026	$	387	$	248	$	635
2027	289		226		515
2028	190		188		378
2029	58		152		210
2030	44		136		180
Thereafter	68		226		294
Total lease payments	1,036		1,176		2,212
Less: Discount	(81)		(177)		(258)
Total lease liabilities	$	955	$	999	$	1,954

(a)The weighted-average remaining lease term is 3.5 years and the weighted-average discount rate is 4.94%.

(b)The weighted-average remaining lease term is 5 years and the weighted-average discount rate is 5.07%.

The following tables present the Company’s total lease cost and other information for operating and finance lease liabilities related to continuing operations for the years ended December 31:


millions	2025		2024
Lease Cost
Finance lease cost:
Amortization of right-of-use assets	$	188	$	152
Interest on lease liabilities	40		36
Operating lease cost	486		459
Short-term lease cost	384		342

Total lease cost	$	1,098	$	989

millions	2025		2024
Cash payments related to leases
Operating cash flows from finance leases	$	40	$	34
Operating cash flows from operating leases	$	295	$	240
Investing cash flows from operating leases	$	192	$	209
Financing cash flows from finance leases	$	177	$	137

Changes in Right-of-Use assets
Right-of-use assets obtained in relation to new finance lease liabilities	$	395	$	195
Right-of-use assets obtained in relation to new operating lease liabilities	$	617	$	280


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NOTE 7 - DERIVATIVES

OBJECTIVE AND STRATEGY

The Company uses a variety of derivative financial instruments and physical contracts to manage its exposure to commodity price fluctuations and transportation commitments and to fix margins on the future sale of stored commodity volumes. Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. The Company may occasionally use a variety of derivative financial instruments to manage its exposure to foreign currency fluctuations and interest rate risks. The Company also enters into derivative financial instruments for trading purposes. The Company may elect normal purchases and normal sales exclusions when physically delivered commodities are purchased from a vendor or sold to a customer. See Note 1 - Summary of Significant Accounting Policies for the Company’s accounting policy on derivatives.

DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS

As of December 31, 2025, the Company’s derivatives not designated as hedges consisted of marketing derivatives. These instruments are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings through mark‑to‑market adjustments until the underlying physical commodity is delivered or the financial instrument is settled.

MARKETING DERIVATIVES

The Company’s marketing derivative instruments not designated as hedges are short-duration physical and financial forward contracts. A substantial majority of the Company’s physically settled derivative contracts are index-based and carry no mark-to-market valuation in earnings. As of December 31, 2025, the weighted-average settlement prices of these forward contracts were $59.59 per barrel and $2.53 per Mcf for crude oil and natural gas, respectively. The weighted-average settlement prices were $71.07 per barrel and $3.50 per Mcf for crude oil and natural gas, respectively, as of December 31, 2024. Net gains and losses associated with marketing derivative instruments not designated as hedging instruments are recognized in net sales. Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities.

The following table summarizes net short volumes associated with the outstanding marketing commodity derivatives as of December 31:



	2025	2024
Oil commodity contracts
Volume (MMbbl)	(59)	(34)

Natural gas commodity contracts
Volume (Bcf)	(189)	(130)

FAIR VALUE OF DERIVATIVES

The Company has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 – using quoted prices in active markets for the assets or liabilities; Level 2 – using observable inputs other than quoted prices for the assets or liabilities; and Level 3 – using unobservable inputs. Transfers between levels, if any, are reported at the end of each reporting period. The following table presents the fair values of the Company’s outstanding derivatives. Fair values are presented at gross amounts below, including when derivatives are subject to netting arrangements, and are presented on a net basis in the Consolidated Balance Sheets.


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millions	Fair Value Measurements Using								Total Fair Value
Balance Sheet Classification	Level 1		Level 2		Level 3		Netting (a)
December 31, 2025



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

(a)These amounts do not include collateral. The Company netted $29 million of collateral received from brokers against derivative assets and $23 million of collateral deposited with brokers against derivatives liabilities as of December 31, 2025. As of December 31, 2024, the Company netted $12 million of collateral received from brokers against derivative assets and $9 million collateral deposited with brokers against derivative liabilities.

GAINS AND LOSSES ON DERIVATIVES

The following table presents gains and (losses) related to the Company’s derivative instruments in the Consolidated Statements of Operations for the years ended December 31:


millions
Income Statement Classification	2025		2024		2023

Marketing Derivatives
Net sales (a)	$	32	$	(374)	$	(74)

(a)Included derivative and non-derivative marketing activity.

CREDIT RISK

The majority of the Company’s counterparty credit risk is related to the physical delivery of energy commodities to its customers and any inability to meet their settlement commitments. The Company manages credit risk by selecting counterparties that it believes to be financially strong, by entering into netting arrangements with counterparties and by requiring collateral or other credit risk mitigants, as appropriate. The Company actively evaluates the creditworthiness of its counterparties, assigns appropriate credit limits and monitors credit exposures against those assigned limits. The Company also enters into futures contracts through regulated exchanges with select clearinghouses and brokers, which are subject to minimal credit risk, if any.


NOTE 8 - FAIR VALUE MEASUREMENTS

FAIR VALUES – NONRECURRING

There were no significant non-recurring fair value measurements in 2025.

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

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


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FINANCIAL INSTRUMENTS FAIR VALUE

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


NOTE 9 - INCOME TAXES

RECENT TAX LEGISLATION

The OBBBA was enacted on July 4, 2025 and introduced provisions expected to benefit the Company including accelerated depreciation for newly acquired and constructed assets, favorable adjustments to interest expense limitation, immediate deduction of research and development costs, and increased tax credit values for qualified CO2 projects. In accordance with ASC 740, the financial statement impact of the OBBBA was recognized beginning in the third quarter of 2025. These provisions are expected to significantly reduce the Company’s 2025 cash tax liability.

The OECD Pillar Two initiative proposes to apply a 15% global minimum tax on multinational entities, applied on a jurisdiction-by-jurisdiction basis. Several countries, including European Union member states, Canada and Oman, have enacted or are in the process of enacting legislation aligned with all or portions of Pillar Two. The Company continues to monitor and assess the impact of new OECD Pillar Two administrative guidance and Pillar Two compliant legislation proposed or enacted in the jurisdictions in which the Company operates. Based on developments to date, the Company does not anticipate any significant impact on the Company’s results of operations or cash flows from the enactment of Pillar Two legislation.

The following summarizes domestic and foreign components of income from continuing operations before domestic and foreign income taxes for the years ended December 31:


millions	2025		2024		2023
Domestic	$	1,265	$	2,390	$	2,530
Foreign	1,863		1,634		2,132
Total income from continuing operations before income taxes	$	3,128	$	4,024	$	4,662

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


millions	2025		2024		2023
Current
Federal	$	(307)	$	(775)	$	(539)
State and local	—		(28)		(35)
Foreign	(587)		(620)		(702)
Total current tax expense	$	(894)	$	(1,423)	$	(1,276)
Deferred
Federal	(99)		197		(34)
State and local	(31)		20		20
Foreign	3		48		(40)
Total deferred tax (expense) benefit	$	(127)	$	265	$	(54)
Total income tax expense
Federal	(406)		(578)		(573)
State and local	(31)		(8)		(15)
Foreign	(584)		(572)		(742)
Total income tax expense	$	(1,021)	$	(1,158)	$	(1,330)


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


millions	2025		2024		2023
Federal	$	609	$	405	$	293
State	39		16		42
Foreign
Algeria	155		207		285
Oman	359		332		335
Qatar	73		78		78
All other foreign	1		2		7
Total foreign	588		619		705
Income taxes paid, net of refunds received	$	1,236	$	1,040	$	1,040


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The following reconciliation of the U.S. federal statutory income tax rate to the Company’s worldwide effective tax rate on income from continuing operations for the years ended December 31 is stated as both a percentage and amount of income from continuing operations before income taxes as required by the adoption of Accounting Standards Update 2023-09 in the fourth quarter of 2025:


millions except percentages	2025				2024				2023
	Percentage		Amount		Percentage		Amount		Percentage		Amount
U.S. federal statutory tax rate	21	%	$	657	21	%	$	845	21	%	$	979
State and local income tax, net of federal income tax effect (a)	1		24		—		5		—		13
Foreign tax effects
Algeria
Tax rate differential	1		36		1		47		1		71
Change in tax law or rate	—		—		—		—		1		65
Nontaxable or nondeductible items	1		23		1		20		2		84
Others	—		7		1		20		—		(3)
Canada
Others	(1)		(16)		—		(7)		(1)		(54)
Oman
Tax rate differential	7		201		5		203		4		209
Others	1		34		—		4		—		(3)
Qatar
Tax rate differential	1		33		1		28		1		37
Others	—		(9)		—		8		—		(14)
United Arab Emirates
Tax rate differential	(5)		(143)		(3)		(105)		(2)		(94)
Other foreign jurisdictions	1		30		—		(5)		—		(11)
Effect of changes in tax laws or rates enacted in the current period	—		—		—		—		—		—
Effect of cross-border tax laws	—		10		—		1		—		4
Tax credits	(1)		(15)		(1)		(21)		—		(22)
Changes in valuation allowance	—		2		—		2		—		—
Nontaxable or nondeductible items	1		16		1		29		—		20
Changes in unrecognized tax benefits	5		144		3		136		2		105
Other adjustments	—		(13)		(1)		(52)		(1)		(56)
Worldwide effective tax rate	33	%	$	1,021	29	%	$	1,158	28	%	$	1,330

(a) Texas and New Mexico contributed to the majority of the tax effect in this category.

The Company’s worldwide effective tax rate in 2025, 2024 and 2023 was higher than the U.S. statutory rate of 21%, primarily driven by the Company’s jurisdictional mix of income from continuing operations, where international income is subject to tax at statutory rates as high as 55%.

The reclassification of OxyChem, which is primarily domestic, to discontinued operations increased this impact. The effective tax rate for discontinued operations was 47%, 26% and 23% for 2025, 2024 and 2023, respectively. The increase in the 2025 discontinued operations effective tax rate relative to 2024 and 2023 is the result of a one-time charge associated with the OxyChem Transaction.


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


millions	2025		2024
Deferred tax liabilities
Property, plant and equipment differences	$	(7,402)	$	(7,100)
Equity investments, partnerships and international subsidiaries	(831)		(633)
Gross long-term deferred tax liabilities	$	(8,233)	$	(7,733)

Deferred tax assets
Environmental reserves	409		416
Postretirement benefit accruals	173		249
Deferred compensation and benefits	344		258
Asset retirement obligations	893		788
Foreign tax credit carryforwards	713		1,975
Business credit carryforwards	60		54
Net operating loss carryforward	1,095		1,031
Interest expense carryforward	11		11
All other	685		539
Gross long-term deferred tax assets	4,383		5,321
Valuation allowance	(1,769)		(2,962)
Net long-term deferred tax assets	$	2,614	$	2,359
Total deferred income tax liability, net	$	(5,619)	$	(5,374)
Less: foreign deferred tax asset in long-term receivables and other assets, net	(17)		(20)
Total deferred income tax liability (a)	$	(5,636)	$	(5,394)

(a) The deferred income tax assets and liabilities associated with discontinued operations were not classified as held for sale because they will be realized upon the sale of OxyChem.

Total deferred tax assets, after valuation allowances, were $2.6 billion and $2.4 billion as of December 31, 2025 and 2024, respectively. The Company expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The total deferred tax liabilities were $8.2 billion and $7.7 billion as of December 31, 2025 and 2024, respectively.

As of December 31, 2025, the Company had foreign tax credit carryforwards of $713 million and state tax credit carryforwards of $39 million. The Company had recorded a valuation allowance for $713 million of the foreign tax credit carryforwards and $32 million of the state tax credit carryforwards.

As of December 31, 2025, the Company had tax-effected foreign net operating loss carryforwards of $971 million, state net operating loss carryforwards of $121 million, and federal net operating loss carryforwards of $3 million. The carryforward balances have varying carryforward periods through 2045, excluding certain attributes for which there is an indefinite carryforward period. A valuation allowance was recorded for $890 million of the tax-effected foreign net operating loss carryforwards and $85 million of the tax-effected state net operating loss carryforwards. The Company had an additional valuation allowance of $46 million against other foreign deferred tax assets.

The Company had a tax-effected state interest expense carryforward of $11 million with no valuation allowance as of December 31, 2025.

In prior years, a deferred tax liability had not been recognized for temporary differences related to unremitted earnings of certain consolidated international subsidiaries. As of December 31, 2025, in connection with the OxyChem Transaction, the Company reversed its indefinite reinvestment assertion for unremitted earnings of its foreign operations. The reversal resulted in the recognition of a deferred tax liability of $101 million related to such earnings, presented as part of discontinued operations.


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


millions	2025		2024		2023
Balance as of January 1	$	1,951	$	1,951	$	2,010
Increases related to prior-year positions	—		—		—
Increases related to current-year positions	1		—		—
Settlements	—		—		—
Reductions for tax positions of prior years	(8)		—		(59)
Balance as of December 31	$	1,944	$	1,951	$	1,951

The December 31, 2025 balance of unrecognized tax benefits of $1.9 billion included potential tax benefits of $1.9 billion of which, if recognized, $1.4 billion would affect the effective tax rate on income. Also included were benefits of $45 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain. Unrecognized tax benefits are included in deferred credits and other liabilities - other. The Company records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes. In 2025, the Company recorded interest related to liabilities for unrecognized tax benefits of $188 million, for a cumulative accrued interest related to liabilities for unrecognized tax benefits of $951 million as of December 31, 2025, which is not included in the table above. There were no penalties associated with liabilities for unrecognized tax benefits recorded for the years ended December 31, 2025 and 2024.

The Company recognized $54 million and $30 million in federal and state income tax receivables as of December 31, 2025 and 2024, respectively, which were recorded in other current assets. In addition, the Company recognized $470 million and $247 million in 2025 and 2024, respectively, of long-term income tax receivables, which were recorded in long-term receivables and other assets, net.

The Company is subject to audit by various tax authorities in varying periods. See Note 1 2 - Lawsuits, Claims, Commitments and Contingencies for a discussion of these matters.


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NOTE 10 - RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

The Company has various defined contribution and defined benefit plans for its salaried, domestic union and nonunion hourly and certain foreign national employees. In addition, the Company also provides medical and other benefits for certain active, retired and disabled employees and their eligible dependents.

DEFINED CONTRIBUTION PLANS

All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by the Company based on plan-specific criteria, such as base pay, level and employee contributions. Certain salaried employees participate in a supplemental retirement plan that restores benefits lost due to government limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $451 million and $387 million as of December 31, 2025 and 2024, respectively. In 2025, 2024 and 2023 the Company expensed $274 million, $252 million and $221 million, respectively, under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited. Pension costs for the Company’s defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.

POSTRETIREMENT AND OTHER BENEFIT PLANS

The Company provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. The Company generally funds the benefits as they are paid during the year. In 2025, 2024 and 2023, these benefit costs, including the postretirement costs, were $240 million, $205 million and $175 million, respectively.

OBLIGATIONS AND FUNDED STATUS

The following tables show the amounts recognized in the Company’s Consolidated Balance Sheets related to its pension and postretirement benefit plans as of December 31:


	Pension Benefits				Postretirement Benefits
millions	2025		2024		2025		2024
Amounts recognized in the Consolidated Balance Sheet:
Other long-term assets	$	153	$	133	$	—	$	—
Accrued liabilities	(2)		(2)		(51)		(52)
Deferred credits and other liabilities	(228)		(244)		(757)		(778)
	$	(77)	$	(113)	$	(808)	$	(830)
Accumulated other comprehensive loss included the following after-tax balances:
Net (gain) loss	$	(29)	$	(8)	$	(120)	$	(122)
Prior service credit	—		—		(59)		(40)
	$	(29)	$	(8)	$	(179)	$	(162)


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The following tables show the funding status, obligations and plan asset fair values of the Company related to its pension and postretirement benefit plans for the years ended December 31:


	Pension Benefits				Postretirement Benefits
millions	2025		2024		2025		2024
Changes in the benefit obligation:
Benefit obligation — beginning of year	$	813	$	879	$	830	$	718
Service cost — benefits earned during the period	4		4		20		18
Interest cost on projected benefit obligation	42		42		42		35
Actuarial (gain) loss	14		(38)		(10)		105
Benefits paid	(68)		(71)		(45)		(50)
Plan amendments	—		—		(33)		—
Other	4		(3)		4		4
Benefit obligation — end of year	$	809	$	813	$	808	$	830

Changes in plan assets:
Fair value of plan assets — beginning of year	$	700	$	732	$	—	$	—
Actual return on plan assets	72		16		—		—
Employer contributions	21		23		41		45
Benefits paid	(68)		(71)		(45)		(50)
Other	7		—		4		5
Fair value of plan assets — end of year	$	732	$	700	$	—	$	—
Unfunded status:	$	(77)	$	(113)	$	(808)	$	(830)

Actuarial losses related to postretirement benefits are primarily due to changes in health care trend rates and expected increases in premiums related to certain provisions in the Inflation Reduction Act. Other actuarial gains and losses are primarily driven by discount rate movement. The decrease in postretirement obligation in 2025 due to plan amendments is related to changes in Medicare advantaged prescription drug plans to introduce an annual deductible and remove certain benefits.

The following table sets forth details of the obligations and assets of the Company’s defined benefit pension plans as of December 31:


	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
millions	2025		2024		2025		2024
Projected benefit obligation	$	636	$	648	$	173	$	165
Accumulated benefit obligation	$	636	$	647	$	173	$	165
Fair value of plan assets	$	525	$	505	$	207	$	195


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COMPONENTS OF NET PERIODIC BENEFIT COSTS

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


	Pension Benefits						Postretirement Benefits
millions	2025		2024		2023		2025		2024		2023
Net periodic benefit costs:
Service cost — benefits earned during the period	$	4	$	4	$	5	$	20	$	18	$	16
Interest cost on projected benefit obligation	42		42		45		42		35		37
Expected return on plan assets	(36)		(41)		(45)		—		—		—
Recognized actuarial loss (gain)	3		2		4		(11)		(15)		(20)
Recognized prior service credit	—		—		—		(8)		(8)		(9)

Gain (loss) due to settlement	—		—		1		—		—		—


Net periodic benefit costs	$	13	$	7	$	10	$	43	$	30	$	24

The service cost component of net periodic benefit costs is included in selling, general and administrative expense, oil and gas operating expense, midstream costs and exploration expense on the Company’s Consolidated Statements of Operations. All other components of net periodic benefit costs are included in other operating and non-operating expense. As a result of the OxyChem Transaction, pension and postretirement net periodic benefit costs of approximately $9 million, $1 million and $2 million were reclassified to discontinued operations in the income statement for fiscal years 2025, 2024 and 2023 respectively.

ADDITIONAL INFORMATION

The following table sets forth the weighted-average assumptions used to determine the Company’s benefit obligation and net periodic benefit cost for domestic plans for the years ended December 31:


	Pension Benefits				Postretirement Benefits
	2025		2024		2025		2024
Benefit Obligation Assumptions:
Discount rate	5.29	%	5.52	%	5.45	%	5.68	%
Rate of increase in compensation levels	3.49	%	3.95	%	—		—
Net Periodic Benefit Cost Assumptions:
Discount rate	5.52	%	4.98	%	5.68	%	5.12	%
Rate of increase in compensation levels	3.95	%	3.96	%	—		—
Assumed long-term rate of return on assets	5.49	%	6.13	%	—		—

For domestic pension plans and postretirement benefit plans, the Company based the discount rate on a AA-AAA Universe yield curve in 2025 and 2024. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end. Assumed rates of compensation increases for active participants in certain plans vary by age group.

The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and health care cost trend rates. Health care cost trend rates for Medicare advantaged prescription drug plans are 44% in 2025, 45% in 2026, 10% in 2027, 6.5% in 2028, then grading down to 4.5% in 2036 and beyond. Health care cost trend rates used for non-medicare advantaged prescription drug plans are 6.2% in 2025, 7.0% in 2026, then grading down to 4.5% in 2036 and beyond. Increases in health care trend rates for Medicare advantaged prescription drug plans in 2025 and 2026 are due to increases in premiums related to certain provisions in the Inflation Reduction Act.

The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan assets and liabilities.

FAIR VALUE OF PENSION PLAN ASSETS

Qualified defined benefit plan assets are monitored by the Company’s Pension and Retirement Trust and Investment Committee in its role as a fiduciary. The Investment Committee selects and employs various external professional investment management firms to manage specific investments across the spectrum of asset classes. The Investment Committee employs a liability driven investment approach that uses a diversified blend of investments (equity securities,


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fixed-income securities, and alternative investments) along a glide path to optimize the long-term return of plan assets relative to plan liabilities, at a prudent level of risk. Equity investments are diversified across U.S. and non-U.S. stocks, as well as differing styles and market capitalizations. Investment performance is measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.

The fair values of the Company’s pension plan assets by asset category as of December 31, 2025 and 2024 were as follows:


millions	Level 1		Level 2		Level 3		Total
December 31, 2025
Asset Class:

Government securities	$	36	$	—	$	—	$	36
Corporate bonds (a)	—		17		—		17
Equity securities (b)	30		—		—		30
Other	1		43		—		44
Investments measured at fair value	$	67	$	60	$	—	$	127
Investments measured at net asset value (c)	—		—		—		605
Total pension plan assets	$	67	$	60	$	—	$	732

December 31, 2024
Asset Class:

Government securities	$	33	$	—	$	—	$	33
Corporate bonds (a)	—		17		—		17
Equity securities (b)	31		—		—		31
Other	2		41		—		43
Investments measured at fair value	$	66	$	58	$	—	$	124
Investments measured at net asset value (c)	—		—		—		576
Total pension plan assets	$	66	$	58	$	—	$	700

(a)This category represents investment grade bonds of U.S. and non-U.S. issuers from diverse industries.

(b)This category represents direct investments in mutual funds and common and preferred stocks from diverse U.S. and non-U.S. industries.

(c)Certain investments measured at fair value using the NAV per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.

Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows for the years ended December 31:


millions	Pension Benefits			Postretirement Benefits
2026		$	68		$	52
2027		67			55
2028		62			54
2029		59			54
2030		58			53
2031 - 2035		268			264

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


96			OXY 2025 FORM 10-K


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NOTE 11 - ENVIRONMENTAL LIABILITIES AND EXPENDITURES

The Company is subject to numerous international, federal, state, and local, laws and regulations related to improving or maintaining environmental quality. The laws that require or address environmental remediation, including CERCLA and similar laws, may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. The Company participates in or actively monitors a range of remedial activities and government or private proceedings under these laws with respect to alleged past practices at Third-Party, Currently Operated, and Closed or Non-operated Sites, each of which may include NPL Sites. Remedial activities may include one or more of the following: investigation involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and maintenance of remedial systems. The environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, natural resource damages, punitive damages, civil penalties, injunctive relief and government oversight costs.

As discussed in Note 4 - Acquisitions, Divestitures and Other Transactions, certain Occidental subsidiaries remain responsible for environmental remediation at legacy sites and the indemnification of legacy environmental liabilities and pre-closing liabilities of OxyChem, which are not classified as held for sale. Expenses related to OxyChem and the retained liabilities and indemnification obligations associated with the chemical business are reported as discontinued operations for all periods presented, reflecting the OxyChem Transaction.

ENVIRONMENTAL REMEDIATION

As of December 31, 2025, the Company participated in or monitored remedial activities or proceedings at 152 sites. The following table presents the current and non-current environmental remediation liabilities of the Company separated by those related to ongoing operations and discontinued operations as of December 31, 2025 and 2024.



millions	as of December 31, 2025						as of December 31, 2024
	Ongoing Operations		Discontinued Operations		Total		Ongoing Operations		Discontinued Operations		Total
Current Portion:
Accrued Liabilities	$	55	$	96	$	151	$	55	$	95	$	150
Non-Current Portion:
Deferred credit and other liabilities	141		1,578		1,719		170		1,589		1,759
Total current and non-current	$	196	$	1,674	$	1,870	$	225	$	1,684	$	1,909

The estimates of environmental remediation liabilities in the table above vary over time depending on factors such as acquisitions or divestitures, identification of additional sites, remedy selection and implementation and changes in applicable laws or regulations, among other factors. Environmental remediation expenses primarily relate to existing conditions from alleged past practices.

Environmental remediation expenses related to ongoing operations were $18 million in 2025, $20 million in 2024 and $46 million in 2023. For discontinued operations, remediation expenses were $64 million in 2025, $56 million in 2024 and $33 million in 2023.

Based on current estimates, the Company expects to expend funds corresponding to approximately 30% of the year-end consolidated remediation balance over the next three to four years with the remainder over the subsequent 10 or more years.

Environmental remediation sites for ongoing operations and discontinued operations are grouped into NPL Sites and the following three categories of non-NPL Sites — Third-Party Sites, Currently Operated Sites and Closed or Non-operated Sites.


	2025			2024
millions, except number of sites	Number of Sites	Remediation Balance		Number of Sites	Remediation Balance
NPL Sites	29	$	1,379	32	$	1,374
Third-Party Sites	69	238		63	200
Currently Operated Sites	4	25		12	88
Closed or Non-operated Sites	50	228		51	247
Total	152	$	1,870	158	$	1,909


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As of December 31, 2025, environmental remediation liabilities exceeded $10 million each at 14 of the 152 sites described above, and 88 of the sites had liabilities less than $1 million each. Of the 152 sites above, 69 relate to ongoing operations with a combined remediation balance of approximately $196 million.

The DASS in Newark, New Jersey accounted for the majority of the liabilities associated with the category of NPL Sites.

Of the 69 Third-Party Sites, eight locations — a former copper mining and smelting operation in Tennessee, a chrome site in New Jersey, a former oil field and a landfill in California, active chemical plants in Kansas and Louisiana, a landfill in New York and an active refinery in Louisiana where the Company reimburses the current owner for certain remediation activities — accounted for approximately two thirds of the liabilities associated with this category.

Oil and gas operations in Colorado, which are collectively managed as one Currently Operated Site, accounted for approximately two thirds of the liabilities associated with this category.

Seven Closed or Non-operated Sites — a landfill in Western New York, a former refinery in Oklahoma, former chemical plants in California, New York, and Washington, and a closed coal mine in Pennsylvania — accounted for approximately two thirds of the liabilities associated with this category.

The Company believes its range of reasonably possible additional losses beyond those amounts currently recorded for environmental remediation for the 152 environmental sites in the table above could be up to $1.9 billion.

DIAMOND ALKALI SUPERFUND SITE

The EPA has organized the DASS into four OUs for evaluating, selecting and implementing remediation under CERCLA. The Company’s current activities in each OU are summarized below.

OU1 – The Former Diamond Alkali Plant at 80-120 Lister Avenue in Newark: Maxus and its affiliates implemented an interim remedy of OU1 pursuant to a 1990 Consent Decree, for which maintenance and monitoring are currently being performed. In January 2025, the EPA issued a ROD for the final remedy of OU1 that provides for optimized containment for which it estimated a cost of $16 million.

OU2 – The Lower 8.3 Miles of the Lower Passaic River: In March 2016, the EPA issued a ROD outlining the remedial actions required for OU2. During the third quarter of 2016, and following Maxus’s bankruptcy filing, the EPA issued an AOC for the design of the remedy selected in the ROD. In May 2024, the EPA approved the remedial design for OU2. In June 2024, the EPA confirmed that the work required by the AOC had been fully completed in accordance with its terms. The EPA has estimated the cost to remediate OU2 to be approximately $1.4 billion.

OU3 – Newark Bay Study Area, including Newark Bay and portions of the Hackensack River, Arthur Kill, and Kill van Kull: Maxus and its affiliates initiated a remedial investigation and feasibility study of OU3 pursuant to a 2004 AOC which was amended in 2010. The Company is currently performing feasibility study activities in OU3.

OU4 – The 17-mile Lower Passaic River Study Area, comprising OU2 and the Upper 9 Miles of the Lower Passaic River: In September 2021, the EPA issued a ROD selecting an interim remedy for the portion of OU4 that excludes OU2 and is located upstream from the Lister Avenue Plant site. In March 2023, the EPA issued a Unilateral Administrative Order directing the design of the EPA’s selected interim remedy for OU4. The EPA has estimated the cost to remediate OU4 to be approximately $440 million.

Natural Resource Trustees – In addition to the activities of the EPA and other parties involved in the OUs described above, federal and state natural resource trustees are assessing natural resources in the Lower Passaic River and Greater Newark Bay to evaluate potential claims for natural resource damages.

Legal matters related to the DASS (Alden Leeds)

In December 2022, the EPA and the DOJ filed a proposed Consent Decree in the Alden Leeds litigation, seeking court approval to settle with 85 parties for a total of $150 million for cleanup costs associated with OU2 and OU4. In January 2024, the DOJ filed a proposed Amended Consent Decree that excluded three companies from the original settlement, among other changes, and subsequently filed a motion to approve the Amended Consent Decree. In December 2024, the U.S. District Court for the District of New Jersey (District Court) approved the Amended Consent Decree. In its order approving the Amended Consent Decree, the District Court accepted the EPA’s revised determination that the Company was responsible for approximately 85% of the cleanup costs for OU2 and OU4. The Company filed an appeal against the District Court’s ruling on the grounds that the decision was flawed for several reasons, including the failure to consider the impact of recent Supreme Court decisions that restrict EPA authority and limit judicial deference to EPA actions. The Notice of Appeal was filed in February 2025, and all briefs have been filed as of January 2026.

As a result of the District Court’s approval of the Amended Consent Decree, the non-current environmental remediation liability related to OU2 and OU4 was increased by $925 million in the fourth quarter of 2024. This charge was included in asset impairments and other charges in the Consolidated Statements of Operations and represented the additional share of the total estimated remediation costs which may be incurred because of the assignment by the District Court of 85% of the responsibility for OU2 and OU4. These costs have not been discounted as the timing and amount of the payments are not fixed or reliably determinable. It is expected that the cash outlay for remediation costs will be expended over ten to twenty years, or more.

The Alden Leeds settlement does not address the liability of entities that were excluded from the settlement, including for OU2, OU3, OU4 or natural resource damages, or the liability of any settling party with respect to OU3 or natural resource damages.


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While the remedies for OU2 and OU4 are expected to take ten to twenty years to complete, the EPA may seek to require the Company to perform a substantial majority or all of the remediation work and provide additional financial assurance. It is uncertain when or to what extent the EPA may take action to compel further remediation in OU2 or OU4, or the amount of financial assurance that could be required.

In June 2018, the Company filed a complaint under CERCLA in the District Court against numerous potentially responsible parties seeking contribution and cost recovery of amounts incurred or to be incurred to comply with the AOC and the OU2 ROD, or to perform other remediation activities related to the DASS (2018 Contribution Action). Because costs are being incurred to implement the OU4 Unilateral Administrative Order, a cost recovery action under CERCLA was brought in March 2023 in the District Court against multiple parties (2023 Cost Recovery Action). Both the 2018 Contribution Action and the 2023 Cost Recovery Action were stayed pending the outcome of the Alden Leeds litigation. The Company does not know when the Court will lift the stay in those matters. If not reversed on appeal, the approved Amended Consent Decree could bar the Company from pursuing contribution against the settling parties for remediation costs incurred or that may be incurred in the future to design and implement the remedies in OU2 and OU4, including claims asserted in the 2018 Contribution Action.

Other information

For the DASS, a reserve has been accrued relating to the estimated allocable share of the costs to perform the maintenance and monitoring required in the OU1 Consent Decree, as well as the remedial investigation and feasibility study required in OU3 (Newark Bay). Subject to and without waiver of any rights, including appeal, a reserve has also been accrued for design and implementation of remedies selected in the OU2 ROD and AOC, and the OU4 ROD and OU4 Unilateral Administrative Order, based on the December 2024 Order of the District Court approving the Amended Consent Decree described above, which Order is currently being appealed.

The accrued environmental remediation reserve does not account for the possibility of additional remediation costs or natural resource damages for the DASS that are not considered reasonably estimable. The ultimate liability at the DASS may be greater or less than both the reserved amount and any reasonably possible additional losses, and will depend on final design plans, future actions by the EPA and natural resource trustees, as well as the resolution of the allocable share with other potentially responsible parties, among other factors.

The estimated costs currently recorded for remediation at the DASS and the range of reasonably possible additional losses beyond the amounts currently recognized are evaluated periodically. Due to the complexity and scope of the remediation efforts, the estimated costs may fluctuate over time as new information becomes available.


NOTE 12 - LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

LEGAL MATTERS

The Company is involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. The Company is also involved in proceedings under CERCLA and similar federal, regional, state, provincial, tribal, local and international environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, natural resource damages, punitive damages, civil penalties, injunctive relief and government oversight costs, as described in Note 11 - Env iro 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.


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TAX MATTERS AND OTHER DISPUTES

During the course of its operations, the Company is subject to audit by tax authorities for varying periods in various federal, state, local and international tax jurisdictions. Tax years through 2021 for U.S. federal income tax purposes have been audited by the IRS pursuant to its Compliance Assurance Program and subsequent taxable years are currently under review. Tax years through 2018 have been audited for state income tax purposes. There are no outstanding significant audit matters in international jurisdictions. During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law.

The IRS is currently reviewing the legal entity reorganization transaction as part of the Company’s 2022 federal tax audit. Following the acquisition of Anadarko and related divestitures, the Company reorganized its legal entities to better align with the nature of its business activities. This reorganization resulted in the Company making an adjustment to the tax basis in a portion of its operating assets, reducing deferred tax liabilities and recording a $2.7 billion tax benefit in 2022.

For Anadarko, its taxable years through 2014 and tax year 2016 for U.S. federal tax purposes have been audited and closed by the IRS. Tax years 2015 and 2017 through 2019 have been audited by the IRS but remain open pending the outcome of the Tronox U.S. Tax Court litigation discussed below. Tax years through 2018 have been audited for state income tax purposes. There are no outstanding significant audit matters in international jurisdictions. As stated above, during the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law.

Other than the dispute discussed below, the Company believes that the resolution of these outstanding tax disputes would not have a material adverse effect on its consolidated financial position or results of operations.

Anadarko received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox Adversary Proceeding settlement payment in 2015. In September 2018, Anadarko received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting Anadarko’s refund claim. Anadarko disagreed and, in November 2018, filed a petition with the U.S. Tax Court to dispute the disallowance. Trial was held in May 2023. The parties filed post-trial briefs throughout 2023 and 2024. Closing arguments were held in May 2024. The Tax Court may issue an opinion at any time. If the Tax Court opines that all or a portion of the original $5.2 billion deduction is not deductible, a computation phase will commence where the parties will compute the tax amount to be included in the Tax Court’s decision. Once the parties submit their computation, the Tax Court judge will formally enter the decision reflecting the computed tax amount. To pursue an appeal of the Tax Court’s decision, any tax due as a result of the Tax Court’s decision must be fully bonded or paid within 90 days of the decision’s entry. If Anadarko does not pursue an appeal, the IRS will assess any resulting tax deficiency, including interest, and issue a notice demanding payment thereof.

In accordance with ASC 740’s guidance on the accounting for uncertain tax positions, the Company has recorded no tax benefit on the tentative cash tax refund of $881 million. Additionally, the Company has recorded no tax benefit on approximately $500 million of additional cash tax benefits realized from the utilization of tax attributes generated as a result of the deduction of the $5.2 billion Tronox Adversary Proceeding settlement payment in 2015. If the payment is ultimately determined not to be deductible, the Company would be required to repay the tentative refund received, plus other cash benefits received related to the $5.2 billion deduction, plus interest, which as of December 31, 2025 totaled approximately $2.3 billion. As a result, should the Company not ultimately prevail on the issue, there would be no additional tax expense recorded relative to this position for financial statement purposes other than future interest. However, in that event, as of December 31, 2025, the Company would be required to repay approximately $1.4 billion in federal and state taxes and accrued interest of $0.9 billion. A liability for the taxes and interest is included in deferred credits and other liabilities - other.

INDEMNITIES TO THIRD PARTIES

The Company has indemnified various parties against specified liabilities those parties might incur in the future in connection with purchases and other transactions that they have entered into with the Company. These indemnities usually are contingent upon the other party incurring liabilities that reach specified thresholds. The Company reserves for indemnity claims when a payment for such claims is probable and estimable. As discussed in Note 4 - Acquisitions, Divestitures and Other Transactions, The Company is providing indemnification to Berkshire Hathaway for retained liabilities in the OxyChem Transaction.

PURCHASE OBLIGATIONS AND COMMITMENTS

The Company has entered into agreements providing for future payments, primarily to secure terminal, pipeline and processing capacity, CO2, drilling rigs and services, electrical power, non-lease components and steam. The Company has certain other commitments under contracts, guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent liabilities. The amounts that will be paid for such outstanding off-balance sheet purchase obligations as of December 31, 2025 are $3.0 billion in 2026, $4.7 billion in 2027 and 2028, $2.6 billion in 2029 and 2030, and $2.3 billion in 2031 and thereafter.


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NOTE 13 - STOCKHOLDERS’ EQUITY

The following table presents Occidental’s common share activity, including exercises of warrants, and other transactions in Occidental’s common stock in 2025:


Period	Exercise of Common Stock Warrants	(a)	Other	(b)	Common Stock Outstanding	(c)
December 31, 2024					938,457,983
First Quarter 2025	123,673		3,468,265		942,049,921
Second Quarter 2025	41,926,088		440,156		984,416,165
Third Quarter 2025	726,741		32,123		985,175,029
Fourth Quarter 2025	819,165		32,222		986,026,416
Total 2025	43,595,667		3,972,766		986,026,416

(a)$930 million of cash was received in 2025 from the exercise of common stock warrants.

(b)Consists of issuances under the 2015 long-term incentive plan, the OPC savings plan and the dividend reinvestment plan.

(c)As of December 31, 2025, the Company had 30.4 million of outstanding warrants with a strike price of $22 per share and 83.9 million of warrants with a strike price of $59.59 per share.

TREASURY STOCK

As of December 31, 2025, 2024 and 2023, treasury stock shares numbered 228.3 million, 228.3 million and 228.1 million, respectively.

PREFERRED STOCK

In 2019, Occidental issued 100,000 shares of Occidental series A preferred stock, with a face value of $100,000 per share and a liquidation preference of $105,000 per share plus unpaid accrued dividends to Berkshire Hathaway. Prior to August 2029, a mandatory redemption provision obligates Occidental to redeem preferred stock at a 10% premium to face value on a dollar-for-dollar basis for every dollar distributed to common shareholders (either via common stock dividends or share repurchases) above $4.00 per share, on a trailing 12-month basis. Preferred redemptions can settle between 30 and 60 days from the date Berkshire Hathaway is notified of the redemption obligation and accrued unpaid dividends are paid up to but not including the redemption date. Occidental cannot voluntarily redeem preferred stock before August 2029. After August 2029, Occidental can voluntarily redeem preferred stock at a 5% premium to face value.

Dividends on the preferred stock accrue on the face value at a rate per annum of 8%, but will be paid only when, as and if declared by the Company’s Board of Directors. At any time, when such dividends have not been paid in full, the unpaid amounts will accrue dividends, compounded quarterly, at a rate per annum of 9%. Following the payment in full of any accrued but unpaid dividends, the dividend rate will remain at 9% per annum. If preferred dividends are not paid in full, Occidental is prohibited from paying dividends on common stock. Occidental paid $679 million in preferred stock dividends in 2025.

Occidental did not redeem preferred stock in 2025. To the extent Occidental’s trailing 12-month distributions to common shareholders is above $4.00 per share, Occidental is required to match any common shareholder distributions with preferred stock redemptions. As of the date of this filing, approximately $8.5 billion face value of the preferred stock remains outstanding.

BERKSHIRE WARRANT

In connection with the preferred stock issuance, Occidental also issued the Berkshire Warrant. The Berkshire Warrant is exercisable at the holder’s option, in whole or in part, until the first anniversary of the date on which no shares of preferred stock remain outstanding, at which time the Berkshire Warrant expires. The holder of the Berkshire Warrant and the preferred stock may redeem the preferred stock as payment for the exercise price of the Warrant in lieu of cash payment upon exercise. As of December 31, 2025, the Berkshire Warrant would result in the issuance of 83.9 million shares of Occidental common stock, if exercised in full for its current strike price of $59.59 per share of Occidental common stock.

COMMON STOCK WARRANTS

Occidental issued approximately 116 million Common Stock Warrants on August 3, 2020 to holders of record of outstanding shares of Occidental’s common stock as of the close of business on July 6, 2020. The Common Stock Warrants have an exercise price of $22.00 per share and will expire on August 3, 2027. As of December 31, 2025, Occidental had 30.4 million outstanding warrants.


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EARNINGS PER SHARE

Occidental’s instruments containing rights to nonforfeitable dividends granted in stock-based awards are considered participating securities prior to vesting and, therefore, have been deducted from earnings in computing basic and diluted EPS under the two-class method.

Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the weighted-average number of common shares outstanding during each period, including vested but unissued shares and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options, warrants and unvested stock awards.

The following table presents the calculation of basic and diluted EPS for the years ended December 31:


millions except per share amounts	2025		2024		2023
Income from continuing operations	$	2,107	$	2,866	$	3,332
Income from discontinued operations, net of tax	262		212		1,364
Net income	$	2,369	$	3,078	$	4,696
Less: Net income attributable to noncontrolling interest	(43)		(22)		—
Less: Preferred stock dividends	(679)		(679)		(923)
Net income attributable to common stock	$	1,647	$	2,377	$	3,773
Less: Incremental fair value for warrants inducement	(25)		—		—
Less: Net income allocated to participating securities	(10)		(13)		(23)
Net income, net of participating securities	$	1,612	$	2,364	$	3,750
Weighted-average number of basic shares	975.5		911.8		889.2
Basic earnings per common share	$	1.65	$	2.59	$	4.22

Net income attributable to common stock	$	1,647	$	2,377	$	3,773
Less: Incremental fair value for warrants inducement	(25)		—		—
Less: Net income allocated to participating securities	(10)		(13)		(21)
Net income, net of participating securities	$	1,612	$	2,364	$	3,752
Weighted-average number of basic shares	975.5		911.8		889.2
Dilutive securities	24.6		55.3		71.7
Total diluted weighted-average common shares	1,000.1		967.1		960.9
Diluted earnings per common share	$	1.61	$	2.44	$	3.90

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

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Accumulated OCI (loss) consisted of the following after-tax amounts as of December 31, 2025 and 2024:


millions	2025		2024
Foreign currency translation adjustments	$	(6)	$	(6)
Derivatives	—		15
Pension and postretirement adjustments (a)	208		170
Total	$	202	$	179

(a)See Note 1 0 - Retirement and Postretirement Benefit Plans for further information.


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NOTE 14 - STOCK-BASED INCENTIVE PLANS

Occidental issues stock-based awards to employees in accordance with the terms of the Plans. An aggregate of 188 million shares of Occidental common stock were authorized for issuance and approximately 14.4 million shares had been reserved for issuance for employee awards through December 31, 2025. As of December 31, 2025, approximately 68.8 million shares were available for grants of future awards. The 2015 Long-Term Incentive Plan requires each share covered by an award (other than options) to be counted as if three shares were issued in determining the number of shares that are available for future awards. Accordingly, the number of shares available for future awards may be less than 68.8 million depending on the type of award granted, and shares available for future awards may increase by the number of shares that are forfeited, canceled, or correspond to the portion of any stock-based awards settled in cash, including awards that were issued under a previous plan that remain outstanding. Current outstanding awards include RSUs, stock options, CROCEI awards and TSRI awards.

During 2025, non-employee directors were granted awards for 60,040 shares of common stock. Compensation expense for these awards was measured using the closing quoted market price of Occidental’s common stock on the grant date and was fully recognized at that time.

The Company incurred expenses of $234 million, $213 million and $203 million related to stock-based incentive plans in the years ended December 31, 2025, 2024 and 2023, respectively. The income tax benefit associated with this expense was $49 million, $45 million and $43 million in the years ended December 31, 2025, 2024 and 2023, respectively.

As of December 31, 2025, unrecognized compensation expense for all unvested stock-based incentive awards was $319 million. This expense is expected to be recognized over a weighted-average period of 1.8 years. The Company accounts for forfeitures as they occur.

RESTRICTED STOCK UNITS

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs may be settled in stock or may be cash settled liabilities. These awards vest from one to three years following the grant date. For certain RSUs, dividend equivalents are paid during the vesting period.

CASH-SETTLED RSU LIABILITY AWARDS

The weighted-average, grant-date fair values of cash-settled RSUs granted in 2025, 2024 and 2023 were $46.44, $58.87 and $60.43 per share, respectively. Cash-settled RSUs resulted in payments of $8 million, $8 million and $9 million, during the years ended December 31, 2025, 2024 and 2023, respectively.

STOCK-SETTLED RSU EQUITY AWARDS

The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2025, 2024 and 2023 were $48.85, $61.34 and $59.85, respectively. The fair value of RSUs settled in shares during the years ended December 31, 2025, 2024 and 2023 was $171 million, $240 million and $254 million, respectively.

A summary of changes in the Company’s unvested cash- and stock-settled RSUs for 2025 is presented below:


	Cash-Settled			Stock-Settled
thousands, except fair values	RSUs			RSUs
Unvested as of January 1	398	$	58.00	7,119	$	57.63
Granted	255	$	46.44	4,891	$	48.85
Vested	(170)	$	56.47	(3,551)	$	54.56
Forfeitures	(45)	$	55.30	(327)	$	53.44
Unvested as of December 31	438	$	52.15	8,132	$	53.86

TOTAL SHAREHOLDER RETURN INCENTIVE AWARDS

Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date. Payout is based upon the Company’s absolute total shareholder return and performance relative to its peers. TSRIs have payouts that range from 0% to 200% of the target award and settle in stock once certified. Dividend equivalents for TSRIs are accumulated and paid upon certification of the award. The fair value of TSRIs settled in shares during the years ended December 31, 2025, 2024 and 2023 was $33 million, $68 million and $45 million, respectively.


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The fair values of TSRIs are initially determined on the grant date using a Monte Carlo simulation model based on the Company’s assumptions, noted in the following table, and the volatility from corresponding peer group companies. The expected life is based on the Term. The risk-free interest rate is the implied yield available on zero coupon Treasury notes at the time of grant with a remaining term equal to the Term. The dividend yield is the expected annual dividend yield over the Term, expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by the employees who receive the awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by the Company.

The grant-date assumptions used in the Monte Carlo simulation models for the estimated payout level of TSRIs were as follows:


	TSRIs
	2025		2024		2023
Assumptions used:
Risk-free interest rate	4.0%		4.3%		4.6%
Volatility factor	32%		45%		64%
Expected life, years	2.83		2.83		2.84
Grant-date fair value of underlying Occidental common stock	$	48.84	$	61.36	$	59.71

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


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

(a)Presented at the target payouts. In 2025, the weighted-average payout at vesting was 176% of the target, resulting in the issuance of approximately 683,358 shares of Occidental common stock.

STOCK OPTIONS

Certain employees are granted options that vest over three years, expire on the tenth anniversary of the grant date, and settle in stock. Exercise prices of the options were equal to the quoted market value of Occidental’s stock on the grant date. There were no options granted in 2025.

A summary of the Company’s outstanding stock options as of December 31, 2025 and changes during the year ended December 31, 2025 is presented below:


	Vested			Unvested
thousands, except fair values	Options	Weighted Average Strike Price		Options	Weighted Average Strike Price
January 1	2,305	$	37.89	83	$	42.98

Vested	83	$	42.98	(83)	$	42.98


December 31	2,388	$	38.07	—	$	—

There were no options exercised during the years ended December 31, 2025 and 2024. The intrinsic value of options exercised during the year ended December 31, 2023 was $9 million. As of December 31, 2025, the weighted average remaining life of fully vested options was 4.5 years.

CASH RETURN ON CAPITAL EMPLOYED INCENTIVE AWARDS

Certain executives are awarded CROCEI awards that vest at the end of a three-year period if performance targets based on CROCE are met. These awards are settled in stock upon certification of the performance target, with payouts that range from 0% to 200% of the target award. Dividend equivalents are accumulated and paid upon certification of the award.


104			OXY 2025 FORM 10-K


			table of contents			FINANCIAL STATEMENTS FOOTNOTES

The value of shares that vested in 2025, 2024 and 2023 were $15 million, $25 million and $25 million, respectively. A summary of changes in the Company’s unvested CROCEI in 2025 is presented below:


	CROCEI
thousands, except fair values	Awards	Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested as of January 1	447		$	54.55
Granted	391		$	48.84
Vested (a)	(156)		$	42.98
Forfeited	(3)		48.84
Unvested as of December 31	679		$	53.94

(a) Presented at the target payouts. In 2025, the weighted-average payout at vesting was 200% of the target, resulting in the issuance of approximately 312,000 shares of Occidental common stock.


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES


NOTE 15 - INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

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

In October 2025, the Company announced entry into a purchase and sale agreement with Berkshire Hathaway to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion. The sale was completed on January 2, 2026, with final proceeds subject to post-closing adjustments. The Company reassessed its operating segments. Accordingly, the chemical segment results are presented separately as discontinued operations and corporate costs directly attributable to the chemical segment are included under discontinued operations. See Note 4 - Acquisitions, Divestitures and Other Transactions for related disclosure.

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

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

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


	Years Ended December 31,
millions	2025		2024		2023
Segment income from continuing operations before taxes
Oil and gas segment	$	4,586	$	5,214	$	6,240
Midstream and marketing segment	252		563		(35)
Corporate and eliminations	(631)		(584)		(586)
Interest and debt expense, net	(1,079)		(1,169)		(957)






Income from continuing operations before income taxes	$	3,128	$	4,024	$	4,662
Income tax expense	(1,021)		(1,158)		(1,330)
Income from continuing operations	$	2,107	$	2,866	$	3,332
Discontinued operations, net of tax	262		212		1,364
Net income	$	2,369	$	3,078	$	4,696
Less: Net income attributable to noncontrolling interest	(43)		(22)		—
Less: Preferred stock dividends and redemption premiums	(679)		(679)		(923)
Net income attributable to common stockholders	$	1,647	$	2,377	$	3,773

The following tables include a summary of significant revenue and expense line items for each segment. Items within “Significant segment expenses” align with the significant segment-level information that is regularly provided to the CODM as required by the adoption of ASU 2023-07 in the fourth quarter of 2024. Intersegment expenses are included within the amounts shown.


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES

OIL AND GAS SEGMENT

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


	Years Ended December 31,
millions	2025		2024		2023
Revenues and other income
Net sales	$	20,902	$	21,705	$	21,284
Gains (losses) on sale of assets and other income	(70)		(551)		192

Total	$	20,832	$	21,154	$	21,476

Significant segment expenses
Oil and gas lease operating expense	4,681		4,738		4,677
Transportation and gathering expense	1,629		1,583		1,427



Other operating and non-operating expense	1,161		997		889
Taxes other than on income	1,009		1,026		1,076
Depreciation, depletion and amortization	7,115		6,565		6,112

Other segment expenses	633		993		1,031


Total	$	16,228	$	15,902	$	15,212
Segment income before other items	$	4,604	$	5,252	$	6,264


Losses from equity investments and other	(18)		(38)		(24)
Segment income from continuing operations before taxes	$	4,586	$	5,214	$	6,240

MIDSTREAM AND MARKETING SEGMENT

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


	Years Ended December 31,
millions	2025		2024		2023
Revenues and other income
Net sales	$	1,279	$	886	$	2,433
Gains on sale of assets and other income	500		628		494

Total	$	1,779	$	1,514	$	2,927

Significant segment expenses



Purchased commodities and midstream cost of sales	800		1,035		2,749

Other operating and non-operating expense	359		289		234

Depreciation, depletion and amortization	294		273		266

Other segment expenses	168		151		163


Total	$	1,621	$	1,748	$	3,412
Segment income (losses) before other items	$	158	$	(234)	$	(485)


Income from equity investments and other	94		797		450
Segment income (losses) from continuing operations before taxes	$	252	$	563	$	(35)


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			table of contents			FINANCIAL STATEMENTS FOOTNOTES

SEGMENT INVESTMENTS AND EXPENDITURES

The following table includes segment-level balance sheet information:


millions	Oil and gas		Midstream and marketing		Corporate and eliminations		Assets held for sale		Total
Year ended December 31, 2025
PP&E Additions	$	5,703	$	806	$	98	$	—	$	6,607
Investments in unconsolidated entities	$	129	$	2,346	$	—	$	—	$	2,475

Total Assets	$	60,393	$	13,901	$	3,372	$	6,520	$	84,186


Year ended December 31, 2024
PP&E Additions	$	5,408	$	930	$	82	$	—	$	6,420
Investments in unconsolidated entities	$	94	$	2,552	$	—	$	—	$	2,646

Total Assets	$	63,596	$	13,177	$	3,102	$	5,570	$	85,445

GEOGRAPHIC AREAS

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


millions	2025		2024		2023
United States	$	57,038	$	59,158	$	48,677
International
UAE	3,375		3,495		3,609
Oman	2,238		2,187		2,156
Algeria	626		618		624

Qatar	326		361		393
Other International	40		44		35
Total International	6,605		6,705		6,817
Total	$	63,643	$	65,863	$	55,494


108			OXY 2025 FORM 10-K


			table of contents			Supplemental Quarterly Financial Data (Unaudited)


Supplemental Quarterly Financial Data (Unaudited)			Occidental Petroleum Corporation and Subsidiaries


millions except per-share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2025
Segment net sales
Oil and gas	$	5,683	$	5,009	$	5,404	$	4,806
Midstream and marketing	173		390		265		451
Eliminations	(152)		(141)		(150)		(145)
Net sales	$	5,704	$	5,258	$	5,519	$	5,112
Segment earnings
Oil and gas	$	1,697	$	934	$	1,300	$	655
Midstream and marketing	(72)		39		81		204
Total segment earnings	$	1,625	$	973	$	1,381	$	859
Unallocated corporate items
Interest expense, net	(310)		(271)		(266)		(232)
Income tax benefit	(347)		(222)		(279)		(173)
Other	(138)		(142)		(130)		(221)
Income from continuing operations	$	830	$	338	$	706	$	233
Discontinued operations, net of taxes	115		130		136		(119)
Net Income	$	945	$	468	$	842	$	114
Less: Net income attributable to noncontrolling interests	(9)		(10)		(12)		(12)
Less: Preferred stock dividend	(170)		(170)		(169)		(170)
Net income (loss) attributable to common stockholders	$	766	$	288	$	661	$	(68)
Basic income (loss) per common share	$	0.81	$	0.27	$	0.67	$	(0.07)
Diluted income (loss) per common share	$	0.77	$	0.26	$	0.65	$	(0.07)
Dividends per common share	$	0.24	$	0.24	$	0.24	$	0.24

2024
Segment net sales
Oil and gas	$	4,915	$	5,469	$	5,697	$	5,624
Midstream and marketing	78		257		399		152
Eliminations	(146)		(146)		(141)		(139)
Net sales	$	4,847	$	5,580	$	5,955	$	5,637
Segment earnings
Oil and gas	$	1,238	$	1,639	$	1,165	$	1,172
Midstream and marketing	(38)		110		614		(123)
Total segment earnings	$	1,200	$	1,749	$	1,779	$	1,049
Unallocated corporate items
Interest expense, net	(290)		(258)		(305)		(316)
Income tax expense	(248)		(402)		(391)		(117)
Other	(155)		(143)		(183)		(103)
Income from continuing operations	$	507	$	946	$	900	$	513
Discontinued operations, net of taxes	381		224		240		(633)
Net Income (loss)	$	888	$	1,170	$	1,140	$	(120)
Less: Net income attributable to noncontrolling interests	—		(8)		(7)		(7)
Less: Preferred stock dividend	(170)		(170)		(169)		(170)
Net income (loss) attributable to common stockholders	$	718	$	992	$	964	$	(297)
Basic earnings (loss) per common share	$	0.81	$	1.10	$	1.03	$	(0.32)
Diluted earnings (loss) per common share	$	0.75	$	1.03	$	0.98	$	(0.30)
Dividends per common share	$	0.22	$	0.22	$	0.22	$	0.22


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			table of contents			Supplemental Oil and Gas Information (Unaudited)

Supplemental Oil and Gas Information

OIL AND GAS RESERVES

The following tables set forth the Company’s net interests in quantities of proved developed and undeveloped reserves of oil, NGL and natural gas and changes in such quantities. Proved oil, NGL and natural gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGL and natural gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs. The following table shows the pricing used in the reserve analysis for the periods presented:


	2025		2024		2023
Average WTI Oil ($/Bbl)	$	65.34	$	75.48	$	78.22
Average Brent Oil ($/Bbl)	$	68.42	$	79.65	$	82.80
Average Henry Hub Natural Gas ($/MMbtu)	$	3.39	$	2.13	$	2.64
Average Mt. Belvieu NGL ($/Bbl)	$	31.79	$	33.04	$	29.94

Reserves are stated net of applicable royalties. Estimated reserves include the Company’s economic interests under PSCs and other similar economic arrangements. In addition, discussions of oil and gas production or volumes, in general, refer to sales volumes unless the context requires or it is indicated otherwise.

Prices for oil, NGL and natural gas fluctuate widely. Historically, the markets for oil, NGL and natural gas and refined products have been volatile and may continue to be volatile in the future. Prolonged declines in oil, NGL and natural gas prices would reduce the Company’s operating results and cash flows and could impact its future rate of growth and the recoverability of the carrying value of its assets.


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			table of contents			Supplemental Oil and Gas Information (Unaudited)

OIL RESERVES


MMbbl	United States	International	Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance as of December 31, 2022	1,639	274	1,913
Revisions of previous estimates	77	91	168
Improved recovery	7	11	18
Extensions and discoveries	59	3	62
Purchases of proved reserves	14	—	14
Sales of proved reserves	(1)	—	(1)
Production	(195)	(39)	(234)
Balance as of December 31, 2023	1,600	340	1,940
Revisions of previous estimates	47	(7)	40
Improved recovery	38	6	44
Extensions and discoveries	132	2	134
Purchases of proved reserves	254	—	254
Sales of proved reserves	(30)	—	(30)
Production	(209)	(38)	(247)
Balance as of December 31, 2024	1,832	303	2,135
Revisions of previous estimates(a)	36	69	105
Improved recovery	49	6	55
Extensions and discoveries	149	—	149
Purchases of proved reserves	4	—	4
Sales of proved reserves	(20)	—	(20)
Production	(226)	(40)	(266)
Balance as of December 31, 2025	1,824	338	2,162

PROVED DEVELOPED RESERVES
December 31, 2022	1,208	200	1,408
December 31, 2023	1,140	258	1,398
December 31, 2024	1,243	249	1,492
December 31, 2025	1,258	279	1,537
PROVED UNDEVELOPED RESERVES
December 31, 2022	431	74	505
December 31, 2023	460	82	542
December 31, 2024	589	54	643
December 31, 2025	566	59	625

(a)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 53 MMbbl were related to additions associated with infill development projects, mainly in the Permian Basin (28 MMbbl) and the DJ Basin (16 MMbbl). Further positive revisions were associated with changes in economic conditions (73 MMbbl), primarily in the Permian Basin (70 MMbbl), and the Oman contract extension (61 MMbbl). The positive revisions were partially offset by negative price revisions of 57 MMbbl primarily associated with the Permian Basin (61 MMbbl), which were partially offset by positive price revisions of 5 MMbbl on international PSCs. Further negative revisions were associated with updates based on reservoir performance (19 MMbbl) primarily related to the Permian Basin (57 MMbbl), which were partially offset by positive reservoir performance updates in the DJ Basin (18 MMbbl) and GOA (17 MMbbl).


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			table of contents			Supplemental Oil and Gas Information (Unaudited)

NGL RESERVES


MMbbl	United States	International	Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance as of December 31, 2022	654	192	846
Revisions of previous estimates	183	2	185
Improved recovery	2	—	2
Extensions and discoveries	45	—	45
Purchases of proved reserves	9	—	9
Sales of proved reserves	(1)	—	(1)
Production	(90)	(13)	(103)
Balance as of December 31, 2023	802	181	983
Revisions of previous estimates	68	9	77
Improved recovery	2	—	2
Extensions and discoveries	100	—	100
Purchases of proved reserves	200	—	200
Sales of proved reserves	(10)	—	(10)
Production	(102)	(14)	(116)
Balance as of December 31, 2024	1,060	176	1,236
Revisions of previous estimates(a)	(53)	(2)	(55)
Improved recovery	3	—	3
Extensions and discoveries	100	—	100
Purchases of proved reserves	3	—	3
Sales of proved reserves	(18)	—	(18)
Production	(105)	(14)	(119)
Balance as of December 31, 2025	990	160	1,150

PROVED DEVELOPED RESERVES
December 31, 2022	444	120	564
December 31, 2023	515	124	639
December 31, 2024	709	130	839
December 31, 2025	698	119	817
PROVED UNDEVELOPED RESERVES
December 31, 2021	210	72	282
December 31, 2023	287	57	344
December 31, 2024	351	46	397
December 31, 2025	292	41	333

(a)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 28 MMbbl were related to additions associated with infill development projects, mainly in the Permian Basin (14 MMbbl) and the DJ Basin (13 MMbbl). Further positive revisions were associated with changes in economic conditions (34 MMbbl), primarily in the Permian Basin (30 MMbbl). The positive revisions were partially offset by negative revisions associated with updates based on reservoir performance (93 MMbbl) primarily related to the DJ Basin (78 MMbbl). Further negative revisions were associated with negative price revisions of 19 MMbbl primarily associated with the Permian Basin (21 MMbbl), which were partially offset by positive price revisions of 2 MMbbl in the DJ Basin, and negative revisions related to management changes in development plans (7 MMbbl).


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			table of contents			Supplemental Oil and Gas Information (Unaudited)

NATURAL GAS RESERVES


Bcf	United States	International	Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance as of December 31, 2022	4,073	2,277	6,350
Revisions of previous estimates	325	(6)	319
Improved recovery	1	17	18
Extensions and discoveries	268	5	273
Purchases of proved reserves	50	—	50
Sales of proved reserves	(2)	—	(2)
Production	(480)	(176)	(656)
Balance as of December 31, 2023	4,235	2,117	6,352
Revisions of previous estimates	215	100	315
Improved recovery	2	6	8
Extensions and discoveries	532	17	549
Purchases of proved reserves	1,016	—	1,016
Sales of proved reserves	(58)	—	(58)
Production	(548)	(191)	(739)
Balance as of December 31, 2024	5,394	2,049	7,443
Revisions of previous estimates(a)	636	32	668
Improved recovery	6	8	14
Extensions and discoveries	543	—	543
Purchases of proved reserves	19	—	19
Sales of proved reserves	(113)	—	(113)
Production	(643)	(186)	(829)
Balance as of December 31, 2025	5,842	1,903	7,745

PROVED DEVELOPED RESERVES
December 31, 2022	2,761	1,597	4,358
December 31, 2023	2,770	1,507	4,277
December 31, 2024	3,564	1,593	5,157
December 31, 2025	4,168	1,469	5,637
PROVED UNDEVELOPED RESERVES
December 31, 2022	1,312	680	1,992
December 31, 2023	1,465	610	2,075
December 31, 2024	1,830	456	2,286
December 31, 2025	1,674	434	2,108

(a)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 205 Bcf were related to additions associated with infill development projects, mainly in the DJ Basin (118 Bcf) and the Permian Basin (72 Bcf). Further positive revisions were associated with updates based on reservoir performance (401 Bcf), primarily due to positive performance revisions in the DJ Basin (337 Bcf) and international assets (34 Bcf), and with changes in economic conditions (147 Bcf), primarily in the Permian Basin (134 Bcf). The positive revisions were partially offset by negative price revisions of 56 Bcf primarily associated with the Permian Basin (72 Bcf), which were partially offset by positive price revisions of 11 Bcf in the DJ Basin and 6 Bcf on international PSCs.


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			table of contents			Supplemental Oil and Gas Information (Unaudited)

TOTAL RESERVES


MMboe (a)	United States	International	Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance as of December 31, 2022	2,972	845	3,817
Revisions of previous estimates	314	92	406
Improved recovery	9	14	23
Extensions and discoveries	149	4	153
Purchases of proved reserves	31	—	31
Sales of proved reserves	(2)	—	(2)
Production	(365)	(81)	(446)
Balance as of December 31, 2023	3,108	874	3,982
Revisions of previous estimates	151	19	170
Improved recovery	40	7	47
Extensions and discoveries	321	5	326
Purchases of proved reserves	623	—	623
Sales of proved reserves	(50)	—	(50)
Production	(402)	(84)	(486)
Balance as of December 31, 2024	3,791	821	4,612
Revisions of previous estimates(b)	89	72	161
Improved recovery	53	7	60
Extensions and discoveries	340	—	340
Purchases of proved reserves	10	—	10
Sales of proved reserves	(57)	—	(57)
Production	(438)	(85)	(523)
Balance as of December 31, 2025	3,788	815	4,603

PROVED DEVELOPED RESERVES
December 31, 2022	2,112	586	2,698
December 31, 2023	2,117	633	2,750
December 31, 2024	2,546	645	3,191
December 31, 2025	2,651	643	3,294
PROVED UNDEVELOPED RESERVES
December 31, 2022	860	259	1,119
December 31, 2023	991	241	1,232
December 31, 2024	1,245	176	1,421
December 31, 2025	1,137	172	1,309

(a)Natural gas volumes have been converted to Boe based on an energy content of six Mcf of gas to one barrel of oil. Conversion to Boe does not necessarily result in price equivalency.

(b)Revisions of previous estimates in 2025 included the effects of new infill drilling, price revisions and other updates, including changes in reservoir performance, economic conditions, and development plans. Positive revisions of 115 MMboe were related to additions associated with infill development projects, mainly in the Permian Basin (54 MMboe) and the DJ Basin (49 MMboe). Further positive revisions were associated with changes in economic conditions of 131 MMboe, primarily in the Permian Basin (122 MMboe), and the Oman contract extension (61 MMboe). The positive revisions were partially offset by negative price revisions of 85 MMboe primarily associated with the Permian Basin (94 MMboe), which were partially offset by positive price revisions of 7 MMboe on international PSCs. Further negative revisions were associated with updates based on reservoir performance (45 MMboe) primarily related to the Permian Basin (66 MMboe), which were partially offset by positive reservoir performance updates in GOA (19 MMboe).


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CAPITALIZED COSTS

Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows:


millions	United States		International		Total
December 31, 2025
Proved properties	$	98,402	$	17,606	$	116,008
Unproved properties	10,713		176		10,889
Total capitalized costs (a)	109,115		17,782		126,897
Proved properties depreciation, depletion and amortization	(53,137)		(13,938)		(67,075)
Unproved properties valuation	(3,217)		—		(3,217)
Total Accumulated depreciation, depletion and amortization	(56,354)		(13,938)		(70,292)
Net capitalized costs	$	52,761	$	3,844	$	56,605

December 31, 2024
Proved properties	$	91,017	$	17,072	$	108,089
Unproved properties	13,626		159		13,785
Total capitalized costs (a)	104,643		17,231		121,874
Proved properties depreciation, depletion and amortization	(45,268)		(13,437)		(58,705)
Unproved properties valuation	(3,598)		—		(3,598)
Total Accumulated depreciation, depletion and amortization	(48,866)		(13,437)		(62,303)
Net capitalized costs	$	55,777	$	3,794	$	59,571

December 31, 2023
Proved properties	$	78,188	$	16,582	$	94,770
Unproved properties	14,298		146		14,444
Total capitalized costs (a)	92,486		16,728		109,214
Proved properties depreciation, depletion and amortization	(42,102)		(12,940)		(55,042)
Unproved properties valuation	(4,233)		—		(4,233)
Total Accumulated depreciation, depletion and amortization	(46,335)		(12,940)		(59,275)
Net capitalized costs	$	46,151	$	3,788	$	49,939

(a)Included acquisition costs, development costs, capitalized interest and AROs.


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COSTS INCURRED

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, were as follows:


millions	United States		International		Total
For the year ended December 31, 2025
Property acquisition costs (a)
Proved properties	$	205	$	—	$	205
Unproved properties	237		1		238
Exploration costs	399		149		548
Development costs	5,074		512		5,586
Costs incurred	$	5,915	$	662	$	6,577
For the year ended December 31, 2024
Property acquisition costs (a)
Proved properties	$	8,963	$	8	$	8,971
Unproved properties	3,178		—		3,178
Exploration costs	544		180		724
Development costs	4,584		500		5,084
Costs incurred	$	17,269	$	688	$	17,957
For the year ended December 31, 2023
Property acquisition costs (a)
Proved properties	$	112	$	288	$	400
Unproved properties	143		—		143
Exploration costs	743		150		893
Development costs	3,957		543		4,500
Costs incurred	$	4,955	$	981	$	5,936

(a)Included approximately $290 million, $30 million and $120 million in property acquisition costs related to non-monetary exchange transactions for the years ended December 31, 2025, 2024 and 2023, respectively.


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RESULTS OF OPERATIONS

The Company’s oil and gas producing activities for continuing operations, which exclude items such as asset divestitures, corporate overhead and interest, were as follows:


millions	United States		International		Total
FOR THE YEAR ENDED DECEMBER 31, 2025
Revenues	$	17,460	$	3,423	$	20,883
Lease operating costs	3,665		1,016		4,681
Transportation costs	1,569		60		1,629
Other operating expenses	1,308		201		1,509
Depreciation, depletion and amortization	6,599		516		7,115
Taxes other than on income	991		18		1,009
Exploration expenses	137		111		248
Pretax income before impairments and other charges	3,191		1,501		4,692
Asset impairments and other charges	6		—		6
Pretax income	3,185		1,501		4,686
Income tax expense (a)	746		614		1,360
Results of operations	$	2,439	$	887	$	3,326
FOR THE YEAR ENDED DECEMBER 31, 2024
Revenues	$	17,974	$	3,693	$	21,667
Lease operating costs	3,680		1,058		4,738
Transportation costs	1,522		61		1,583
Other operating expenses	1,088		268		1,356
Depreciation, depletion and amortization	6,049		516		6,565
Taxes other than on income	1,004		22		1,026
Exploration expenses	119		156		275
Pretax income before impairments and other charges	4,512		1,612		6,124
Asset impairments and other charges	334		—		334
Pretax income	4,178		1,612		5,790
Income tax expense (a)	885		599		1,484
Results of operations	$	3,293	$	1,013	$	4,306
FOR THE YEAR ENDED DECEMBER 31, 2023
Revenues	$	17,494	$	3,766	$	21,260
Lease operating costs	3,669		1,008		4,677
Transportation costs	1,367		60		1,427
Other operating expenses	1,058		194		1,252
Depreciation, depletion and amortization	5,559		553		6,112
Taxes other than on income	959		117		1,076
Exploration expenses	323		118		441
Pretax income before impairments and other charges	4,559		1,716		6,275
Asset impairments and other charges	209		—		209
Pretax income	4,350		1,716		6,066
Income tax expense (a)	933		746		1,679
Results of operations	$	3,417	$	970	$	4,387

(a)U.S. federal income taxes reflect certain expenses related to oil and gas activities allocated for U.S. income tax purposes. These amounts are computed using the statutory rate in effect during the period.


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RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS


$/Boe (a)	United States		International		Total
FOR THE YEAR ENDED DECEMBER 31, 2025
Revenues (b)	$	39.80	$	40.33	$	39.89
Lease operating costs	8.35		11.97		8.94
Transportation costs	3.58		0.71		3.11
Other operating expenses	2.98		2.37		2.88
Depreciation, depletion and amortization	15.05		6.07		13.59
Taxes other than on income	2.26		0.21		1.93
Exploration expenses	0.31		1.31		0.47
Pretax income before impairments and other charges	7.27		17.69		8.97
Asset impairments and other charges	0.01		—		0.01
Pretax income	7.26		17.69		8.96
Income tax expense (c)	1.70		7.24		2.60
Results of operations	$	5.56	$	10.45	$	6.36
FOR THE YEAR ENDED DECEMBER 31, 2024
Revenues (b)	$	44.68	$	44.11	$	44.59
Lease operating costs	9.15		12.64		9.75
Transportation costs	3.78		0.73		3.26
Other operating expenses	2.70		3.20		2.79
Depreciation, depletion and amortization	15.04		6.16		13.51
Taxes other than on income	2.50		0.26		2.11
Exploration expenses	0.30		1.87		0.57
Pretax income before impairments and other charges	11.21		19.25		12.60
Asset impairments and other charges	0.83		—		0.69
Pretax income	10.38		19.25		11.91
Income tax expense (c)	2.20		7.15		3.05
Results of operations	$	8.18	$	12.10	$	8.86
FOR THE YEAR ENDED DECEMBER 31, 2023
Revenues (b)	$	47.91	$	46.49	$	47.66
Lease operating costs	10.05		12.45		10.48
Transportation costs	3.74		0.74		3.20
Other operating expenses	2.90		2.39		2.81
Depreciation, depletion and amortization	15.22		6.83		13.70
Taxes other than on income	2.63		1.44		2.41
Exploration expenses	0.88		1.47		0.99
Pretax income before impairments and other charges	12.49		21.17		14.07
Asset impairments and other charges	0.57		—		0.47
Pretax income	11.92		21.17		13.60
Income tax expense (c)	2.56		9.21		3.76
Results of operations	$	9.36	$	11.96	$	9.84

(a)Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil.

(b)Revenues are net of royalty payments.

(c)U.S. federal income taxes reflect certain expenses related to oil and gas activities allocated for U.S. income tax purposes. These amounts are computed using the statutory rate in effect during the period.


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STANDARDIZED MEASURE, INCLUDING YEAR-TO-YEAR CHANGES THEREIN, OF DISCOUNTED FUTURE NET CASH FLOWS

For purposes of the following disclosures, future cash flows were computed by applying to the Company’s proved oil and gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2025, 2024 and 2023, respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities to develop and produce proved reserves at year end.

Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10% discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions as of December 31, 2025, 2024 and 2023. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS


millions	United States		International		Total
Balance as of December 31, 2025
Future cash inflows	$	143,509	$	29,026	$	172,535
Future costs
Production costs and other operating	(65,765)		(11,462)		(77,227)
Development costs (a)	(21,439)		(3,646)		(25,085)
Future income tax expense	(6,922)		(3,301)		(10,223)
Future net cash flows	49,383		10,617		60,000
10% discount factor	(19,485)		(3,888)		(23,373)
Standardized measure of discounted future net cash flows	$	29,898	$	6,729	$	36,627
Balance as of December 31, 2024
Future cash inflows	$	159,735	$	31,110	$	190,845
Future costs
Production costs and other operating	(69,335)		(11,652)		(80,987)
Development costs (a)	(22,149)		(2,507)		(24,656)
Future income tax expense	(9,034)		(3,339)		(12,373)
Future net cash flows	59,217		13,612		72,829
10% discount factor	(24,480)		(5,478)		(29,958)
Standardized measure of discounted future net cash flows	$	34,737	$	8,134	$	42,871
Balance as of December 31, 2023
Future cash inflows	$	143,471	$	35,020	$	178,491
Future costs
Production costs and other operating	(58,864)		(10,921)		(69,785)
Development costs (a)	(19,404)		(3,706)		(23,110)
Future income tax expense	(10,441)		(4,895)		(15,336)
Future net cash flows	54,762		15,498		70,260
10% discount factor	(23,715)		(6,243)		(29,958)
Standardized measure of discounted future net cash flows	$	31,047	$	9,255	$	40,302

(a)Included ARO costs.


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CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES


millions	2025		2024		2023
Balance as of January 1	$	42,871	$	40,302	$	58,152
Sales and transfers of oil and gas produced, net of production costs and other operating expenses	(13,803)		(14,577)		(14,318)
Net change in prices received per barrel, net of production costs and other operating expenses	(5,968)		(4,903)		(23,774)
Extensions, discoveries and improved recovery, net of future production and development costs	4,776		3,949		2,910
Change in estimated future development costs	(1,587)		(122)		(3,430)
Revisions of quantity estimates	1,821		3,574		6,313
Previously estimated development costs incurred during the period	3,495		3,440		2,584
Accretion of discount	3,849		4,052		6,152
Net change in income taxes	2,581		1,581		5,575
Purchases and sales of reserves in place, net	(78)		8,050		404
Changes in production rates and other	(1,330)		(2,475)		(266)
Net change	(6,244)		2,569		(17,850)
Balance as of December 31	$	36,627	$	42,871	$	40,302


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NET PRODUCTIVE AND DRY— EXPLORATORY AND DEVELOPMENT WELLS COMPLETED

The following table sets forth, for each year in the three-year period ended December 31, 2025, the Company’s net productive and dry exploratory and development wells completed:


	United States	International	Total
2025
Oil
Exploratory	17	4	21
Development	452	44	496
Gas
Exploratory	—	—	—
Development	36	1	37
Dry
Exploratory	—	5	5
Development	—	—	—
2024
Oil
Exploratory	29	5	34
Development	355	34	389
Gas
Exploratory	1	2	3
Development	26	4	30
Dry
Exploratory	1	7	8
Development	—	—	—
2023
Oil
Exploratory	25	13	38
Development	420	63	483
Gas
Exploratory	1	1	2
Development	38	3	41
Dry
Exploratory	5	8	13
Development	7	—	7

PRODUCTIVE OIL AND GAS WELLS

The following table sets forth, as of December 31, 2025, the Company’s productive oil and gas wells (both producing and capable of production):


	United States		International		Total
	Gross (a)	Net (b)	Gross (a)	Net (b)	Gross (a)	Net (b)
Oil	19,019	16,288	3,021	1,412	22,040	17,700
Gas	2,989	2,428	166	101	3,155	2,529
Multiple completion wells included above	1,722	1,412	—	—	1,722	1,412

(a)The total number of wells in which interests are owned.

(b)The sum of fractional interests.


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PARTICIPATION IN WELLS BEING DRILLED OR PENDING COMPLETION

The following table sets forth, as of December 31, 2025, the Company’s participation in exploratory and development wells being drilled:


	United States	International	Total
Exploratory and development wells being drilled
Gross	120	9	129
Net	93	7	100
Exploratory and development wells pending completion (a)
Gross	181	1	182
Net	130	1	131

(a)Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future. There were 100 MMboe of PUD reserves primarily assigned to U.S. onshore development wells suspended or waiting on completion as of December 31, 2025. The Company expects to convert all of these PUD reserves to developed status within five years of their initial disclosure.

As of December 31, 2025, the Company was participating in 104 and 39 gross pressure-maintenance projects in the United States and internationally, respectively. In the United States, these projects primarily consisted of waterfloods and CO2 floods, and in the Middle East and North Africa, these projects consisted mostly of waterfloods.

OIL AND GAS ACREAGE

The following table sets forth, as of December 31, 2025, the Company’s holdings of developed and undeveloped oil and gas acreage:


thousands	United States	International	Total
Developed (a)
Gross (b)	5,595	1,287	6,882
Net (c)	3,781	485	4,266
Undeveloped (d)
Gross (b)	1,169	8,358	9,527
Net (c)	725	7,291	8,016
Fee Mineral Ownership (e)
Gross (b)	7,713	—	7,713
Net (c)	4,373	—	4,373

(a)Acres spaced or assigned to productive wells.

(b)Total acres in which interests are held.

(c)Sum of the fractional interests owned based on working interests, or interests under PSCs and other economic arrangements.

(d)Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether the acreage contains proved reserves.

(e)The Company’s fee mineral acreage is primarily undeveloped.

The Company’s investment in developed and undeveloped acreage comprises numerous concessions, blocks and leases. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before the contractual expiration date. In some instances, the Company may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Company has generally been successful in obtaining extensions. Scheduled lease and concession expirations for undeveloped acreage over the next three years are not expected to have a material adverse impact on the Company.


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OIL, NGL AND NATURAL GAS SALES VOLUMES PER DAY

The following tables set forth the sales volumes from ongoing operations of oil, NGL and natural gas per day for each of the three years in the period ended December 31, 2025. The differences between the sales and production volumes per day are negligible and are generally due to the timing of shipments at the Company’s international locations where product is loaded onto tankers. Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil.


Sales per Day (Mboe/d)	2025	2024	2023
United States
Permian	786	664	584
Rockies & Other Domestic	284	310	271
Gulf of America	132	125	145
Total	1,202	1,099	1,000
International
Algeria and Other International	31	33	35
Al Hosn Gas	90	91	82
Dolphin	40	39	39
Oman	71	66	66
Total	232	229	222


Total Sales per Day (Mboe/d)	1,434	1,328	1,222


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Sales per Day by Products	2025	2024	2023
United States
Oil (Mbbl/d)
Permian	416	370	337
Rockies & Other Domestic	92	96	77
Gulf of America	112	105	120
Total	620	571	534
NGL (Mbbl/d)
Permian	201	163	140
Rockies & Other Domestic	78	106	97
Gulf of America	9	9	11
Total	288	278	248
Natural gas (MMcf/d)
Permian	1,011	783	644
Rockies & Other Domestic	686	649	584
Gulf of America	68	66	81
Total	1,765	1,498	1,309
International
Oil (Mbbl/d)
Algeria and Other International	25	27	29
Al Hosn Gas	15	15	14
Dolphin	6	6	6
Oman	62	56	57
Total	108	104	106
NGL (Mbbl/d)
Algeria and Other International	2	3	3
Al Hosn Gas	28	27	23
Dolphin	8	8	8
Total	38	38	34
Natural gas (MMcf/d)
Algeria and Other International	17	18	15
Al Hosn Gas	284	293	267
Dolphin	155	150	150
Oman	57	63	57
Total	513	524	489
Total Sales per Day (Mboe/d)	1,434	1,328	1,222


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			table of contents

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