OCCIDENTAL PETROLEUM CORP /DE/

Supplemental Oil and Gas Information

OIL AND GAS RESERVES

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

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

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

OIL RESERVES

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

NGL RESERVES

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

NATURAL GAS RESERVES

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

TOTAL RESERVES

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

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

CAPITALIZED COSTS

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

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

COSTS INCURRED

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

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

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

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

RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

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

(b)Revenues are net of royalty payments.

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

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

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

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

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

(a)Included ARO costs.

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

NET PRODUCTIVE AND DRY— EXPLORATORY AND DEVELOPMENT WELLS COMPLETED

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

PRODUCTIVE OIL AND GAS WELLS

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

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

(b)The sum of fractional interests.

PARTICIPATION IN WELLS BEING DRILLED OR PENDING COMPLETION

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

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

As of December 31, 2025, the Company was participating in 104 and 39 gross pressure-maintenance projects in the United States and internationally, respectively. In the United States, these projects primarily consisted of waterfloods and CO 2 floods, and in the Middle East and North Africa, these projects consisted mostly of waterfloods.

OIL AND GAS ACREAGE

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

(a)Acres spaced or assigned to productive wells.

(b)Total acres in which interests are held.

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

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

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

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

OIL, NGL AND NATURAL GAS SALES VOLUMES PER DAY

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