OCCIDENTAL PETROLEUM CORP /DE/

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:

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:

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

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 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 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 CO 2 flooding performance and the expansive CO 2 transportation and processing infrastructure has resulted in decades of high-value enhanced oil production. With 34 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 the Company’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 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%.

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.

INTERNATIONAL INTERESTS

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.

MIDDLE EAST / NORTH AFRICA ASSETS

1.Algeria2.Oman3.Qatar4.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.

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.

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 CO 2.

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:

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:

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.

CHANGES IN PROVED RESERVES

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

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 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

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).

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:

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.

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

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 CO 2 separation, transportation, use, recycling and storage position its oil and gas segment for opportunities to lower carbon intensity.