OCCIDENTAL PETROLEUM CORP DE

OIL AND GAS SEGMENT

Occidental’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, Occidental’s operations benefit from scale, technical expertise, decades of high-margin inventory, HSE leadership and commercial and governmental collaboration. These attributes allow Occidental to bring additional production quickly to market, extend the life of older fields at lower costs and provide low-cost returns-driven growth opportunities with advanced technology.

Occidental 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 advantages that Occidental’s portfolio provides, coupled with its advanced subsurface characterization expertise and the proven ability to execute, position it for full-cycle success in the years ahead. The oil and gas segment maximizes efficiencies to deliver lower breakeven costs and generate excess free cash flow and also strives to achieve low development and operating costs to maximize full-cycle value of the assets.

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

■Operating and developing areas where reserves are known to exist and optimizing capital intensity in core areas, primarily in the Permian Basin, DJ Basin, Gulf of America, Algeria, Oman, Qatar and the UAE;

■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 Occidental’s existing positions;

■Focusing Occidental’s subsurface characterization and technical activities on both conventional and unconventional resources;

■Using secondary and tertiary recovery techniques in mature fields; and

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

In 2024, oil and gas capital expenditures, including exploration, were approximately $5.3 billion and primarily focused on Occidental’s assets in the Permian Basin, DJ Basin, Gulf of America and Oman. In 2025, Occidental plans to spend $5.8 billion to $6.0 billion to develop its oil and gas assets.

In August 2024, Occidental acquired CrownRock for total consideration of $12.4 billion, consisting of $9.4 billion of cash consideration (inclusive of certain working capital and other customary purchase price adjustments), 29.6 million shares of common stock of Occidental, and the assumption of $1.2 billion of existing debt of CrownRock, adding to Occidental's oil and gas portfolio in the Permian Basin.

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 2024 and 2023:

The following table presents Occidental’s average realized prices for continuing operations as a percentage of WTI, Brent and NYMEX for 2024 and 2023:

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

Occidental conducts its domestic operations through land leases, subsurface mineral rights it owns, or a combination of both. Occidental’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. Occidental has leasehold and mineral interests in 9.3 million net acres, of which approximately 51% is leased, 48% is owned subsurface mineral rights and 1% is owned land with mineral rights. Approximately $5.0 billion of Occidental’s worldwide capital budget is expected to be allocated to its domestic oil and gas operations in 2025.

DOMESTIC ASSETS(a)

1. Powder River Basin2. DJ Basin3. Permian Basin4. Gulf of America

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

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 47% of total United States oil production in 2024. Occidental had a leading position in the Permian Basin, and produced approximately 10% of the total oil in the basin in 2024. In 2024, Occidental’s production in the Permian Basin was 664 Mboe/d. In 2024, Occidental spent approximately $2.7 billion of development capital in the Permian Basin, of which 88% was spent on Permian Resources assets.

Occidental 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, Occidental 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. Occidental strengthened its oil and gas portfolio through the acquisition of CrownRock’s well-positioned assets in the Permian Basin. Occidental’s unconventional oil and gas operations in Permian Resources include approximately 1.5 million net acres. In 2024, Occidental’s activities were focused in the core development areas with emphasis on maintaining the industry leading capital intensity through optimized surface infrastructure and customized well designs. In 2024, Permian Resources produced from approximately 6,100 gross wells and added 356 MMboe to Occidental’s proved reserves through infill development projects and extensions of proved areas.

The Permian Basin’s concentration of large conventional reservoirs, strong CO 2 flooding performance and the expansive CO 2 transportation and processing infrastructure has resulted in decades of high-value enhanced oil production.

With 33 active CO 2 floods and over 50 years of experience, Permian EOR is the industry leader in Permian Basin CO 2 flooding, which can increase ultimate oil recovery by 10% to 25%. Technology improvements, such as the recent trend toward vertical expansion of the CO 2 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 Occidental’s existing CO 2 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 CO 2 projects, which could be developed over the next 20 years or accelerated, depending on market conditions. Permian EOR produced from approximately 12,600 gross wells in 2024.

Rockies and Other Domestic

In 2024, Occidental produced 310 Mboe/d and spent development capital of approximately $0.8 billion in the Rockies and Other Domestic locations. Production in the DJ Basin is derived from approximately 3,700 wells primarily focused in the Niobrara and Codell formations. The DJ Basin, including the North DJ Basin, comprises approximately 0.6 million total net acres and provides competitive economics, low breakeven costs and free cash flow generation through Occidental’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. Occidental has 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. Occidental 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 2024, Occidental submitted Oil and Gas Development Plans comprising approximately 200 wells to the ECMC. As of December 31, 2024, Occidental has permits for over 90% of the 2025 drilling schedule and over 70% of the 2026 drilling schedule with the remaining percentage of activity largely submitted and pending approval. Occidental continues to gain efficiencies in the permitting process and will continue to look for additional opportunities to do so in the future.

Occidental has interests in approximately 0.1 million net acres in the Powder River Basin, mainly located in Converse County and Campbell County, Wyoming. The field contains the Turner, Niobrara, Mowry and Parkman formations that hold both liquids and natural gas.

Occidental holds approximately 4.6 million net acres in other domestic locations, which consist of acreage and fee minerals outside of Occidental’s core operated areas including parts of Arkansas, Colorado, Louisiana, Texas, West Virginia and Wyoming.

OFFSHORE DOMESTIC ASSETS

Gulf of America

The Gulf of America accounts for more than 14% of total United States oil production. Occidental is the fourth-largest oil and gas producer in the deepwater Gulf of America, operating 8 strategically located deepwater floating platforms and producing from 16 active fields while owning a working interest in approximately 300 blocks, covering approximately 1.1 million net acres.

In 2024, Occidental’s Gulf of America production was 125 Mboe/d from 82 gross wells. Occidental’s focused production management and artificial lift projects successfully reduced reservoir declines for a consecutive fifth year. Operational efficiency focus continued in 2024, with Production Operations and Asset Integrity teams continuing to achieve world class platform operating efficiencies, with major equipment uptimes of over 98%. Multiple platform seasonal shut-ins were planned and executed safely, resulting in an 80% reduction in the number of annual planned shut-in days compared to 2019.

Occidental’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.

Occidental invested $0.7 billion of development capital in 2024 with a continued strategy of low risk, infill drilling opportunities and accelerated project delivery at its Horn Mountain, Lucius, and Marco Polo facilities. Drilling and well service activities were ramped up using two floating drill ships and several service rigs. During 2024, all necessary regulatory permits for new wells and existing operations were obtained timely without any operational delays. Occidental was further awarded 45 new leases from the BOEM’s Lease Sale 261.

Occidental’s Asset Development teams made significant progress in developing new plans to significantly expand the recovery from Occidental’s producing oil and gas reservoirs. Several major secondary recovery uplift projects, as well as new horizontal/extended reach well opportunities, will be ready to begin implementation in 2025 onwards.

Occidental is also implementing several state-of-the-art artificial lift projects, including down-hole gas-lift and caisson electric submersible pumps at its Horn Mountain platform. These projects are expected to deliver some of the highest margin production in Occidental’s portfolio coming online beginning in the third quarter of 2025. Occidental plans to conduct development and exploration activities in 2025 using two floating drill ships and several other well service vessels and continue to optimize its extensive portfolio of lease working interests.

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

INTERNATIONAL INTERESTS

Occidental primarily conducts its ongoing 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, Occidental 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 Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts. Occidental’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, Occidental’s net economic benefit from these contracts is greater when product prices are higher. Approximately $0.6 billion of Occidental’s worldwide capital budget is expected to be allocated to its international operations in 2025.

MIDDLE EAST / NORTH AFRICA ASSETS

1.Algeria2.Oman3.Qatar4.UAE

Algeria

Occidental’s interests in Algeria consists of production rights in 18 fields within Blocks 404a and 208 located in the Berkine Basin in Algeria’s Sahara Desert. Occidental also owns interests in 3 unitized fields with 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 2024, net production in Algeria was 28 Mboe/d, from 205 gross wells, and annual development capital expenditures were $0.1 billion.

Oman

In Oman, Occidental 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. Occidental holds 6.0 million gross acres and has 10,000 potential well inventory locations. In 2024, Occidental’s share of production was 66 Mboe/d.

Occidental has produced over 823 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, Occidental has drilled over 3,600 new wells and has produced over 634 million gross barrels. In 2024, Occidental invested development capital of $0.4 billion across all of the Oman blocks to drill 95 wells and execute facilities projects to support development and EOR activities.

In 2025, Occidental will continue to enhance production by adding extended and dual laterals, stimulating wells with the OXY JETTINGTM wellbore stimulation system, and expanding thermal conformance. Occidental will also continue to execute projects in Oman targeting emissions reductions.

Qatar

In Qatar, Occidental partners in the Dolphin Energy Project, an investment that is comprised of two separate economic interests. Occidental 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. Occidental also has a 24.5% interest in DEL, which operates a pipeline and is discussed further in the midstream and marketing segment section in this Form 10-K under Pipeline. In 2024, Occidental’s net share of production from Dolphin was 39 Mboe/d.

UAE

Occidental 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 2024, Occidental’s net share of production from Al Hosn Gas was 293 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 CO 2.

In 2019 and 2020, Occidental 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 an area approximately 1.5 million acres and 0.8 million acres, respectively, and are adjacent to Al Hosn Gas. In 2023, Occidental commenced first oil production in Onshore Block 3. In 2025, Occidental will continue further exploration and appraisal activities in Onshore Block 3 and Block 5.

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 2024, 2023 and 2022 calculated first-day-of-the-month average prices for both WTI and Brent oil prices, as well as the Henry Hub gas prices:

Occidental had proved reserves from continuing operations at year-end 2024 of 4,612 MMboe, compared to the year-end 2023 proved reserves of 3,982 MMboe. Proved developed reserves represented approximately 69% of Occidental’s total proved reserves at year-end 2024 and 2023. The following table shows Occidental’s proved reserves from continuing operations by commodity as a percentage of total proved reserves:

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

CHANGES IN PROVED RESERVES

Changes in Occidental’s 2024 reserves were as follows:

Occidental’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 Occidental’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 Occidental. 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 Occidental’s share of proved reserves under PSCs because more oil is required to recover costs. Conversely, when prices rise, Occidental’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 2024, Occidental’s revisions of previous estimates of proved reserves were positive 170 MMboe, which were composed of 112 MMboe of positive revisions related to additions associated with infill development projects and updates based on reservoir performance of 152 MMboe. The positive revisions were partially offset by negative revisions of 87 MMboe associated with management changes in development plans. Further negative revisions of 29 MMboe were associated with negative price revisions.

The positive revisions related to additions associated with infill development projects of 112 MMboe were mainly in the DJ Basin (55 MMboe), the Permian Basin (45 MMboe) and international assets (8 MMboe).

Positive revisions associated with updates based on reservoir performance of 152 MMboe were primarily due to positive performance revisions in the DJ Basin (81 MMboe), GOA (41 MMboe), international assets (32 MMboe) and the Powder River Basin (11 MMboe).

The negative revisions of 87 MMboe associated with management changes in development plans were primarily related to the Permian Basin (53 MMboe), Oman (19 MMboe) and GOA (13 MMboe).

Negative price revisions of 29 MMboe were mainly associated with the Permian Basin.

Improved Recovery

In 2024, Occidental added proved reserves of 47 MMboe related to improved recovery in Permian EOR (40 MMboe) and Oman (7 MMboe). These properties comprise conventional projects, which are characterized by the deployment of EOR development methods, largely employing application of CO 2 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 CO 2 or steam flooding depends on the geology of the formation, the evaluation of engineering data, availability and cost of either CO 2 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

Occidental also added proved reserves from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2024, extensions and discoveries added 326 MMboe primarily related to the recognition of proved reserves in the Permian Basin (313 MMboe).

Purchases of Proved Reserves

In 2024, Occidental purchased proved reserves of 623 MMboe primarily consisting of proved reserves in the Permian Midland Basin related to the CrownRock Acquisition.

Sales of Proved Reserves

In 2024, Occidental sold 50 MMboe in proved reserves related to the divestitures of certain non-strategic assets primarily in the Permian Basin.

Proved Undeveloped Reserves

Occidental had PUD reserves at year-end 2024 of 1,421 MMboe, compared to the year-end 2023 amount of 1,232 MMboe.

Changes in PUD reserves were as follows:

Revisions of previous estimates were a negative 44 MMboe. Approximately 87 MMboe of the negative revisions were associated with management changes in development plans, mainly in the Permian Basin (53 MMboe), Oman (19 MMboe), and GOA (13 MMboe). Further negative revisions of 49 MMboe were primarily associated with updates based on reservoir performance, primarily due to negative performance revisions in the Permian Basin (46 MMboe) and international assets (31 MMboe) that were partially offset by positive performance revisions in GOA (33 MMboe). The negative revisions were partially offset by positive revisions of 81 MMboe primarily due to additions associated with infill development projects, mainly in the DJ Basin (49 MMboe) and the Permian Basin (29 MMboe), as well as positive revisions of 10 MMboe primarily associated with updates based on interest related revisions.

Extensions and discoveries added 234 MMboe primarily related to the recognition of proved reserves in the Permian Basin (227 MMboe). Total improved recovery additions of 43 MMboe were the result of implementing secondary and tertiary projects in Permian EOR (40 MMboe) and Oman (3 MMboe). In 2024, Occidental purchased PUD reserves of 305 MMboe primarily consisting of development projects in the Permian Midland Basin related to the CrownRock Acquisition. The 2024 additions to PUD reserves were partially offset by transfers to proved developed reserves of 332 MMboe. The transfers were primarily associated with the DJ Basin (141 MMboe), the Permian Basin (135 MMboe), GOA (24 MMboe), and the UAE (19 MMboe).

In 2024, Occidental incurred approximately $2.1 billion to convert PUD reserves to proved developed reserves, and in 2024 Occidental converted approximately 27% of its PUD reserves to proved developed, when adjusted for revisions and sales. As of December 31, 2024, Occidental had 1,421 MMboe of PUD reserves of which 83% were associated with domestic onshore, 5% with GOA and 12% with international assets. Occidental’s most active development areas are located in the Permian Basin, which represented 68% of the PUD reserves as of December 31, 2024. Occidental’s total planned

2025 capital expenditures for oil and gas are between $5.8 billion and $6.0 billion. Overall, Occidental plans to spend approximately $8.7 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, 2024, Occidental had 167 MMboe of pre-2020 PUD reserves that remained undeveloped. These PUD reserves relate to approved long-term development plans, primarily associated with international development projects (129 MMboe) with physical limitations in existing gas processing capacity and related to approved long-term development plans for Permian EOR projects (34 MMboe), also with physical limitations in existing gas processing capacity. Occidental remains committed to these projects and continues to actively progress the development of these volumes. In addition to the above, Occidental has 29 MMboe of PUD reserves that are scheduled to be developed more than five years from their initial date of booking. These PUD reserves are related to approved long-term development plans, primarily associated with international development projects.

RESERVES EVALUATION AND REVIEW PROCESS

Occidental’s estimates of proved reserves and associated future net cash flows as of December 31, 2024 were made by Occidental’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 Occidental 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, volumetric analysis and material balance 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 Occidental’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 Occidental's oil and gas reserves data. She has over 23 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.

Occidental has a Reserves Committee, consisting of senior corporate officers, to review and approve Occidental’s oil and gas reserves. The Reserves Committee reports to the Audit Committee of Occidental’s Board of Directors during the year. Since 2003, Occidental 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 2024, Ryder Scott conducted a process review of the methods and analytical procedures utilized by Occidental’s engineering and geological staff for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as of December 31, 2024, 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 Occidental’s 2024 year-end total proved reserves portfolio. In 2024, Ryder Scott reviewed approximately 34% of Occidental’s proved oil and gas reserves. Since being engaged in 2003, Ryder Scott has reviewed the specific application of Occidental’s reserve estimation methods and procedures for approximately 86% of Occidental’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 Occidental’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 Occidental. Occidental 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 Occidental, Ryder Scott has concluded that the overall procedures and methodologies Occidental 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 is highly competitive, is subject to significant volatility due to various market conditions and operations are highly dependent on oil prices and, to a lesser extent, NGL and natural gas prices. All commodity prices decreased in 2024. In 2024, compared to 2023, the average daily price per barrel of WTI crude decreased to $75.72 from $77.64, the average daily Brent price per barrel decreased to $79.79 from $82.25 and the average daily NYMEX natural gas price per MMcf decreased to $2.34 from $2.94.

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 costs in producing areas; (iii) currency exchange rates and inflation rates; and (iv) the effect of changes in these variables on market perceptions. It is expected that the price of oil will be volatile for the foreseeable future given the current geopolitical risks, the ongoing global impact of geopolitical risks, the evolving macro-economic environment and supply activity from OPEC and non-OPEC oil producing countries and U.S. Government management of the U.S. Strategic Petroleum Reserve. Occidental does not operate or own assets in either Russia or Ukraine, or in the immediate vicinity of ongoing conflicts in the Middle East.

NGL prices are related to the supply and demand for the components of products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify the pricing volatility from region to region.

Domestic natural gas prices and local differentials are strongly affected by local supply and demand fundamentals, as well as government regulations, global LNG demand and availability of transportation capacity from producing areas. International gas prices are generally fixed under long-term contracts.

These and other factors make it difficult to predict the future direction of oil, NGL and domestic gas prices reliably. For purposes of the current capital plan, Occidental will continue to focus on allocating capital to high-return assets with the flexibility to adjust based on fluctuations in commodity prices, current economic conditions, such as supply chain constraints, higher interest rates, global logistics and high inflation, which has continued to disrupt global supply and demand balances, with the goal of keeping returns well above its cost of capital.

The timing, process and ultimate cost to transition to a less carbon-intensive economy remains largely unknown; various industry forecasts indicate a growing demand for hydrocarbons for the remainder of the current decade. Occidental 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 CO 2 separation, transportation, use, recycling and storage position its oil and gas segment to support Occidental’s transition to net zero as well as create opportunities in a low-carbon future.