OCCIDENTAL PETROLEUM CORP /DE/ (OXY)

CIK: 0000797468. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-18.
SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas
SEC company page: https://www.sec.gov/edgar/browse/?CIK=797468. Latest filing source: 0001628280-26-009059.
Selected Fundamentals

Metric	Value	Unit	FY	Filed
Revenue	21,593,000,000	USD	2025	2026-02-18
Net income	2,369,000,000	USD	2025	2026-02-18
Assets	84,186,000,000	USD	2025	2026-02-18
Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-18. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000797468.json. Derived margins are computed from the extracted annual SEC facts.
Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.
Metric	2014	2016	2017	2018	2019	2020	2021	2022	2023	2024	2025
Revenue			12,508,000,000	17,824,000,000	20,911,000,000	17,809,000,000	25,956,000,000	36,634,000,000	23,156,000,000	22,019,000,000	21,593,000,000
Net income		-574,000,000	1,311,000,000	4,131,000,000	-522,000,000	-14,831,000,000	2,322,000,000	13,304,000,000	4,696,000,000	3,078,000,000	2,369,000,000
Diluted EPS		-0.75	1.70	5.39	-1.22	-17.06	1.58	12.40	3.90	2.44	1.61
Assets		43,109,000,000	42,026,000,000	42,159,000,000	107,190,000,000	80,064,000,000	75,036,000,000	72,609,000,000	74,008,000,000	85,445,000,000	84,186,000,000
Stockholders' equity	34,959,000,000		-258,000,000	21,330,000,000	34,232,000,000	18,573,000,000	20,327,000,000	30,085,000,000	30,250,000,000	34,159,000,000	36,034,000,000
Cash and cash equivalents		2,233,000,000	1,672,000,000	3,033,000,000	3,032,000,000	2,008,000,000	2,764,000,000	984,000,000	1,426,000,000	2,125,000,000	1,968,000,000
Net margin			10.48%	23.18%	-2.50%	-83.28%	8.95%	36.32%	20.28%	13.98%	10.97%
Financial Charts

Macro Cross-References

CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
UNRATE - Unemployment Rate
FEDFUNDS - Federal Funds Effective Rate
CES0500000003 - Average Hourly Earnings of All Employees, Total Private
DFEDTARU - Federal Funds Target Range - Upper Limit
DFEDTARL - Federal Funds Target Range - Lower Limit
DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
PCEPI - Personal Consumption Expenditures: Chain-type Price Index
PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
PPIACO - Producer Price Index by Commodity: All Commodities
T10YIE - 10-Year Breakeven Inflation Rate
U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
PAYEMS - All Employees, Total Nonfarm
CIVPART - Labor Force Participation Rate
EMRATIO - Employment-Population Ratio
UNEMPLOY - Unemployed
CE16OV - Employment Level
ICSA - Initial Claims
JTSJOL - Job Openings: Total Nonfarm
JTSQUR - Quits: Total Nonfarm
GDPC1 - Real Gross Domestic Product
A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
INDPRO - Industrial Production: Total Index
TCU - Capacity Utilization: Total Index
HOUST - New Privately-Owned Housing Units Started: Total Units
PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
RSAFS - Advance Retail Sales: Retail Trade
PCE - Personal Consumption Expenditures
DSPIC96 - Real Disposable Personal Income
PSAVERT - Personal Saving Rate
M2SL - M2
BOPGSTB - U.S. International Trade in Goods and Services: Balance
Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-18. Report date: 2025-12-31.
ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8 and the information set forth in Risk Factors under Part 1, Item 1A. The following sections include a discussion of results for fiscal 2025 compared to fiscal 2024 as well as certain 2023 results. The comparative results for fiscal 2024 with fiscal 2023 generally have not been included in this Form 10-K, but may be found in “Part II - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024.

INDEX

PAGE

Current Business Outlook and Strategy

22

Oil and Gas Segment

24

Midstream and Marketing Segment

34

Segment Results of Operations and Items Affecting Comparability

36

Consolidated Results of Operations

39

Income Taxes

42

Liquidity and Capital Resources

43

Lawsuits, Claims, Commitments and Contingencies

45

Environmental Expenditures

46

Global Investments

46

Critical Accounting Policies and Estimates

47

Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data

51

OXY 2025 FORM 10-K

21

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

CURRENT BUSINESS OUTLOOK AND STRATEGY

GENERAL

The Company’s financial results are significantly influenced by oil prices, and to a lesser extent, NGL and natural gas prices, and commodity market differentials. Oil prices have been and are expected to remain volatile due to shifts in energy supply and demand, ongoing geopolitical factors and OPEC supply actions. In 2025, compared to 2024, the average annual WTI price per barrel decreased to $64.81 from $75.72, and the average annual Brent price per barrel decreased to $68.18 from $79.79.

The Company’s costs are influenced by inflationary trends, market conditions, the availability and cost of oilfield services, electricity, and CO₂, and other operational expenditures. In April 2025, a U.S. tariff policy was announced that imposed a 10% base tariff rate on most imports, with higher rates applied to certain countries. Since then, the U.S. has negotiated trade deals, and certain tariff rates have been adjusted or paused amid ongoing litigation. These tariffs may increase the Company’s supplier costs and affect demand and prices for its products. The Company works to manage inflation impacts by capitalizing on operational efficiencies, locking in pricing on longer-term contracts and working closely with vendors to secure the supply of critical materials. Seasonality is not a primary driver of changes in the Company’s consolidated quarterly earnings.

STRATEGY

The Company is focused on delivering a unique shareholder value proposition with its portfolio of oil and gas and midstream and marketing assets, as well as its ongoing development of carbon management and storage solutions and GHG emissions reduction efforts. The Company conducts its operations with a priority on HSE, sustainability and social responsibility. In order to maximize shareholder returns, the Company will:

■    Maintain production base to preserve asset base integrity and longevity;

■Deliver a sustainable and growing dividend;

■Prioritize excess cash flow and proceeds from divestitures, including the OxyChem Transaction, for deleveraging until principal debt is approximately $14.3 billion, after which available cash will be allocated to opportunistic share repurchases and/or further net debt reduction;

■Enhance its asset base with investments in its cash-generative oil and gas business; and

■Advance integrated technologies in CO2, power and midstream to enable differentiated resource recovery and value.

OXYCHEM TRANSACTION

In October 2025, the Company announced entry into a purchase and sale agreement with Berkshire Hathaway to sell all of the issued and outstanding equity interests in OxyChem in an all-cash transaction for $9.7 billion. The sale was completed on January 2, 2026, resulting in an estimated gain of $3.2 billion, net of taxes and subject to post-closing adjustments. As a result, OxyChem’s results of operations, cash flows and the related retained liabilities and indemnification obligations are reported as discontinued operations in the Company’s Consolidated Statements of Operations and Cash Flows for all periods presented, with its assets and liabilities reclassified as held for sale in the Company’s Consolidated Balance Sheets.

An Occidental subsidiary, Environmental Resource Holdings, LLC (ERH), has retained legacy tort claims and environmental liabilities primarily associated with historical operations outside of the footprint of the operating facilities that were sold. Glenn Springs Holdings, Inc. will continue to manage the remedial activities at environmental sites on behalf of ERH. The Company expects to expend funds for remediation over many years based on the approved workplans.

CAPITAL INVESTMENT

In 2025, the Company invested $5.6 billion in high-return oil and gas assets to generate long-term free cash flow throughout the commodity cycle. In the midstream and marketing segment, the Company invested $0.7 billion before contributions from noncontrolling interest, primarily related to STRATOS.

DEBT

In 2025, the Company used proceeds from divestitures and cash on hand to repay approximately $4.0 billion of debt. Subsequent to December 31, 2025, but before the date of this filing, the Company used proceeds from the OxyChem Transaction to pay or satisfy and discharge an additional $5.4 billion of debt.

As of the date of this filing, the principal debt outstanding was approximately $15 billion, of which $24 million is due in 2026, $48 million in 2027, $14 million in 2028, $367 million in 2029 and $14.6 billion due in 2030 and thereafter.

For detailed information on the Company’s debt activity, see Note 5 - Long-Term Debt in the notes to the Consolidated Condensed Financial Statements in Part II, Item 8 of this Form 10-K.

22

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

SHAREHOLDER RETURN PRIORITIES

Capital is returned to shareholders through the Company’s dividend and share repurchases. In 2025, the Company declared dividends to common shareholders of $945 million, or $0.96 per share. As of December 31, 2025, $1.2 billion remained of the Company’s $3.0 billion share repurchase program, which the Board authorized in February 2023. After using the proceeds from the OxyChem Transaction to reduce the principal of outstanding debt to approximately $15 billion, the Company’s shareholder return priorities are to continue to provide a sustainable and growing dividend and further reduce principal debt to approximately $14.3 billion. Available cash will be allocated, as appropriate, to opportunistic share repurchases and/or further debt reduction.

SUSTAINABILITY STRATEGY

The Company’s sustainability strategy is organized around four pillars: principles of governance, people, planet, and prosperity. The Company integrates these sustainability pillars into our strategic planning and investment decision-making processes.

In 2020, the Company was the first U.S. oil and gas company to announce goals to achieve net-zero GHG emissions for its total emissions inventory including use of sold products. These goals include achieving net-zero GHG emissions (i) from its operations and energy use before 2040, with an ambition to do so before 2035, and (ii) from its total carbon inventory, including the use of its sold products, with an ambition to do so before 2050. In 2020, the Company also set various interim targets, including 2025 carbon and methane intensity targets, and the Company was the first U.S. oil and gas company to endorse the World Bank’s initiative for zero routine flaring by 2030. In 2022, the Board of Directors adopted the Company’s updated HSE and Sustainability Principles, based on engagement with shareholders, employees and other stakeholders. The HSE and Sustainability Principles reinforce the alignment among the Company’s core values, goals and strategies, underpin its Operating Management System, and help to guide the workforce across its operations. In 2023, the Company was an original signatory to the Oil and Gas Decarbonization Charter, committed funding to the World Bank’s Global Flaring and Methane Reduction Partnership, and established a new, medium-term 2030 methane intensity target. In 2025, the Company established a new, medium-term 2030 CO2 equivalent intensity target.

The Company seeks to meet its sustainability and environmental goals by implementing practices and technologies to reduce operational emissions coupled with its development and commercialization of technologies that lower both GHG emissions from industrial processes and existing atmospheric concentrations of CO2. The Company believes that carbon removal technologies, including DAC and CCUS, can, with incentives necessary for their development and deployment, provide essential CO2 reductions to assist the world’s transition to a lower carbon-intensive economy. Through fiscal 2024, the Company reduced estimated methane emissions by approximately 78.6% from 2019 and 40% from 2023, along with a 28.7% reduction in CO2 equivalent emissions since 2019. The following actions helped the Company advance its low-carbon business strategy in 2025:

■Completed construction of STRATOS central processing facilities and obtained Class VI permits to sequester CO2, with operations expected to begin in 2026.

■Actively progressed its sequestration hub plans, with five sequestration hubs in various stages of development primarily in the Permian Basin and across the Texas and Louisiana Gulf Coast; and

■Implemented emissions reduction projects involving hundreds of facilities and wells and thousands of pieces of equipment across its oil and gas operations.

The future costs associated with emissions reduction, carbon removal and CCUS to meet the Company’s long-term net-zero GHG goals may be substantial and the execution of its plans and net-zero pathway depends on securing third-party capital investments. As reflected by the joint venture with BlackRock, the Company is pursuing multiple avenues to fund these projects including project financing, long-term carbon removal or CCUS agreements, and identifying business opportunities with stakeholders in carbon-intensive industries.

KEY PERFORMANCE INDICATORS

The Company seeks to meet its strategic goals by continually measuring its success against key performance indicators that drive total stockholder return. In addition to efficient capital allocation and deployment discussed below in the section titled “Oil and Gas Segment - Business Strategy,” the Company believes its most significant performance indicators are:

OPERATIONAL

■Total spend per barrel - In 2026, the Company will continue our emphasis on controlling total costs from a per-barrel perspective. Total spend per barrel is the sum of capital spending, general and administrative expenses, other operating and non-operating expenses and oil and gas lease operating costs divided by global oil, NGL and natural gas sales volumes.

■Daily production - the Company seeks to maximize field operability and minimize production down-time.

OXY 2025 FORM 10-K

23

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

FINANCIAL

■CROCE - CROCE is calculated as (i) the cash flows from operating activities, before changes in working capital, plus distributions from WES classified as investing cash flows, divided by (ii) the average of the opening and closing balances of total equity plus total debt.

■FCF - FCF is calculated as the cash flows from operating activities, before changes in working capital, less the Company’s capital expenditures, net of contributions from noncontrolling interests.

■Financial Leverage- Reduce debt to achieve metrics consistent with an investment grade credit rating.

SUSTAINABILITY AND ENVIRONMENTAL

■Interim targets to advance the goal of net-zero operational and energy use emissions before 2040, with an ambition to achieve before 2035.

■Milestones in specific carbon removal and CCUS projects that advance a net-zero total emissions inventory, including use of sold products, with an ambition to achieve before 2050.

■Facilitate deployment of carbon removal, CCUS and other solutions to advance total carbon impact past 2050.

OIL AND GAS SEGMENT

BUSINESS STRATEGY

The Company’s oil and gas segment focuses on long-term value creation in the key performance indicators noted above of total spend per barrel, field operability, daily production, and leadership through our HSE and sustainability initiatives. In each core operating area, the Company’s operations benefit from scale, technical expertise, decades of high-margin inventory, HSE leadership and commercial and governmental collaboration. These attributes allow the Company to bring additional production quickly to market, extend the life of mature fields at lower costs and pursue low-cost returns-driven growth opportunities with advanced technology.

The Company is one of the largest U.S. producers of liquids, which includes oil and NGL, enabling it to maximize cash margins on a per barrel basis. The Company’s robust portfolio, combined with our subsurface characterization expertise and proven ability to execute, support long-term value creation and full-cycle success. The oil and gas segment strives to maximize efficiencies to lower breakeven costs, generate excess free cash flow and maintain low development and operating costs — thereby enhancing the full-cycle value of its assets.

The oil and gas segment implements the Company’s strategy primarily by:

■Operating and developing areas where reserves are known to exist and optimizing capital intensity in the Permian Basin, Rockies, Gulf of America, and our international locations;

■Maintaining a disciplined and prudent approach to capital expenditures with a focus on high-return, short and mid-cycle, cash-flow-generating opportunities and an emphasis on creating value and further enhancing the Company’s existing positions;

■Applying the Company’s subsurface characterization and technical expertise to both conventional and unconventional resources;

■Using secondary and tertiary recovery techniques in mature fields and leveraging the Company’s EOR position, experience and infrastructure to extend U.S. unconventional resources; and

■Focusing on cost-reduction efficiencies and innovative technologies to reduce carbon emissions.

In 2025, oil and gas capital expenditures, including exploration, were approximately $5.6 billion and primarily focused on the Company’s assets in the Permian Basin, DJ Basin, Gulf of America and Oman.

OIL AND GAS PRICE ENVIRONMENT

Oil and gas prices are the major variables that drive the industry’s financial performance. The following table presents the average daily WTI and Brent prices for oil and NYMEX natural gas prices for 2025 and 2024:

2025

2024

% Change

WTI Oil ($/Bbl)

$

64.81 

$

75.72 

(14)

%

Brent Oil ($/Bbl)

$

68.18 

$

79.79 

(15)

%

NYMEX Natural Gas ($/Mcf)

$

3.55 

$

2.34 

52 

%

24

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following table presents the Company’s average realized prices for continuing operations as a percentage of WTI, Brent and NYMEX for 2025 and 2024:

2025

2024

Worldwide oil as a percentage of average WTI

100 

%

99 

%

Worldwide oil as a percentage of average Brent

95 

%

94 

%

Worldwide NGL as a percentage of average WTI

32 

%

28 

%

Worldwide NGL as a percentage of average Brent

30 

%

27 

%

Domestic natural gas as a percentage of NYMEX

45 

%

40 

%

Prices and differentials can vary significantly, even on a short-term basis, making it difficult to predict realized prices with a reliable degree of certainty.

DOMESTIC INTERESTS

BUSINESS REVIEW

The Company conducts its domestic operations through land leases, subsurface mineral rights it owns, or a combination of both. The Company’s domestic oil and gas leases have a primary term ranging from one to 10 years, which is extended through the end of production once it commences. The Company has leasehold and mineral interests in 8.9 million net acres, of which approximately 51% is leased, 48% is owned subsurface mineral rights and 1% is owned land with mineral rights.

DOMESTIC ASSETS (a)

1. Powder River Basin

2. DJ Basin

3. Permian Basin

4. Gulf of America

(a)Map represents geographic outlines of the respective basins.

 OXY 2025 FORM 10-K

25

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

The Permian Basin

The Permian Basin extends throughout West Texas and Southeast New Mexico and is one of the largest and most active oil basins in the United States, accounting for more than 49% of total United States oil production in 2025. In 2025, the Company sustained a leading position in the Permian Basin, producing approximately 10% of the total oil in the basin. The Company’s 2025 production in the Permian Basin was 786 Mboe/d. In 2025, the Company invested approximately $3.4 billion of development capital in the Permian Basin.

The Company manages its Permian Basin operations through two businesses: Permian Resources, which includes unconventional opportunities, and Permian EOR, which utilizes secondary and tertiary recovery techniques. By exploiting the natural synergies between Permian Resources and Permian EOR, the Company is able to deliver unique short- and long-term advantages, efficiencies and expertise across its Permian Basin operations.

The Permian Resources business is focused on developing and producing unconventional reservoir targets using horizontal drilling technology. The development programs are designed to create long-term value from primary development by maximizing the recovery of oil, utilizing sustainable practices and providing strong financial returns. In 2025, Permian Resources prioritized core development areas, focusing on maintaining the industry-leading capital intensity through optimized surface infrastructure and customized well designs. Permian Resources has 1.5 million net acres. In 2025, Permian Resources produced from approximately 6,300 gross wells and added 390 MMboe to the Company’s proved reserves through infill development projects and extensions of proved areas.

The Permian Basin’s concentration of large conventional reservoirs, strong CO2 flooding performance and the expansive CO2 transportation and processing infrastructure has resulted in decades of high-value enhanced oil production. With 34 active CO2 floods and over 50 years of experience, Permian EOR is the industry leader in Permian Basin CO2 flooding, which can increase ultimate oil recovery by 10% to 25%. Technology improvements, such as the recent trend toward vertical expansion of the CO2 flooded interval into residual oil zone targets, continue to yield more recovery from existing projects. Significant opportunities also remain to gain additional recovery by expanding the Company’s existing CO2 projects into new portions of reservoirs that have only been waterflooded. Permian EOR has 1.4 million net acres with a large inventory of future CO2 projects, which could be developed over the next 20 years or accelerated, depending on market conditions. Permian EOR produced from approximately 11,900 gross wells in 2025.

Rockies and Other Domestic

In 2025, the Company produced 284 Mboe/d and invested capital of approximately $0.8 billion in the Rockies and Other Domestic locations. Production in the DJ Basin is derived from approximately 3,500 gross wells primarily focused in the Niobrara and Codell formations. The DJ Basin comprises approximately 0.5 million total net acres and provides competitive economics, low breakeven costs and free cash flow generation through the Company’s contiguous acreage position and royalty uplift.

Operations in the DJ Basin are subject to regulations that impose siting requirements, or “setback,” on certain oil and gas drilling locations based on the distance of a proposed well pad to occupied structures. The Company has a dedicated stakeholder relations team that conducts regulatory and community outreach with respect to its permit applications and operations in Colorado with a focus on building trust and fostering open communication with those who live and work near its operations. The Company has established a steady cadence of permit approvals from various agencies, local governments and the ECMC through robust community outreach, protective site selection, thoughtful facility design and planning, and best-in-class measures to mitigate potential impacts from operations. In 2025, the Company submitted Oil and Gas Development Plans comprising approximately 100 wells to the ECMC. As of December 31, 2025, the Company has permits for over 90% of the 2026 drilling schedule and over 45% of the 2027 drilling schedule with the remaining percentage of activity pending regulatory approval or scheduled for submission in 2026. The Company continues to gain efficiencies in the permitting process and will continue to look for additional opportunities to do so in the future.

The Company has interests in approximately 0.2 million net acres in the Powder River Basin, mainly located in Converse County and Campbell County, Wyoming. The Powder River Basin contains the Turner, Niobrara, Mowry, Parkman, and Teapot formations that hold both liquids and natural gas and produces from 139 gross wells.

The Company holds approximately 4.5 million net acres in other domestic locations, which consist of acreage and fee minerals outside of the Company’s core operated areas including parts of Arkansas, Colorado, Louisiana, Texas, West Virginia and Wyoming.

OFFSHORE DOMESTIC ASSETS

Gulf of America

The Company is the fourth-largest oil and gas producer in the deep-water Gulf of America, operating 8 strategically located deep-water floating platforms and producing from 14 active fields while owning a working interest in approximately 230 blocks, covering approximately 0.8 million net acres.

In 2025, the Company’s Gulf of America production was 132 Mboe/d from 96 gross wells. The Company’s focused production management processes and development projects resulted in increased production from the prior year. Operational efficiency focus continued in 2025, with Production Operations and Asset Integrity teams achieving world class highest platform operating efficiencies, with major equipment uptimes of over 99%.

26

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

The Company’s Gulf of America assets continued to be among the lowest carbon emissions operations in the industry with zero routine flaring and zero cold venting.

The Company invested $0.5 billion of development capital in 2025 with a continued strategy of low risk, infill drilling opportunities and accelerated project delivery at its Horn Mountain, Constitution and Lucius facilities. Drilling and well service projects were implemented utilizing two floating drill ships and several service rigs. During 2025, all necessary regulatory permits for new wells and existing operations were obtained timely without any operational delays.

As part of its Gulf of America 2.0 program (GOA 2.0), the Company successfully implemented several state-of-the-art artificial lift projects, including down-hole gas-lift and caisson electric submersible pumps at its Horn Mountain platform in 2025, delivering some of the highest margin production in the Company’s portfolio. In addition, the Company’s asset development and facilities teams began implementation of several GOA 2.0 growth projects to significantly increase recovery from the Company’s existing producing oil and gas reservoirs with the first water injection at Marlin planned to be on stream in Summer 2026 and at Horn Mountain in 2027. Several major secondary recovery uplift projects and new horizontal/extended reach well opportunities will continue implementation in 2026 onwards.

The Company’s Gulf of America operations will conduct both development and exploration activities in 2026 using two floating drill ships and several other well service vessels and will continue to develop and expand its extensive portfolio of lease working interests through its GOA 2.0 program.

The following table shows key areas of ongoing development in the Gulf of America, along with the corresponding working interest in those areas.

Working Interest

Horn Mountain

100 

%

Holstein

100 

%

Marlin

100 

%

Lucius

67 

%

K2 Complex

51 

%

Caesar Tonga

34 

%

Constellation

33 

%

INTERNATIONAL INTERESTS

BUSINESS REVIEW

The Company primarily conducts its international operations in two sub-regions: the Middle East and North Africa. Its activities include oil, NGL and natural gas production through direct working interests and PSCs. Under the PSCs, the Company records a share of production and reserves to recover certain development and production costs and an additional share for profit. These contracts do not transfer any right of ownership to the Company and reserves reported from these arrangements are based on the Company’s economic interest as defined in the contracts. The Company’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, the Company’s net economic benefit from these contracts is greater when product prices are higher.

 OXY 2025 FORM 10-K

27

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

MIDDLE EAST / NORTH AFRICA ASSETS

1.Algeria

2.Oman

3.Qatar

4.UAE

Algeria

The Company’s interests in Algeria consists of production rights in 18 fields within Blocks 404a and 208, both of which expire in 2048, located in the Berkine Basin in Algeria’s Sahara Desert. The Company also owns interests in 3 unitized fields within Blocks 404a and 208 (the Ourhoud Unit, the EMK Unit and the HBN Unit) as well as in 3 processing facilities (the El Merk central processing facility in Block 208 that processes produced oil, NGL and natural gas; and the Hassi Berkine South and Ourhoud central processing facilities in Block 404a that process produced oil).

In 2025, net production in Algeria was 28 Mboe/d from 219 gross wells, and annual development capital expenditures were $0.1 billion.

Oman

In Oman, the Company is the operator of Block 9, Block 27, Block 53 (Mukhaizna Field), Block 62 and Block 65 and has additional interests in Blocks 30, 51 and 72, which are under the exploration phase. The working interest and contract expiration year for each of the respective blocks are shown in the table below. The Company holds 6.0 million gross acres and has 10,000 potential well inventory locations. In 2025, the Company’s share of production was 72 Mboe/d.

Working Interest

Block Expiration (Year)

Block 9

50 

%

2030

Block 27

65 

%

2035

Block 53

47 

%

2050

Block 62

100 

%

2028

Block 65

51 

%

2037

Blocks 30, 51 and 72

100 

%

Exploration Phase

The Company has produced over 853 million gross barrels from Block 9 since the beginning of its operation through successful exploration, continuous drilling improvements and EOR projects. The Mukhaizna Field in Block 53 is a major pattern steam flood project for EOR that utilizes some of the largest mechanical vapor compressors ever built. Since assuming operations in the Mukhaizna Field in 2005, the Company has drilled over 3,600 new wells and has substantially increased production to deliver over 662 million gross barrels, while maintaining a strong commitment to operational excellence, environmental stewardship and community engagement. The Company signed a 15-year contract extension for Block 53 in 2025, which is expected to deliver significant value to all stakeholders. In 2025, the Company invested development capital of $0.4 billion across all of the Oman blocks to drill 120 wells and execute facilities projects to support development and EOR activities.

28

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

Qatar

In Qatar, the Company partners in the Dolphin Energy Project, an investment that is comprised of two separate economic interests. The Company has a 24.5% interest in the upstream operations to develop and produce NGL, natural gas and condensate from Qatar’s North Field through mid-2032. The Company also has a 24.5% interest in Dolphin midstream in the UAE, which operates a pipeline and is discussed further in the midstream and marketing segment section in this Form 10-K under Pipeline. In 2025, the Company’s net share of production from Dolphin was 40 Mboe/d.

UAE

The Company has a 40% participating interest in the Shah gas field (Al Hosn Gas), in conjunction with ADNOC, the UAE’s national oil company, which expires in 2041. In 2025, the Company’s net share of production from Al Hosn Gas was 283 MMcf/d of natural gas and 42 Mbbl/d of NGL and condensate. Al Hosn Gas includes gas processing facilities which are discussed further in the midstream and marketing segment section in this Form 10-K under Gas Processing, Gathering and CO2.

In 2019 and 2020, the Company acquired 9-year exploration concessions and, subject to a declaration of commerciality, 35-year production concessions for Onshore Block 3 and Block 5, which cover a combined area of approximately 2.5 million acres, and are adjacent to Al Hosn Gas. In 2023, the Company commenced first oil production in Onshore Block 3.

PROVED RESERVES

Proved oil, NGL and natural gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGL and natural gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs.

The following table shows the 2025, 2024 and 2023 calculated first-day-of-the-month average prices for both WTI and Brent oil prices, as well as the Henry Hub gas and Mt. Belvieu NGL prices:

2025

2024

2023

WTI Oil ($/Bbl)

$

65.34 

$

75.48 

$

78.22 

Brent Oil ($/Bbl)

$

68.42 

$

79.65 

$

82.80 

Henry Hub Natural Gas ($/MMbtu)

$

3.39 

$

2.13 

$

2.64 

Mt. Belvieu NGL ($/Bbl)

$

31.79 

$

33.04 

$

29.94 

The Company had proved reserves from continuing operations at year-end 2025 of 4,603 MMboe, compared to the year-end 2024 proved reserves of 4,612 MMboe. Proved developed reserves represented approximately 72% and 69% of the Company’s total proved reserves as of December 31, 2025 and 2024, respectively. The following table shows the Company’s proved reserves from continuing operations by commodity as a percentage of total proved reserves:

2025

2024

Oil

47 

%

46 

%

NGL

25 

%

27 

%

Natural gas

28 

%

27 

%

The Company does not have any reserves from non-traditional sources. For further information regarding the Company’s proved reserves, see the Supplemental Oil and Gas Information section in Item 8 of this Form 10-K.

 OXY 2025 FORM 10-K

29

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

CHANGES IN PROVED RESERVES

Changes in the Company’s 2025 reserves were as follows:

MMboe

2025

Balance — beginning of year

4,612 

Revisions of previous estimates

161 

Improved recovery

60 

Extensions and discoveries

340 

Purchases

10 

Sales

(57)

Production

(523)

Balance — end of year

4,603 

The Company’s ability to add reserves, other than through purchases, depends on the success of infill development, extension, discovery and improved recovery projects, each of which depends on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside management’s control and may negatively or positively affect the Company’s reserves.

Revisions of Previous Estimates

Revisions can include upward or downward changes to previous proved reserve estimates for existing fields due to the evaluation or interpretation of geologic, production decline or operating performance data. In addition, product price changes affect proved reserves recorded by the Company. For example, lower prices may decrease the economically recoverable reserves, particularly for domestic properties, because the reduced margin limits the expected life of the operations. Offsetting this effect, lower prices increase the Company’s share of proved reserves under PSCs because more oil is required to recover costs. Conversely, when prices rise, the Company’s share of proved reserves decreases for PSCs and economically recoverable reserves may increase for other operations. Reserve estimation rules require that estimated ultimate recoveries be much more likely to increase or remain constant than to decrease, as changes are made due to increased availability of technical data.

In 2025, the Company’s revisions of previous estimates of proved reserves were positive 161 MMboe, which were composed of positive revisions related to additions associated with infill development projects (115 MMboe), changes in economic conditions (131 MMboe), and the Oman contract extension (61 MMboe). The positive revisions were partially offset by negative revisions associated with price revisions (85 MMboe) and updates based on reservoir performance (45 MMboe).

Positive revisions related to additions associated with infill development projects of 115 MMboe were mainly in the Permian Basin (54 MMboe) and the DJ Basin (49 MMboe).

Positive revisions associated with changes in economic conditions of 131 MMboe were primarily in the Permian Basin (122 MMboe).

Negative price revisions of 85 MMboe were primarily associated with the Permian Basin (94 MMboe), which were partially offset by positive price revisions of 7 MMboe on international PSCs.

Negative revisions of 45 MMboe associated with updates based on reservoir performance were primarily related to the Permian Basin (66 MMboe), which were partially offset by positive reservoir performance updates in GOA (19 MMboe).

Improved Recovery

In 2025, the Company added proved reserves of 60 MMboe related to improved recovery in GOA (44 MMboe), Permian EOR (9 MMboe) and Oman (7 MMboe). These properties comprise conventional projects, which are characterized by the deployment of EOR development methods, largely employing application of CO2 flood, waterflood or steam flood. These types of conventional EOR development methods can be applied through existing wells, though additional drilling is frequently required to fully optimize the development configuration. Waterflooding is the technique of injecting water into the formation to displace the oil to the offsetting oil production wells. The use of either CO2 or steam flooding depends on the geology of the formation, the evaluation of engineering data, availability and cost of either CO2 or steam and other economic factors. Both techniques work similarly to lower viscosity, causing the oil to move more easily to the producing wells.

Extensions and Discoveries

The Company also added proved reserves from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2025, extensions and discoveries added 340 MMboe primarily related to the recognition of proved reserves in the Permian Basin (336 MMboe).

30

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

Purchases of Proved Reserves

In 2025, the Company purchased proved reserves of 10 MMboe consisting of proven reserves in the Permian Basin related to acreage trades.

Sales of Proved Reserves

In 2025, the Company sold 57 MMboe in proved reserves related to the divestitures of certain non-strategic assets in the Permian Basin and the DJ Basin.

Proved Undeveloped Reserves

The Company had PUD reserves at year-end 2025 of 1,309 MMboe, compared to the year-end 2024 amount of 1,421 MMboe.

Changes in PUD reserves were as follows:

MMboe

2025

Balance — beginning of year

1,421 

Revisions of previous estimates

46 

Improved recovery

55 

Extensions and discoveries

247 

Purchases

1 

Sales

(23)

Transfer to proved developed reserves

(438)

Balance — end of year

1,309 

Revisions of previous estimates were a positive 46 MMboe. Approximately 238 MMboe of the positive revisions were associated with updates based on reservoir performance, primarily due to positive performance revisions in the Permian Basin (242 MMboe). Further positive revisions were composed of positive revisions related to additions associated with infill development projects (102 MMboe), changes in economic conditions (16 MMboe), and the Oman contract extension (11 MMboe). The positive revisions were partially offset by negative revisions of 318 MMboe associated with management changes in development plans, mainly in the Permian Basin (314 MMboe).

The positive revisions related to additions associated with infill development projects of 102 MMboe were mainly in the Permian Basin (47 MMboe) and the DJ Basin (44 MMboe). Positive revisions associated with changes in economic conditions of 16 MMboe were primarily in the Permian Basin.

Extensions and discoveries added 247 MMboe primarily related to the recognition of proved reserves in the Permian Basin (243 MMboe). Total improved recovery additions of 55 MMboe were the result of implementing secondary and tertiary projects in GOA (44 MMboe), Permian EOR (7 MMboe) and Oman (4 MMboe). In 2025, the Company purchased PUD reserves of 1 MMboe consisting of development projects in the Permian Basin related to acreage trades and sold 23 MMboe consisting of development projects primarily related to certain non-strategic assets in the Permian Basin. The 2025 additions to PUD reserves were partially offset by transfers to proved developed reserves of 438 MMboe. The transfers were primarily associated with the Permian Basin (278 MMboe), the DJ Basin (98 MMboe) and GOA (47 MMboe).

In 2025, the Company incurred approximately $2.2 billion to convert PUD reserves to proved developed reserves, and converted approximately 31% of its PUD reserves to proved developed, when adjusted for revisions and sales. As of December 31, 2025, the Company had 1,309 MMboe of PUD reserves of which 82% were associated with domestic onshore, 5% with GOA and 13% with international assets. The Company’s most active development areas are located in the Permian Basin, which represented 69% of the PUD reserves as of December 31, 2025. Overall, the Company plans to spend approximately $8.4 billion over the next five years to develop its PUD reserves in the Permian Basin.

PUD reserves are supported by a five-year detailed field-level development plan, which includes the timing, location and capital commitment of the wells to be drilled. Only PUD reserves which are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the PUD reserves are expected to be developed beyond the five years and are tied to approved long-term development projects.

As of December 31, 2025, the Company had 185 MMboe of pre-2021 PUD reserves that remained undeveloped. These PUD reserves relate to approved long-term development plans, primarily associated with international development projects (168 MMboe) with physical limitations in existing gas processing capacity and related to approved long-term development plans for Permian EOR projects (17 MMboe), also with physical limitations in existing gas processing capacity. The Company remains committed to these projects and continues to actively progress the development of these volumes.

 OXY 2025 FORM 10-K

31

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

RESERVES EVALUATION AND REVIEW PROCESS

The Company’s estimates of proved reserves and associated future net cash flows as of December 31, 2025 were made by the Company’s technical personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and funding commitments by the Company to develop the reserves. This process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of the proved reserves estimation process, all reserve volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Price differentials between benchmark prices (the unweighted arithmetic average of the first-day-of-the-month price for each month within the year) and realized prices and specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including estimates from decline curve analysis, type well profile analysis, computer simulation of the reservoir performance and volumetric analysis calculations that take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes supported by various technologies including seismic analysis. These reliable field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities.

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods for which the incremental cost of any additional required investment is relatively minor.

Net PUD reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. PUD reserves are supported by a five-year detailed field-level development plan, which includes the timing, location and capital commitment of the wells to be drilled. The development plan is reviewed and approved annually by senior management and technical personnel. Annually, a detailed review is performed by the Company’s Corporate Reserves Group and its technical personnel on a lease-by-lease basis to assess whether PUD reserves are being converted on a timely basis within five years from the initial disclosure date. Any leases not showing timely transfers from PUD reserves to proved developed reserves are reviewed by senior management to determine if the remaining reserves will be developed in a timely manner and have sufficient capital committed in the development plan. Only PUD reserves that are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the PUD reserves are expected to be developed beyond the five years and are tied to approved long-term development plans.

The current Vice President, Reserves for Oxy Oil and Gas is responsible for overseeing the preparation of reserve estimates, in compliance with SEC rules and regulations, including the internal audit and review of the Company’s oil and gas reserves data. She has over 24 years of experience in the upstream sector of the exploration and production business and has extensive experience evaluating a variety of assets in basins around the world. She is a past President of the International Executive Committee for the SPEE and a member of the Society of Petroleum Engineers. She is a licensed Professional Engineer in the State of Texas and currently serves on the SPEE Reserves Definitions Committee. She has Bachelor of Science degree in chemical engineering from the University of Illinois Urbana-Champaign.

The Company has a Reserves Committee, consisting of senior corporate officers, to review and approve the Company’s oil and gas reserves. The Reserves Committee reports to the Audit Committee of the Company’s Board of Directors during the year. Since 2003, the Company has retained Ryder Scott, independent petroleum engineering consultants, to review its annual oil and gas reserve estimation processes. For additional reserves information, see Supplemental Oil and Gas Information under Item 8 of this Form 10-K.

In 2025, Ryder Scott conducted a process review of the methods and analytical procedures utilized by the Company’s engineering and geological staff for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as of December 31, 2025, in accordance with SEC regulatory standards. Ryder Scott reviewed the specific application of such methods and procedures for selected oil and gas properties considered to be a valid representation of the Company’s 2025 year-end total proved reserves portfolio. In 2025, Ryder Scott reviewed approximately 39% of the Company’s proved oil and gas reserves. Since being engaged in 2003, Ryder Scott has reviewed the specific application of the Company’s reserve estimation methods and procedures for approximately 97% of the Company’s existing proved oil and gas reserves.

Management retained Ryder Scott to provide objective third-party input on its methods and procedures and to gather industry information applicable to the Company’s reserve estimation and reporting process. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities reported by the Company. The Company has filed Ryder Scott’s independent report as an exhibit to this Form 10-K.

Based on its reviews, including the data, technical processes and interpretations presented by the Company, Ryder Scott has concluded that the overall procedures and methodologies the Company utilized in estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications for the reviewed properties are appropriate for the purpose thereof and comply with current SEC regulations.

OUTLOOK

The oil and gas exploration and production industry remains highly competitive and is subject to significant volatility due to various market conditions, with operations highly dependent on oil prices and, to a lesser extent, NGL and natural gas

32

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

prices. In 2025, compared to 2024, the average daily price per barrel of WTI crude decreased to $64.81 from $75.72, the average daily Brent price per barrel decreased to $68.18 from $79.79 and the average daily NYMEX natural gas price per MMcf increased to $3.55 from $2.34.

Oil prices will continue to be affected by: (i) global supply and demand, which are generally a function of global economic conditions, inventory levels, production or supply chain disruptions, technological advances, regional market conditions and the actions of OPEC, other significant producers and governments; (ii) transportation capacity, infrastructure constraints, and associated costs in producing areas; (iii) currency exchange rates and inflation; and (iv) the impact of these variables on market sentiment. It is expected that the price of oil will be volatile for the foreseeable future given the ongoing geopolitical risks, the evolving macro-economic environment and supply activity from OPEC and non-OPEC oil producing countries. The Company does not operate or own assets in either Russia or Ukraine, or in the immediate vicinity of ongoing conflicts in the Middle East.

NGL pricing is influenced by the supply and demand for the individual components of these liquids. Some are closely tied to oil prices, while others are affected by natural gas prices and the demand for chemical products that use NGLs as feedstock. In addition, regional infrastructure constraints continue to amplify pricing volatility.

Domestic natural gas prices and local differentials are primarily driven by local supply and demand fundamentals, government regulations, global LNG demand and transportation capacity from producing areas. International gas prices are generally fixed under long-term contracts.

These and other factors make it difficult to reliably forecast oil, NGL and domestic gas prices. For its current capital plan, the Company will continue to focus on allocating capital to high-return assets with the flexibility to adapt to market conditions including commodity price fluctuations, supply chain constraints, tariffs, higher interest rates, global logistics and persistent inflation, all of which disrupt global supply and demand balances. The Company’s objective is to deliver our free cash flow needs without impacting operational performance.

The timing, process and ultimate cost of transitioning to a less carbon-intensive economy remain largely uncertain; various industry forecasts indicate a growing demand for hydrocarbons for the next decade. The Company believes its operational flexibility to achieve low development and operating costs to maximize full-cycle value of its assets and its knowledge and experience in CO2 separation, transportation, use, recycling and storage position its oil and gas segment for opportunities to lower carbon intensity.

 OXY 2025 FORM 10-K

33

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

MIDSTREAM AND MARKETING SEGMENT

BUSINESS STRATEGY

The midstream and marketing segment strives to maximize value by optimizing the use of its gathering, processing, transportation, storage and terminal commitments and by providing the oil and gas segment access to domestic and international markets. To generate returns, the segment evaluates opportunities across the value chain and uses its assets to provide services to Occidental’s subsidiaries, as well as third parties. The midstream and marketing segment operates or contracts for services on gathering systems, gas plants, and storage facilities and invests in entities that conduct similar activities.

This segment also seeks to minimize the costs of gas and power used in the Company’s operations. Also included in the midstream and marketing segment is OLCV. OLCV seeks to leverage the Company’s experience with carbon management in EOR. OLCV invests in emerging low-carbon technologies that are expected to reduce the Company’s carbon footprint and ensure the long-term sustainability of the Company’s principal business, and enable others to do the same.

Capital is employed to sustain or expand assets to improve the competitiveness of the Company’s business. In 2025, capital expenditures related to the midstream and marketing segment totaled $720 million, before contributions from noncontrolling interests, the majority of which were related to the construction of STRATOS.

BUSINESS ENVIRONMENT

Midstream and marketing segment earnings are primarily affected by the performance of its marketing, gathering and transportation business, as well as its gas processing business. The marketing business aggregates, markets and stores Company and third-party volumes. Marketing performance is affected primarily by commodity price changes and margins in oil and gas transportation and storage programs. The marketing business results can experience significant volatility depending on commodity prices and the Midland-to-Gulf-Coast oil spreads and Waha-to-Gulf-Coast gas spreads. The Midland-to-Gulf-Coast oil spreads have decreased to an average of $0.30 per barrel in 2025 from an average of $0.49 per barrel in 2024. The Waha-to-Gulf-Coast gas spreads have increased to an average of $2.21 per MMbtu in 2025 from an average of $1.49 per MMbtu in 2024. Gas gathering, processing and transportation results are affected by fluctuations in commodity prices and the volumes that are processed and transported through the segment’s plants, as well as the margins obtained on related services from investments in which the Company has an equity interest. Excluding items affecting comparability, midstream and marketing’s results in 2025, compared to 2024, were impacted by higher sulfur prices at Al Hosn, higher Waha-to-Gulf-Coast gas spreads, and lower long-haul crude transportation costs, partially offset by higher losses from equity method investees and higher expenses due to the increase in OLCV activities.

BUSINESS REVIEW

MARKETING

The marketing group markets substantially all of the Company’s oil, NGL and natural gas production and optimizes its transportation and storage capacity. The Company’s third-party marketing activities focus on purchasing oil, NGL and natural gas for resale from parties whose oil and gas supply is located near its transportation and storage capacity. These purchases allow the Company to aggregate volumes to better utilize and optimize its assets.

DELIVERY AND TRANSPORTATION COMMITMENTS

The Company has made long-term commitments to certain refineries and other buyers to deliver oil, NGL and natural gas. The total amount contracted to be delivered is approximately 74 MMbbl of oil through 2026, 693 MMbbl of NGL through 2034 and 545 Bcf of gas through 2029. The price for these deliveries is set at the time of delivery of the product.

The Company has crude pipeline take-or-pay capacity of approximately 750 Mbbl/d to the Gulf Coast, leased crude storage capacity of approximately 9 MMbbl and capacity at the crude terminal of approximately 525 Mbbl/d.

PIPELINE

The Company’s pipeline business mainly consists of its 24.5% ownership interest in DEL. DEL owns and operates a 230-mile-long, 48-inch-diameter natural gas pipeline, known as the Dolphin Pipeline, which transports dry natural gas from Qatar to the UAE and Oman. The Dolphin Pipeline has capacity to transport up to 3.2 Bcf/d and currently transports approximately 2.0 Bcf/d and up to 2.2 Bcf/d in the summer months.

GAS PROCESSING, GATHERING AND CO2

The Company processes its own and third-party domestic wet gas to extract NGL and other gas byproducts, including CO2, and delivers dry gas to pipelines. Margins primarily result from the difference between inlet costs of wet gas and market prices for NGL.

34

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

WES is a publicly traded limited partnership with its limited partner units traded on the NYSE under the ticker symbol “WES.” As of December 31, 2025, the Company owned all of the 2.2% non-voting general partner interest, 40.6% of the WES limited partner units, and a 2% non-voting limited partner interest in WES Operating, a subsidiary of WES. As of December 31, 2025, the Company’s combined share of net income from WES and its subsidiaries was 43.1%. In February 2026, in connection with certain contract amendments, the Company transferred 15.3 million units to WES; after this transfer, the combined share of net income in WES and its subsidiaries is 40.9%. See Note 1 - Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for more information regarding the Company’s equity method investment in WES. WES owns gathering systems, plants and pipelines and earns revenue from fee-based and service-based contracts with the Company and third parties.

The Company’s 40% participating interest in Al Hosn Gas also includes sour gas processing facilities that are designed to process 1.45 Bcf/d of natural gas and separate it into salable gas, condensate, NGL and sulfur. In 2025, the Al Hosn Gas processing facilities produced 13,000 tons per day of sulfur, of which the Company’s net share was 5,200 tons per day of sulfur.

LOW-CARBON VENTURES

OLCV capitalizes on the Company’s extensive experience in utilizing CO2 in its development of CCUS projects and providing services to third parties to facilitate the implementation of their CCUS projects. Moreover, OLCV fosters emerging technologies, including DAC and low-emissions power sources, and other business models with the potential to position the Company as a leader in the production of lower carbon intensity energy and products.

The Company expects to begin sequestering CO2 captured at STRATOS, the first commercial-scale direct air capture facility in Ector County, Texas, in 2026. The Company holds permits for Class VI CO2 injection wells in support of STRATOS. The Company has a joint venture agreement with BlackRock, through a fund managed by its Diversified Infrastructure business, for the development of STRATOS. See Note 1 - Summary of Significant Accounting Policies.

OLCV has acquired access to over 0.3 million acres of pore space to date, and has continued to pursue permits for Class VI CO2 injection wells with the intention of developing additional sequestration hubs. OLCV continues to explore a number of projects to capture and sequester CO2, either from the atmosphere or from industrial point sources. The profitability of sequestration projects is dependent upon the costs of developing, building and operating sequestration infrastructure, demand for sequestration services from emitters and the availability of certain tax attributes and credits generated from the capture and storage of CO2.

The Company owns a 40.3% interest in NET Power Inc., an energy technology company focused on delivering low-carbon gas power solutions. NET Power is currently traded on the NYSE under the symbol “NPWR.”

OUTLOOK

Midstream and marketing segment results can experience volatility depending on commodity price changes, demand impacting export sales, the Midland-to-Gulf-Coast oil spreads and Waha-to-Gulf-Coast gas spreads. Gas gathering, processing and transportation results are affected by fluctuations in commodity prices and the volumes that are processed and transported through the segment’s plants, as well as the margins obtained on related services from investments in which the Company has an equity interest.

OLCV is affected by elements of supply chain and economy-wide cost increases that could increase the cost of sequestration. In addition, there is still uncertainty around recent legislation, such as the IRA and OBBBA, for certain tax credits related to low carbon businesses. For more information refer to the heading Income Taxes below.

 OXY 2025 FORM 10-K

35

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

SEGMENT RESULTS OF OPERATIONS AND ITEMS AFFECTING COMPARABILITY

SEGMENT RESULTS OF OPERATIONS

Segment earnings exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from divestitures of segment assets and income from segment equity investments. Seasonality is not a primary driver of changes in the Company’s consolidated quarterly earnings during the year.

The following table sets forth the sales and earnings of each operating segment and corporate items for the years ended December 31:

millions, except per share amounts

2025

2024

2023

NET SALES (a,b)

Oil and gas

$

20,902 

$

21,705 

$

21,284 

Midstream and marketing

1,279 

886 

2,433 

Eliminations

(588)

(572)

(561)

Total

$

21,593 

$

22,019 

$

23,156 

SEGMENT RESULTS AND EARNINGS (b)

Domestic

$

3,192 

$

3,715 

$

4,822 

International

1,643 

1,774 

1,859 

Exploration

(249)

(275)

(441)

Oil and gas

4,586 

5,214 

6,240 

Midstream and marketing

252 

563 

(35)

Total

$

4,838 

$

5,777 

$

6,205 

Unallocated corporate items

Interest expense, net

(1,079)

(1,169)

(957)

Income tax expense

(1,021)

(1,158)

(1,330)

Other

(631)

(584)

(586)

Income from continuing operations

$

2,107 

$

2,866 

$

3,332 

Discontinued operations, net

262 

212 

1,364 

Net income

2,369 

3,078 

4,696 

Less: Net income attributable to noncontrolling interests

(43)

(22)

— 

Less: Preferred stock dividends and redemption premiums

(679)

(679)

(923)

Net income attributable to common stockholders

$

1,647 

$

2,377 

$

3,773 

Net income attributable to common stockholders—basic

$

1.65 

$

2.59 

$

4.22 

Net income attributable to common stockholders—diluted

$

1.61 

$

2.44 

$

3.90 

(a)Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.

(b)Sales and net results related to the OxyChem Transaction are reflected in discontinued operations, net.

36

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

ITEMS AFFECTING COMPARABILITY

OIL AND GAS SEGMENT

Results of Operations

millions

2025

2024

2023

Segment Sales

$

20,902 

$

21,705 

$

21,284 

Segment Results (a)

Domestic

$

3,192 

$

3,715 

$

4,822 

International

1,643 

1,774 

1,859 

Exploration

(249)

(275)

(441)

Total

$

4,586 

$

5,214 

$

6,240 

Items affecting comparability

Gains (losses) on sales of assets and other, net - domestic (b)

$

(99)

$

(585)

$

142 

Legal reserves and other (c)

$

(105)

$

(54)

$

26 

Asset impairments and related items - domestic (d)

$

(6)

$

(334)

$

(209)

Gain on sales of assets and other, net - international

$

30 

$

— 

$

25 

(a)Results included significant items affecting comparability discussed in the footnotes below.

(b)The 2024 amount included $572 million of losses primarily related to the sale of non-core onshore U.S. assets. The 2023 amount included gains on sales primarily related to certain non-strategic assets in the Permian Basin of $142 million.

(c)The 2025 amount included additions to legal reserves and inventory adjustments.

(d)The 2024 amount included a pre-tax impairment of $334 million related to certain wells in the Gulf of America whose future net cash inflows did not indicate that the asset value is recoverable. The 2023 amount included a pre-tax impairment of $180 million related to undeveloped acreage in the northern non-core area of the Powder River Basin where the Company decided not to pursue future exploration and appraisal activities as well as a $29 million impairment related to an equity method investment in Black Butte Coal Company.

Domestic oil and gas results, excluding significant items affecting comparability, decreased in 2025, compared to 2024, primarily due to lower realized oil prices, partially offset by higher oil volumes, largely driven by a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024, and higher realized domestic gas prices. International oil and gas results, excluding significant items affecting comparability, decreased in 2025, compared to 2024, primarily due to lower oil and NGL prices, partially offset by higher oil volumes.

Average Realized Prices

The following table sets forth the average realized prices for oil, NGL and natural gas from ongoing operations for each of the three years in the period ended December 31, 2025, and includes a year-over-year change calculation:

2025

Year over Year Change

2024

Year over Year Change

2023

Average Realized Prices

Oil ($/Bbl)

United States

$

64.01 

(14)%

$

74.62 

(2)%

$

76.42 

International

$

67.93 

(12)%

$

77.46 

(2)%

$

79.03 

Total worldwide

$

64.60 

(14)%

$

75.05 

(2)%

$

76.85 

NGL ($/Bbl)

United States

$

19.96 

(3)%

$

20.48 

1%

$

20.19 

International

$

25.43 

(9)%

$

28.00 

(5)%

$

29.35 

Total worldwide

$

20.60 

(4)%

$

21.38 

—%

$

21.32 

Natural Gas ($/Mcf)

United States

$

1.58 

68%

$

0.94 

(54)%

$

2.04 

International

$

1.89 

—%

$

1.89 

1%

$

1.88 

Total worldwide

$

1.65 

40%

$

1.18 

(41)%

$

2.00 

 OXY 2025 FORM 10-K

37

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

Realized Price and Sales Volume Variance

The following table presents an analysis of the impacts of changes in average realized prices and sales volumes with regard to the Company’s domestic and international oil and gas revenue:

Increase (Decrease) Related to

millions

Year ended December 31, 2024

(a)

Price Realizations

Net Sales Volumes

Year ended December 31, 2025

(a)

United States Revenue

Oil

$

15,604 

$

(2,386)

$

1,241 

$

14,459 

NGL

1,865 

(21)

53 

$

1,897 

Natural gas

514 

498 

5 

$

1,017 

Total

$

17,983 

$

(1,909)

$

1,299 

$

17,373 

International Revenue

Oil

$

2,940 

$

(330)

$

105 

$

2,715 

NGL

390 

(34)

(4)

352 

Natural gas

361 

3 

(12)

352 

Total

$

3,691 

$

(361)

$

89 

$

3,419 

(a)    Results excluded “other” oil and gas revenue. See Note 2 - Revenue in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional information regarding other revenue.

Production

The following table sets forth the production volumes of oil, NGL and natural gas per day for each of the three years in the period ended December 31, 2025, and includes a year-over-year change calculation:

Production per Day (Mboe/d)

2025

Year over Year Change

2024

Year over Year Change

2023

United States

Permian

786 

18 

%

664 

14 

%

584 

Rockies & Other Domestic

284 

(8)

%

310 

14 

%

271 

Gulf of America

132 

6 

%

125 

(14)

%

145 

Total

1,202 

9 

%

1,099 

10 

%

1,000 

International

Algeria & Other International

31 

(3)

%

32 

(9)

%

35 

Al Hosn Gas

89 

(2)

%

91 

10 

%

83 

Dolphin

40 

3 

%

39 

— 

%

39 

Oman

72 

9 

%

66 

— 

%

66 

Total

232 

2 

%

228 

2 

%

223 

Total Production (Mboe/d) (a)

1,434 

8 

%

1,327 

9 

%

1,223 

(a)Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil. Boe equivalence does not necessarily result in price equivalence. Please refer to the Supplemental Oil and Gas Information (unaudited) section of this Form 10-K for additional information on oil and gas production and sales.

Average daily production volumes increased by 8% in 2025, compared to 2024. The increase in production was primarily driven by a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024.

Lease Operating Expense

The following table sets forth the average lease operating expense per Boe for each of the three years in the period ended December 31, 2025:

2025

2024

2023

Average lease operating expense per Boe

$

8.94 

$

9.75 

$

10.48 

38

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

Average lease operating expense per Boe decreased in 2025, compared to 2024, primarily due to operational efficiencies in the Permian Basin and lower energy costs in Oman.

MIDSTREAM AND MARKETING SEGMENT

millions

2025

2024

2023

Segment Sales

$

1,279 

$

886 

$

2,433 

Segment Results (a)

$

252 

$

563 

$

(35)

Items affecting comparability

Gains on sales of assets and other, net (b)

$

301 

$

647 

$

51 

Equity method investments fair value gains

$

61 

$

27 

$

— 

Derivative losses, net

$

(29)

$

(32)

$

(14)

Asset impairments and other charges, net (c)

$

(487)

$

(21)

$

(60)

Acquisition-related costs (d)

$

— 

$

— 

$

(20)

Carbon Engineering fair value gain (d)

$

— 

$

— 

$

283 

(a)Results included significant items affecting comparability discussed in the footnotes below.

(b)The 2025 amount included a gain of $301 million resulting from pro-rata ownership reduction in WES following an acquisition by WES. The 2024 and 2023 amounts included gains on sale of $489 million and $51 million, respectively, from the sales of 19.5 million and 5.1 million limited partner units in WES, respectively. The 2024 amount also included $158 million of income from equity investments and other related to the Company’s share of WES’ gains on its asset divestitures.

(c)The 2025, 2024 and 2023 amounts primarily included the Company’s proportionate amounts from impairments and other charges recorded by its equity method investees.

(d)The 2023 amount included a gain of $283 million from the remeasurement of the noncontrolling interest held prior to the Carbon Engineering acquisition to fair value and acquisition-related costs of $20 million.

Midstream and marketing segment results, excluding items affecting comparability, increased in 2025, compared to 2024, due to higher sulfur prices at Al Hosn, higher gas margins from transportation capacity optimization in the Permian Basin, and lower long-haul crude transportation costs, partially offset by higher losses from equity method investees and higher expenses related to the increase in OLCV activities.

CORPORATE

Significant corporate items include the following:

millions

2025

2024

2023

Items Affecting Comparability

Acquisition-related costs(a)

$

(13)

$

(150)

$

(6)

Early retirement plan

$

(39)

$

— 

$

— 

Early debt extinguishment

$

20 

$

— 

$

— 

Gains on sales of assets and other, net

$

— 

$

48 

$

— 

(a)The 2024 amount included $66 million of financing costs related to the CrownRock Acquisition and the remaining amounts were related to CrownRock transaction costs. The 2023 amount related to costs incurred for the CrownRock Acquisition.

DISCONTINUED OPERATIONS

Significant discontinued operations items include the following:

millions

2025

2024

2023

Discontinued operations, net of taxes

$

262 

$

212 

$

1,364 

Items Affecting Comparability(a)

$

(283)

$

(622)

$

204 

(a)The 2025 amount included a one-time foreign income tax charge of $101 million and adjustments to legal reserves of $142 million, net of taxes. The 2024 amount included $725 million, net of taxes, related to an increase in the DASS environmental remediation reserve retained in the OxyChem Transaction, partially offset by a gain of $182 million, net of taxes, resulting from a legal settlement related to the Andes Arbitration. The 2023 amount related to a $204 million, net of taxes, remeasurement of the valuation allowance established against the Company’s claims against Maxus. Refer to Note 11 - Environmental Liabilities and Expenditures and Note 12 - Lawsuits, Claims, Commitments and Contingencies for additional details.

CONSOLIDATED RESULTS OF OPERATIONS

 OXY 2025 FORM 10-K

39

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

REVENUE AND OTHER INCOME ITEMS

millions

2025

2024

2023

Net sales

$

21,593 

$

22,019 

$

23,156 

Interest, dividends and other income

$

219 

$

192 

$

153 

Gains (losses) on sales of assets and other, net

$

263 

$

(16)

$

522 

NET SALES

Revenue declined from 2024 to 2025, primarily as a result of lower crude oil prices in the oil and gas segment, partially offset by increased sales volumes due to a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024, and higher domestic natural gas prices. Additionally, midstream and marketing revenue improved year over year due to higher sulfur prices at Al Hosn and enhanced natural gas margins.

GAINS (LOSSES) ON SALES OF ASSETS AND OTHER, NET

Gains (losses) on sales of assets and other, net increased from 2024 to 2025, primarily as a result of a gain of $301 million from a fourth quarter pro-rata ownership reduction in WES following an acquisition by WES.

EXPENSE ITEMS

millions

2025

2024

2023

Oil and gas operating expense

$

4,681 

$

4,738 

$

4,677 

Transportation and gathering expense

$

1,660 

$

1,608 

$

1,481 

Purchased commodities and midstream cost of sales

$

176 

$

431 

$

2,116 

Selling, general and administrative

$

986 

$

960 

$

987 

Other operating and non-operating expense

$

1,556 

$

1,319 

$

1,165 

Taxes other than on income

$

1,030 

$

1,039 

$

1,087 

Depreciation, depletion and amortization

$

7,533 

$

6,951 

$

6,449 

Asset impairments and other charges

$

60 

$

356 

$

209 

Acquisition-related costs

$

13 

$

84 

$

26 

Exploration expense

$

249 

$

275 

$

441 

Interest and debt expense, net

$

1,079 

$

1,169 

$

957 

PURCHASED COMMODITIES AND MIDSTREAM COST OF SALES

Purchased commodities and midstream cost of sales decreased in 2025, compared to 2024, due to certain crude supply contracts which expired in 2024.

OTHER OPERATING AND NON-OPERATING EXPENSE

Other operating and non-operating expense increased in 2025, compared to 2024, primarily due to higher compensation costs, adjustments to legal reserves, and increased research and development activities.

DEPRECIATION, DEPLETION, AND AMORTIZATION

Depreciation, depletion and amortization increased in 2025, compared to 2024, primarily related to increased sales volumes due to a full year of production in 2025 related to the CrownRock Acquisition, which closed in August 2024.

ASSET IMPAIRMENTS AND OTHER CHARGES

Asset impairments in 2024 included $334 million related to certain wells in the Gulf of America whose future net cash inflows did not indicate that the asset value is recoverable.

OTHER ITEMS

Income (expense) millions

2025

2024

2023

Income from equity investments and other

$

76 

$

759 

$

426 

Income tax expense

$

(1,021)

$

(1,158)

$

(1,330)

Discontinued operations, net

$

262 

$

212 

$

1,364 

40

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

INCOME FROM EQUITY INVESTMENTS AND OTHER

Income from equity investments and other decreased in 2025, compared to 2024, primarily due to the Company’s proportionate amount of impairments and other charges recorded by its equity method investees.

DISCONTINUED OPERATIONS, NET

Discontinued operations, net for all periods presented resulted from the OxyChem Transaction that closed on January 2, 2026. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.

Discontinued operations, net in 2024 also included a gain of $182 million, net of taxes, from the Andes Arbitration final legal settlement. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.

Select results for discontinued operations are reflected in the following table:

millions

2025

2024

2023

Income before income taxes

$

495 

$

285 

$

1,767 

Income tax expense

(233)

(73)

(403)

Income from discontinued operations, net of tax

$

262 

$

212 

$

1,364 

Effective tax rate

47 

%

26 

%

23 

%

Income before income taxes increased in 2025, compared to 2024, due to a 2024 pre-tax charge related to the DASS environmental remediation reserve of $925 million, partially offset by a gain of $239 million from the Andes Arbitration legal settlement in 2024 and lower chemical sales and higher raw material costs in 2025. Income taxes and the effective tax rate for discontinued operations increased from 2024 to 2025 primarily due to international tax charges as a result of the OxyChem Transaction.

 OXY 2025 FORM 10-K

41

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

INCOME TAXES

Total deferred tax assets, after valuation allowance, were $2.6 billion and $2.4 billion as of December 31, 2025 and 2024, respectively. The Company expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The total deferred tax liabilities were $8.2 billion and $7.7 billion as of December 31, 2025 and 2024, respectively. See Note 9 - Income Taxes in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.

WORLDWIDE EFFECTIVE TAX RATE

The following table sets forth the calculation of the worldwide effective tax rate for income from continuing operations:

millions

2025

2024

2023

Income from continuing operations before taxes

$

3,128 

$

4,024 

$

4,662 

Income tax benefit (expense)

Federal and state

(437)

(586)

(588)

Foreign

(584)

(572)

(742)

Total income tax expense

(1,021)

(1,158)

(1,330)

Income from continuing operations

$

2,107 

$

2,866 

$

3,332 

Worldwide effective tax rate

33%

29%

28%

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

LEGAL ENTITY REORGANIZATION

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

RECENT TAX LEGISLATION

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

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

42

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

LIQUIDITY AND CAPITAL RESOURCES

SOURCES AND USES OF CASH

The Company currently expects its operational cash flows and cash on hand to be sufficient to meet its current debt maturities and other obligations for the next 12 months from the date of this filing. As of December 31, 2025, the Company’s sources of liquidity included $2.0 billion of cash and cash equivalents and $4.15 billion of borrowing capacity under its RCF. Subsequent to December 31, 2025, but before the date of this filing, the Company used proceeds from the OxyChem Transaction to pay or satisfy and discharge the remaining balance of the term loan of $1.3 billion, current maturities of $270 million, and long-term maturities of $3.8 billion, leaving principal debt outstanding of $15 billion. Following these repayments, $24 million is due in 2026, $48 million in 2027, $14 million in 2028, $367 million in 2029 and $14.6 billion due in 2030 and thereafter.

The Company’s RCF expires on June 30, 2028, and has a borrowing capacity of $4.15 billion. There were no borrowings outstanding on the Company’s RCF as of December 31, 2025. As of December 31, 2025, and through the date of this filing, the Company was in compliance with all covenants in its financing agreements.

The Company’s planned 2026 capital expenditures are between $5.5 billion and $5.9 billion.

The Company is party to various purchase agreements that are not accounted for as leases or otherwise accrued as liabilities as of December 31, 2025. These agreements consist primarily of obligations to secure terminal, pipeline and processing capacity, purchase services used in the normal course of business including transporting and disposing of produced water, purchase goods used in oil and gas production and agreements relating to equipment maintenance and service. Refer to the line item “Purchase Obligations” in the table below under Contractual Obligations for the amounts that will be paid for such outstanding off-balance sheet purchase obligations from 2025 and thereafter.

CONTRACTUAL OBLIGATIONS

The following table summarizes and cross-references the Company’s contractual obligations and indicates on- and off-balance sheet obligations as of December 31, 2025. Commitments related to discontinued operations and liabilities of held for sale assets are excluded.

millions

Payments Due by Year

Total

2026

2027 and 2028

2029 and 2030

2031 and

thereafter

On-Balance Sheet

Current portion of long-term debt (Note 5)

$

1,575 

$

1,575 

$

— 

$

— 

$

— 

Long-term debt (Note 5) (a)

18,852 

— 

2,411 

4,373 

12,068 

Expected interest payments on debt (b)

11,616 

1,213 

2,197 

1,884 

6,322 

Leases (Note 6) (c)

2,212 

635 

893 

390 

294 

Asset retirement obligations (Note 1)

4,553 

381 

535 

677 

2,960 

Other long-term liabilities (d)

3,057 

— 

702 

244 

2,111 

Off-Balance Sheet

Purchase obligations (e)

12,617 

3,038 

4,699 

2,627 

2,253 

Total

$

54,482 

$

6,842 

$

11,437 

$

10,195 

$

26,008 

(a)Excluded unamortized debt premium, net, debt issuance costs and interest.

(b)As noted above, the Company has repaid or otherwise discharged $5.4 billion subsequent to December 31, 2025. Taking into account these debt repayments, expected interest payments on debt would be $934 million in 2026, $1.9 billion in 2027 and 2028, $1.8 billion in 2029 and 2030, and $6.3 billion in 2031 and thereafter, for a total of $10.9 billion.

(c)The Company is the lessee under various agreements for real estate, equipment, plants and facilities.

(d)Included long-term obligations under postretirement benefits, accrued transportation commitments, ad valorem taxes and other accrued liabilities.

(e)Amounts included payments which will become due under long-term agreements to purchase goods and services used in the normal course of business including, but not limited to, capital commitments to secure terminal, pipeline and processing capacity, CO2, drilling rigs and services, electrical power and non-lease components. Amounts excluded certain product purchase obligations related to marketing activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Long-term purchase contracts were discounted at a 5.44% discount rate.

 OXY 2025 FORM 10-K

43

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

GUARANTEES

The Company has entered into various commitments, indemnities and guarantees provided by the Company to third parties, mainly to provide assurance that the Company or its consolidated subsidiaries or affiliates will meet their various obligations. In addition, the Company has entered into certain covenants, indemnities and guarantees related to the OxyChem Transaction. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional details.

As of the date of this filing, the Company has provided required financial assurance through a combination of cash, letters of credit and surety bonds. The Company has not issued any letters of credit under the RCF or other committed facilities. For additional information, see Risk Factors in Part I Item 1A of this Form 10-K.

CASH FLOW ANALYSIS

CASH PROVIDED BY OPERATING ACTIVITIES

millions

2025

2024

2023

Operating cash flow from continuing operations

$

9,606 

$

10,519 

$

10,235 

Operating cash flow from discontinued operations

926 

920 

2,073 

Net cash provided by operating activities

$

10,532 

$

11,439 

$

12,308 

Continuing Operations

Cash flow provided by operating activities from continuing operations decreased in 2025, compared to 2024, primarily driven by higher use of cash in working capital related to higher tax payments in 2025, as certain 2024 tax payments were deferred into 2025 under the federal disaster relief program following 2024 Hurricane Beryl, and timing of payments for accounts payable and accrued liabilities.

Discontinued Operations

Cash flow provided by operating activities from discontinued operations was $926 million, $920 million and $2.1 billion in 2025, 2024 and 2023, respectively, primarily due to chemical segment income. In addition, the 2024 amount included a gain of $239 million from the Andes Arbitration legal settlement.

CASH USED BY INVESTING ACTIVITIES

millions

2025

2024

2023

Capital expenditures

Oil and gas

$

(5,615)

$

(5,320)

$

(4,960)

Midstream and marketing

(720)

(869)

(641)

Corporate

(92)

(74)

(95)

Total

$

(6,427)

$

(6,263)

$

(5,696)

Changes in capital accrual

32 

100 

(22)

Purchase of businesses, assets and equity investments, net

(280)

(9,117)

(713)

Proceeds from sale of assets and equity investments, net

2,278 

1,673 

447 

Other investing activities, net

(286)

(214)

(479)

Investing cash flow from continuing operations

$

(4,683)

$

(13,821)

$

(6,463)

Investing cash flow from discontinued operations

(1,116)

(769)

(517)

Net cash used by investing activities

$

(5,799)

$

(14,590)

$

(6,980)

Continuing Operations

Cash flow used by investing activities from continuing operations decreased by $9.1 billion in 2025 compared to 2024, The decrease was primarily attributable to the cash portion of the CrownRock Acquisition, which was paid in 2024.

Capital expenditures of $6.4 billion in 2025 were primarily related to continued development in the oil and gas segment, which included $3.4 billion related to the Permian Basin, $0.8 billion related to the Rockies, $0.5 billion related to GOA and the remainder to international locations. In 2024, capital expenditures of $6.3 billion were primarily related to development in

44

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

the oil and gas segment, which included $3.1 billion related to the Permian Basin, $0.9 billion related to the Rockies, $0.8 billion related to GOA, and the remainder to international locations.

Midstream capital expenditures were primarily related to the completion of central processing facilities and continued work on Trains 3 and 4 at STRATOS.

The Company purchased $280 million of assets in 2025 primarily related to oil and gas properties, compared to $9.1 billion in 2024 of which $8.8 billion was related to the CrownRock Acquisition.

In 2025, the Company sold non-core assets for $2.3 billion, which included working interests in the Permian Basin for proceeds of approximately $800 million, non-operated proved and unproved royalty and mineral interests in the DJ Basin for proceeds of approximately $840 million and certain gas gathering assets in the Permian Basin for approximately $580 million. In 2024, the Company sold non-core assets in the Powder River Basin with near- to intermediate-term lease expirations and certain Delaware Basin assets in Texas and New Mexico for combined net proceeds of $769 million and 19.5 million of its limited partner units in WES for proceeds of $697 million. See Note 4 - Acquisitions, Divestitures and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for a listing of assets and equity investments acquired and sold in 2025, 2024 and 2023.

Discontinued Operations

Cash flow used by investing activities from discontinued operations in 2025, 2024 and 2023 was $1.1 billion, $769 million and $517 million, respectively, primarily due to capital expenditures associated with OxyChem.

CASH PROVIDED (USED) BY FINANCING ACTIVITIES

millions

2025

2024

2023

Proceeds from debt issuance

$

— 

$

9,612 

$

(46)

Payments of debt

(3,754)

(4,514)

(22)

Preferred stock redemption

— 

— 

(1,661)

Purchases of treasury stock

— 

(27)

(1,798)

Cash dividends paid

(1,594)

(1,446)

(1,365)

Proceeds from issuance of common stock

966 

584 

135 

Other financing activities, net

(453)

(360)

(129)

Financing cash flow from continuing operations

(4,835)

3,849 

(4,886)

Financing cash flow from discontinued operations

(9)

(5)

(4)

Net cash provided (used) by financing activities

$

(4,844)

$

3,844 

$

(4,890)

In 2025, cash used by financing activities included payments of debt of $3.8 billion, dividends of $1.6 billion, and the final deferred payment for the Carbon Engineering acquisition of $0.4 billion. These payments were partially offset by proceeds from the issuance of stock of $1.0 billion, mainly from exercises of common stock warrants, and $200 million of contributions from noncontrolling interest related to the BlackRock joint venture for STRATOS.

Net cash provided by financing activities was $3.8 billion in 2024, which included net proceeds from debt issuance of $9.6 billion and proceeds from the issuance of common stock of $584 million primarily related to common stock warrant exercises, offset by debt repayment of $4.5 billion and cash dividends paid on common and preferred stock of $1.4 billion. See Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities in Part II of this Form 10-K and Note 13 - Stockholders’ Equity in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional information related to the Company’s share repurchases.

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

LEGAL MATTERS

For information on the Company’s Lawsuits, Claims, Commitments and Contingencies, see the information in Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.

 OXY 2025 FORM 10-K

45

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

ENVIRONMENTAL EXPENDITURES

Environmental expenditures relate to the prevention, monitoring, control, treatment or abatement of waste, spills, emissions or releases to air, water or land from the Company’s operations. These activities are generally integrated with ongoing operations or development projects and therefore are estimated using definitions and guidelines established by the American Petroleum Institute. The Company estimated the environmental expenditures to be approximately $874 million in 2025 compared to $663 million in 2024. Included in these expenditures were $402 million and $222 million in 2025 and 2024, respectively, related to longer-lived improvements in properties currently operated by the Company. They also included $472 million of operating expenses in 2025 and $441 million in 2024, which are incurred on a continual basis. While the Company does not expect these costs to fluctuate significantly in the near term, changes in environmental regulations may increase these costs. The environmental expenditures do not include litigation-related costs, including fines, penalties or settlements, the Company’s investments in low-carbon ventures, costs incurred to satisfy asset retirement obligations, or remediation expenses.

The Company’s remediation expenses related to ongoing operations, which are not included in the expenditures above, were $18 million in 2025 and $20 million in 2024. For discontinued operations, these costs were $64 million in 2025 and $56 million in 2024.

For additional information on the Company’s Environmental Liabilities and Expenditures, see the information in Note 11 - Environmental Liabilities and Expenditures in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.

GLOBAL INVESTMENTS

A portion of the Company’s assets are located outside North America. The following table shows the geographic distribution of the Company’s assets as of December 31, 2025, at both the segment and consolidated level:

millions

Oil and gas

Midstream and marketing

Corporate and other

Assets Held for Sale

Total Consolidated

North America

United States

$

55,735 

$

9,229 

$

3,372 

$

6,340 

$

74,676 

Canada

— 

1,638 

— 

85 

$

1,723 

Middle East

3,743 

2,861 

— 

— 

$

6,604 

North Africa and Other

915 

173 

— 

95 

$

1,183 

Consolidated

$

60,393 

$

13,901 

$

3,372 

$

6,520 

$

84,186 

In 2025, net sales outside North America totaled $4.2 billion, or approximately 19% of total net sales, excluding discontinued operations.

46

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The process of preparing financial statements in accordance with United States GAAP requires the Company’s management to make informed estimates and judgments regarding certain items and transactions. Changes in facts and circumstances or discovery of new information may result in revised estimates and judgments and actual results may differ from these estimates upon settlement, but generally not by material amounts. The selection and development of these policies and estimates have been discussed with the Audit Committee of the Board of Directors. The Company considers the following to be its most critical accounting policies and estimates that involve management’s judgment.

OIL AND GAS PROPERTIES

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

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

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

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

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Several factors could change the Company’s proved oil and gas reserves. For example, the Company receives a share of production from PSCs to recover its costs and generally an additional share for profit. The Company’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Generally, the Company’s net economic benefit from these contracts is greater at higher product prices. In other cases, particularly with long-lived properties, lower product prices may lead to a situation where production of a portion of proved reserves becomes uneconomical. For such properties, higher product prices typically result in additional reserves becoming economical. Estimation of future production and development costs is also subject to change partially due to factors beyond the Company’s control, such as energy costs and inflation or deflation of oilfield service costs. These factors, in turn, could lead to changes in the quantity of proved reserves. Additional factors that could result in a change of proved reserves include production decline rates and operating performance differing from those estimated when the proved reserves were initially recorded. Changes in the political and regulatory climate, including new or amended laws and regulations or changes in the interpretation of those laws and regulations, could lead to decreases in proved reserves as development horizons may be extended into the future, changes to development locations may be necessary or such changes may result in higher development or operating costs.

The Company performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to significant and prolonged declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped on a field-by-field basis or by logical grouping of assets if there is a significant shared infrastructure. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change

 OXY 2025 FORM 10-K

47

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

significantly over time. These assumptions include estimates of future production, product prices, contractual prices, estimates of risk-adjusted oil and gas proved and unproved reserves and estimates of future operating and development costs. It is reasonably possible that prolonged declines in commodity prices, reduced capital spending in response to lower prices, or increases in operating costs could result in impairments.

For impairment testing, unless prices are contractually fixed, the Company uses observable forward strip prices for oil and natural gas prices when projecting future cash flows. Future operating and development costs are estimated using the current cost environment applied to expectations of future operating and development activities to develop and produce oil and gas reserves. Market prices for oil, NGL and natural gas have been volatile and may continue to be volatile in the future. Changes in global supply and demand, transportation capacity, currency exchange rates, applicable laws and regulations and the effect of changes in these variables on market perceptions could impact current forecasts. Future fluctuations in commodity prices could cause estimates of future cash flows to vary significantly.

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

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

PROVED RESERVES

The Company estimates its proved oil and gas reserves according to the definition of proved reserves provided by the SEC’s Rule 4-10 (a) of Regulation S-X and the Financial Accounting Standards Board. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Prices include consideration of price changes provided only by contractual arrangements and do not include adjustments based on expected future conditions. For reserves information, see the Supplemental Information on Oil and Gas Exploration and Production Activities under Item 8 of this Form 10-K.

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, development plans, reservoir performance, prices, economic conditions and government restrictions as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volume of proved reserves could have a negative impact on DD&A and could result in property impairments.

The most significant ongoing financial statement effect from a change in the Company’s oil and gas reserves or impairment of its proved properties would be to the DD&A rate. For example, a 5% increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $0.65/Boe, which would increase or decrease pre-tax income by approximately $350 million annually at current production rates.

FAIR VALUES

The Company estimates fair-value of long-lived assets for impairment testing, assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, pension plan assets and initial measurements of AROs.

48

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value, which may be determined using different methods of fair value measurements, largely based on the availability and quality of market information. The Company primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs.

FINANCIAL ASSETS AND LIABILITIES

The Company utilizes published prices or counterparty statements for valuing the majority of its financial assets and liabilities measured and reported at fair value. In addition to using market data, the Company makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For financial assets and liabilities carried at fair value, the Company measures fair value using the following methods:

■The Company values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as using quoted prices in active markets for the assets or liabilities (Level 1).

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

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

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

NON-FINANCIAL ASSETS

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

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

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

 OXY 2025 FORM 10-K

49

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

environmental remediation costs in income when received, or when receipt of recovery is highly probable.

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

Certain sites involve multiple parties with various cost-sharing arrangements, which generally fall into the following three categories: (i) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among the Company and other alleged potentially responsible parties; (ii) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (iii) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, the affected subsidiary evaluates the financial viability of other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to such subsidiary of their failure to participate when estimating its ultimate share of liability. The Company records environmental remediation liabilities at their expected net cost of remedial activities. Based on these factors, except as otherwise disclosed in Note 11 - Environmental Liabilities and Expenditures in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K, the Company believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

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

If the Company were to adjust the balance of their environmental remediation liabilities based on the factors described above, the amount of the increase or decrease would be recognized in earnings. For example, if the balance were increased or reduced by 10%, the Company would record a pre-tax decrease or increase, respectively, to income of approximately $190 million.

INCOME TAXES

The Company files various U.S. federal, state and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). See Note 9 - Income Taxes in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.

LOSS CONTINGENCIES

The Company is involved in the normal course of business, in lawsuits, claims and other legal proceedings and audits. The Company accrues reserves as appropriate for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, the Company discloses, in aggregate on a consolidated basis, exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. The Company reviews such loss contingencies on an ongoing basis.

Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings or other factors. See Note 12 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for additional information.

50

 OXY 2025 FORM 10-K

table of contents

MANAGEMENT’S DISCUSSION AND ANALYSIS

SAFE HARBOR DISCUSSION REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA

Portions of this report contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to: any projections of earnings, revenue or other financial items or future financial position or sources of financing; any statements of the plans, strategies and objectives of management for future operations or business strategy; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing. Words such as “estimate,” “project,” “predict,” “will,” “would,” “should,” “could,” “may,” “might,” “anticipate,” “plan,” “intend,” “believe,” “expect,” “aim,” “goal,” “target,” “objective,” “commit,” “advance,” “guidance,” “priority,” “focus,” “assumption,” “likely” or similar expressions that convey the prospective nature of events or outcomes are generally indicative of forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report unless an earlier date is specified. Unless legally required, the Company does not undertake any obligation to update, modify or withdraw any forward-looking statement as a result of new information, future events or otherwise.

Actual outcomes or results may differ from anticipated results, sometimes materially. Forward-looking and other statements regarding the Company’s sustainability efforts and aspirations are not an indication that these statements are necessarily material to investors or require disclosure in Occidental’s filings with the SEC. In addition, historical, current and forward-looking sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and definitions, assumptions, data sources and estimates or measurements that are subject to change in the future, including through rulemaking or guidance. Factors that could cause results to differ from those projected or assumed in any forward-looking statement include, but are not limited to: general economic conditions, including slowdowns and recessions, domestically or internationally; the Company’s indebtedness and other payment obligations, including the need to generate sufficient cash flows to fund operations; the Company’s ability to successfully monetize select assets and repay or refinance debt and the impact of changes in the Company’s credit ratings or future increases in interest rates; assumptions about energy markets; global and local commodity and commodity-futures pricing fluctuations and volatility; supply and demand considerations for, and the prices of, the Company’s products and services; actions by OPEC and non-OPEC oil producing countries; results from operations and competitive conditions; future impairments of the Company’s proved and unproved oil and gas properties or equity investments, or write-downs of productive assets, causing charges to earnings; unexpected changes in costs; government actions (including the effects of announced or future tariff increases and other geopolitical, trade, tariff, fiscal and regulatory uncertainties), war (including the Russia-Ukraine war and conflicts in the Middle East) and political conditions and events (such as in Latin America); inflation, its impact on markets and economic activity and related monetary policy actions by governments in response to inflation; availability of capital resources, levels of capital expenditures and contractual obligations; the regulatory approval environment, including the Company’s ability to timely obtain or maintain permits or other government approvals, including those necessary for drilling and/or development projects; the Company’s ability to successfully complete, or any material delay of, field developments, expansion projects, capital expenditures, efficiency projects, acquisitions or divestitures; risks associated with acquisitions, mergers and joint ventures, such as difficulties integrating businesses, uncertainty associated with financial projections or projected synergies, restructuring, increased costs and adverse tax consequences; uncertainties and liabilities associated with acquired and divested properties and businesses, including retained liabilities and indemnification obligations associated with the chemical business; uncertainties about the estimated quantities of oil, NGL and natural gas reserves; lower-than-expected production from development projects or acquisitions; the Company’s ability to realize the anticipated benefits from prior or future streamlining actions to reduce fixed costs, simplify or improve processes and improve the Company’s competitiveness; exploration, drilling and other operational risks; disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver the Company’s oil and natural gas and other processing and transportation considerations; volatility in the securities, capital or credit markets, including capital market disruptions and instability of financial institutions; HSE risks, costs and liability under existing or future federal, regional, state, provincial, tribal, local and international HSE laws, regulations and litigation (including related to climate change or remedial actions or assessments); legislative or regulatory changes, including changes relating to hydraulic fracturing or other oil and natural gas operations, retroactive royalty or production tax regimes, and deep-water and onshore drilling and permitting regulations; the Company’s ability to recognize intended benefits from its business strategies and initiatives, such as the OxyChem Transaction, the Company’s low-carbon ventures businesses and announced GHG emissions reduction targets or net-zero goals; changes in government grant or loan programs; potential liability resulting from pending or future litigation, government investigations and other proceedings; disruption or interruption of production or facility damage due to accidents, chemical releases, labor unrest, weather, power outages, natural disasters, cyber-attacks, terrorist acts or insurgent activity; the scope and duration of global or regional health pandemics or epidemics and actions taken by government authorities and other third parties in connection therewith; the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners and other parties; failure of risk management; the Company’s ability to retain and hire key personnel; supply, transportation and labor constraints; reorganization or restructuring of the Company’s operations; changes in state, federal or international tax rates, deductions, incentives or credits; and actions by third parties that are beyond the Company’s control.

Additional information concerning these and other factors that may cause the Company’s results of operations and financial position to differ from expectations can be found in Item 1A, “Risk Factors” and elsewhere in this Form 10-K, as well as in the Company’s other filings with the SEC, including the Company’s Quarterly Reports on Form 10-Q and Current Reports on Form 8-K.

 OXY 2025 FORM 10-K

51

table of contents

QUANTITATIVE AND QUALITATIVE DISCLOSURES