Item 2. Properties
ITEM 2. PROPERTIES
Information with regard to oil and gas producing activities follows:
1. Disclosure of Reserves
A. Summary of Oil and Gas Reserves at Year-End 2024
The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. No major discovery or other favorable or adverse event has occurred since December 31, 2024 that would cause a significant change in the estimated proved reserves as of that date.
Proved Reserves Crude
Oil Natural Gas
Liquids Bitumen Synthetic
Oil Natural
Gas Oil-Equivalent
Total
All Products
(million bbls) (million bbls) (million bbls) (million bbls) (billion cubic ft) (million bbls)
Developed
Consolidated Subsidiaries
United States 1,874 1,179 — — 11,671 4,998
Canada/Other Americas (1)
472 1 2,308 190 296 3,020
Europe 3 — — — 406 71
Africa 153 — — — 93 169
Asia 1,923 46 — — 1,900 2,286
Australia/Oceania 33 7 — — 3,204 574
Total Consolidated 4,458 1,233 2,308 190 17,570 11,118
Equity Companies
United States 6 3 — — 47 17
Europe 2 — — — 262 45
Africa 7 — — — 816 143
Asia 452 117 — — 4,242 1,276
Total Equity Company 467 120 — — 5,367 1,481
Total Developed 4,925 1,353 2,308 190 22,937 12,599
Undeveloped
Consolidated Subsidiaries
United States 1,399 909 — — 5,172 3,170
Canada/Other Americas (1)
646 — 121 106 245 914
Europe — — — — — —
Africa 38 — — — 2 38
Asia 1,186 22 — — 640 1,315
Australia/Oceania 22 — — — 2,275 401
Total Consolidated 3,291 931 121 106 8,334 5,838
Equity Companies
United States — — — — — —
Europe — — — — 54 9
Africa — — — — — —
Asia 272 194 — — 6,224 1,503
Total Equity Company 272 194 — — 6,278 1,512
Total Undeveloped 3,563 1,125 121 106 14,612 7,350
Total Proved Reserves 8,488 2,478 2,429 296 37,549 19,949
(1) Other Americas includes proved developed reserves of 375 million barrels of crude oil and 176 billion cubic feet of natural gas, as well as proved undeveloped reserves of 633 million barrels of crude oil and 231 billion cubic feet of natural gas.
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In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.
The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment; international trade patterns and relations; and other factors described in Item 1A .
The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of reservoir and well performance. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, and significant changes in crude oil and natural gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the Corporation’s capital spending and also impact our partners’ capacity to fund their share of joint projects.
B. Technologies Used in Establishing Proved Reserves Additions in 2024
Additions to ExxonMobil’s proved reserves in 2024 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including high-quality 3‑D and 4‑D seismic data, calibrated with available well control information. The tools used to interpret the data included seismic processing software, reservoir modeling and simulation software, and data analysis packages.
In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.
C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves
ExxonMobil has a dedicated Global Reserves and Resources group that provides technical oversight and is separate from the operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of ExxonMobil’s proved reserves. This group also maintains the official company reserves estimates for ExxonMobil’s proved reserves of crude oil, natural gas liquids, bitumen, synthetic oil, and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The current Global Reserves and Resources Manager has more than 30 years of experience in reservoir engineering and reserves assessment, has a degree in Engineering, and serves on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers. The group is staffed with individuals that have an average of more than 15 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under SEC guidelines. This group includes individuals who hold degrees in either Engineering or Geology.
The Global Reserves and Resources group maintains a central database containing the official company reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long-standing approval guidelines. No changes may be made to the reserves estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized geoscience and engineering professionals within the operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and approval by the appropriate level of management within the operating organization before the changes may be made in the central database. Endorsement by the Global Reserves and Resources group for all proved reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.
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2. Proved Undeveloped Reserves
At year-end 2024, approximately 7.4 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 37 percent of the 19.9 GOEB reported in proved reserves. This compares to 6.3 GOEB of proved undeveloped reserves reported at the end of 2023. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 1.1 GOEB from proved undeveloped to proved developed reserves by year-end. The largest transfers were related to development activities in the United States, Guyana, Kazakhstan, and the United Arab Emirates. In 2024, purchases of 0.4 GOEB in the United States and extensions and discoveries of 1.9 GOEB, primarily in the United States and Guyana, resulted in the addition of approximately 2.3 GOEB of proved undeveloped reserves. Also, the Corporation reclassified approximately 0.7 GOEB of proved undeveloped reserves, primarily in the United States, which was offset by upward revision of approximately 0.6 GOEB, primarily in the United Arab Emirates. This results in a net reclassification of approximately 0.1 GOEB of proved reserves which no longer met the SEC definition of proved reserves.
Overall, investments of $16.4 billion were made by the Corporation during 2024 to progress the development of reported proved undeveloped reserves, including $16.0 billion for oil and gas producing activities, along with additional investments for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 75 percent of the $21.8 billion in total reported Upstream capital and exploration expenditures.
One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-time in order to be developed. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. Proved undeveloped reserves in Australia, Kazakhstan, and the United Arab Emirates have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure, as well as the time required to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, the pace of co-venturer/government funding, changes in the amount and timing of capital investments, and significant changes in crude oil and natural gas price levels. Of the proved undeveloped reserves that have been reported for five or more years, over 80 percent are contained in the aforementioned countries. In Australia, proved undeveloped reserves are associated with future compression for the Gorgon Jansz LNG project. In Kazakhstan, the proved undeveloped reserves are related to the remainder of the Tengizchevroil joint venture development that includes a production license in the Tengiz - Korolev field complex. The Tengizchevroil joint venture is producing, and proved undeveloped reserves will continue to move to proved developed as approved development phases progress. In the United Arab Emirates, proved undeveloped reserves are associated with an approved development plan and continued drilling investment for the producing Upper Zakum field.
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3. Oil and Gas Production, Production Prices and Production Costs
A. Oil and Gas Production
The table below summarizes production by final product sold and by geographic area for the last three years.
(thousands of barrels daily) 2024 2023 2022
Crude Oil NGL Crude Oil NGL Crude Oil NGL
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States 862 383 556 238 523 211
Canada/Other Americas (1)
346 2 240 2 196 2
Europe 2 — 2 — 2 —
Africa 206 2 216 4 233 5
Asia 422 26 417 28 407 23
Australia/Oceania 20 10 24 12 27 16
Total Consolidated Subsidiaries 1,858 423 1,455 284 1,388 257
Equity Companies
United States 2 1 8 1 41 1
Europe 1 — 2 — 2 —
Africa 1 — 1 — — —
Asia 206 59 216 60 216 59
Total Equity Companies 210 60 227 61 259 60
Total crude oil and natural gas liquids production 2,068 483 1,682 345 1,647 317
Bitumen production
Consolidated Subsidiaries
Canada/Other Americas 374 355 327
Synthetic oil production
Consolidated Subsidiaries
Canada/Other Americas 62 67 63
Total liquids production 2,987 2,449 2,354
(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States 2,869 2,292 2,531
Canada/Other Americas (1)
101 96 148
Europe 252 266 306
Africa 45 35 64
Asia 907 915 779
Australia/Oceania 1,264 1,298 1,440
Total Consolidated Subsidiaries 5,438 4,902 5,268
Equity Companies
United States 18 19 20
Europe 100 148 361
Africa 107 90 7
Asia 2,415 2,575 2,639
Total Equity Companies 2,640 2,832 3,027
Total natural gas production available for sale 8,078 7,734 8,295
(thousands of oil-equivalent barrels daily)
Oil-equivalent production 4,333 3,738 3,737
(1) Other Americas includes crude oil production for 2024, 2023, and 2022 of 285 thousand, 178 thousand, and 120 thousand barrels daily, respectively; and natural gas production available for sale for 2024, 2023, and 2022 of 76 million, 67 million, and 45 million cubic feet daily, respectively.
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B. Production Prices and Production Costs
The table below summarizes average production prices and average production costs by geographic area and by product type for the last three years.
(dollars per unit) United
States Canada/
Other
Americas Europe Africa Asia Australia/
Oceania Total
2024
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 73.36 79.47 74.07 81.29 78.40 79.83 76.57
NGL, per barrel 23.08 30.43 63.29 50.51 32.34 38.74 24.32
Natural gas, per thousand cubic feet 0.37 1.72 10.56 2.25 2.55 8.47 3.13
Bitumen, per barrel — 54.02 — — — — 54.02
Synthetic oil, per barrel — 74.16 — — — — 74.16
Average production costs, per oil-equivalent barrel - total 10.89 16.20 25.18 21.85 5.31 6.92 11.70
Average production costs, per barrel - bitumen — 21.16 — — — — 21.16
Average production costs, per barrel - synthetic oil — 44.44 — — — — 44.44
Equity Companies
Average production prices
Crude oil, per barrel 73.91 — 76.34 73.99 73.17 — 73.21
NGL, per barrel 19.94 — — — 47.63 — 47.19
Natural gas, per thousand cubic feet 1.59 — 9.19 4.10 7.52 — 7.41
Average production costs, per oil-equivalent barrel - total 26.41 — 63.76 7.27 2.70 — 4.57
Total
Average production prices
Crude oil, per barrel 73.36 79.47 75.06 81.25 76.69 79.83 76.23
NGL, per barrel 23.07 30.43 63.29 50.51 43.01 38.74 27.16
Natural gas, per thousand cubic feet 0.37 1.72 10.17 3.55 6.17 8.47 4.53
Bitumen, per barrel — 54.02 — — — — 54.02
Synthetic oil, per barrel — 74.16 — — — — 74.16
Average production costs, per oil-equivalent barrel - total 10.94 16.20 36.41 20.68 3.93 6.92 10.53
Average production costs, per barrel - bitumen — 21.16 — — — — 21.16
Average production costs, per barrel - synthetic oil — 44.44 — — — — 44.44
2023
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 75.45 80.51 71.99 82.70 79.50 70.26 78.43
NGL, per barrel 23.88 24.44 64.10 44.72 29.81 34.35 25.12
Natural gas, per thousand cubic feet 1.16 2.57 13.64 2.04 2.40 9.31 4.26
Bitumen, per barrel — 49.64 — — — — 49.64
Synthetic oil, per barrel — 77.56 — — — — 77.56
Average production costs, per oil-equivalent barrel - total 9.70 19.94 36.37 20.70 5.26 5.55 12.05
Average production costs, per barrel - bitumen — 23.80 — — — — 23.80
Average production costs, per barrel - synthetic oil — 45.91 — — — — 45.91
Equity Companies
Average production prices
Crude oil, per barrel 75.48 — 77.82 71.92 74.59 — 74.63
NGL, per barrel 19.13 — — — 45.64 — 45.19
Natural gas, per thousand cubic feet 5.25 — 22.22 5.89 8.54 — 9.15
Average production costs, per oil-equivalent barrel - total 53.49 — 43.99 6.74 2.77 — 5.09
Total
Average production prices
Crude oil, per barrel 75.45 80.51 74.13 82.66 77.83 70.26 77.92
NGL, per barrel 23.86 24.44 64.10 44.72 40.59 34.35 28.66
Natural gas, per thousand cubic feet 1.19 2.57 16.71 4.81 6.93 9.31 6.05
Bitumen, per barrel — 49.64 — — — — 49.64
Synthetic oil, per barrel — 77.56 — — — — 77.56
Average production costs, per oil-equivalent barrel - total 10.15 19.94 39.09 19.79 3.91 5.55 10.63
Average production costs, per barrel - bitumen — 23.80 — — — — 23.80
Average production costs, per barrel - synthetic oil — 45.91 — — — — 45.91
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(dollars per unit) United
States Canada/
Other
Americas Europe Africa Asia Australia/
Oceania Total
2022
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 93.60 97.05 91.32 103.45 94.94 94.43 96.16
NGL, per barrel 38.54 45.22 71.43 57.83 35.77 46.91 39.37
Natural gas, per thousand cubic feet 5.37 4.40 21.17 2.57 2.60 11.47 7.48
Bitumen, per barrel — 64.12 — — — — 64.12
Synthetic oil, per barrel — 96.08 — — — — 96.08
Average production costs, per oil-equivalent barrel - total 9.40 24.63 23.77 21.68 7.31 4.97 13.09
Average production costs, per barrel - bitumen — 29.90 — — — — 29.90
Average production costs, per barrel - synthetic oil — 51.52 — — — — 51.52
Equity Companies
Average production prices
Crude oil, per barrel 94.58 — 90.91 60.00 94.32 — 94.32
NGL, per barrel 39.53 — — — 59.52 — 59.05
Natural gas, per thousand cubic feet 5.49 — 21.10 2.72 13.08 — 13.97
Average production costs, per oil-equivalent barrel - total 40.42 — 26.86 42.24 1.45 — 5.57
Total
Average production prices
Crude oil, per barrel 93.67 97.05 91.15 103.42 94.73 94.43 95.88
NGL, per barrel 38.55 45.22 71.43 57.83 52.85 46.91 43.09
Natural gas, per thousand cubic feet 5.37 4.40 21.14 2.59 10.70 11.47 9.85
Bitumen, per barrel — 64.12 — — — — 64.12
Synthetic oil, per barrel — 96.08 — — — — 96.08
Average production costs, per oil-equivalent barrel - total 10.57 24.63 25.43 21.79 4.02 4.97 11.43
Average production costs, per barrel - bitumen — 29.90 — — — — 29.90
Average production costs, per barrel - synthetic oil — 51.52 — — — — 51.52
Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report due to volumes consumed or flared. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
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4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
2024 2023 2022
Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States 2 — 1
Canada/Other Americas 3 1 3
Europe — 1 —
Africa — — —
Asia — — —
Australia/Oceania — — —
Total Consolidated Subsidiaries 5 2 4
Equity Companies
United States — — —
Europe — — —
Africa — — —
Asia — — —
Total Equity Companies — — —
Total productive exploratory wells drilled 5 2 4
Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States — 1 —
Canada/Other Americas 3 3 4
Europe — — —
Africa — — —
Asia — — —
Australia/Oceania — — —
Total Consolidated Subsidiaries 3 4 4
Equity Companies
United States — — —
Europe — — —
Africa — — —
Asia — — —
Total Equity Companies — — —
Total dry exploratory wells drilled 3 4 4
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2024 2023 2022
Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States 533 446 473
Canada/Other Americas 22 47 33
Europe 1 1 —
Africa 4 4 3
Asia 6 5 5
Australia/Oceania 1 — —
Total Consolidated Subsidiaries 567 503 514
Equity Companies
United States 1 2 49
Europe — — —
Africa — — —
Asia 3 6 10
Total Equity Companies 4 8 59
Total productive development wells drilled 571 511 573
Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States 10 — —
Canada/Other Americas — — —
Europe — — —
Africa 1 — —
Asia — — —
Australia/Oceania — — —
Total Consolidated Subsidiaries 11 — —
Equity Companies
United States — — —
Europe — — —
Africa — — —
Asia — — —
Total Equity Companies — — —
Total dry development wells drilled 11 — —
Total number of net wells drilled 590 517 581
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B. Exploratory and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies
Syncrude Operations. Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2024, the Company’s share of net production of synthetic crude oil was about 62 thousand barrels per day and share of net acreage was about 55 thousand acres in the Athabasca oil sands deposit.
Kearl Operations. Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 49 thousand acres in the Athabasca oil sands deposit.
Kearl is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands and processed through bitumen extraction and froth treatment trains. The product, a blend of bitumen and diluent, is shipped to our refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation. During 2024, average net production at Kearl was about 262 thousand barrels per day.
5. Present Activities
A. Wells Drilling
Wells Drilling Year-End 2024
Year-End 2023
Gross Net Gross Net
Consolidated Subsidiaries
United States 809 648 582 409
Canada/Other Americas 19 9 42 29
Europe 1 1 3 1
Africa 5 1 4 1
Asia 13 5 25 5
Australia/Oceania 1 — 3 1
Total Consolidated Subsidiaries 848 664 659 446
Equity Companies
United States 15 — 9 —
Europe — — — —
Africa — — — —
Asia 43 4 61 4
Total Equity Companies 58 4 70 4
Total gross and net wells drilling 906 668 729 450
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B. Review of Principal Ongoing Activities
United States
Net acreage totaled 9.8 million acres at year-end 2024, of which 0.2 million acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. Development activities continued on the Golden Pass LNG export project.
During the year, a total of 544.1 net exploratory and development wells were completed in the inland lower 48 states. Development activities focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico. In addition, ExxonMobil completed the acquisition of Pioneer, increasing the Permian Basin acreage and production capacity.
Net acreage in the Gulf totaled 0.1 million acres at year-end 2024. A total of a 0.5 net development well was completed during the year.
Participation in Alaska production and development continued with a total of 0.9 net development wells completed.
Canada / Other Americas
Canada
Oil and Gas Operations: Net acreage totaled 3.9 million acres at year-end 2024, of which 2.0 million acres were offshore. A total of 1.7 net exploratory and development wells were completed during the year.
In Situ Bitumen Operations: Net acreage totaled 0.5 million onshore acres at year-end 2024. During the year, a total of 14 net development wells at Cold Lake were completed.
Argentina
Net acreage totaled 0.1 million onshore acres at year-end 2024. During the year, a total of 1.6 net development wells were completed. In 2024, ExxonMobil relinquished 2.6 million net offshore acres and sold a portion of its interests in onshore production facilities. The sale of the remaining onshore assets is expected to be completed in early 2025 resulting in a full Upstream operations exit from the country.
Brazil
Net acreage totaled 1.5 million offshore acres at year-end 2024. During the year, a total of a 0.4 net exploratory well was completed and ExxonMobil relinquished its interest in 1.0 million net offshore acres spanning 10 blocks outside of the core Bacalhau development. Development activities continued on the Bacalhau Phase 1 project.
Guyana
Net acreage totaled 4.6 million offshore acres at year-end 2024. During the year, a total of 10.1 net exploratory and development wells were completed. Development activities continued on the Yellowtail and Uaru projects. The Whiptail project was funded in 2024.
Europe
Germany
Net acreage totaled 1.2 million onshore acres at year-end 2024. During the year, a total of 0.5 net development wells were completed.
Netherlands
Net interest in licenses totaled 1.3 million acres at year-end 2024, of which 0.3 million acres were offshore. Groningen field permanent closure was codified in the Dutch mining law on April 19, 2024.
United Kingdom
Net interest in licenses totaled 0.1 million offshore acres at year-end 2024.
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Africa
Angola
Net acreage totaled 3 million acres at year-end 2024, of which 2.9 million acres were offshore. During the year, a total of 5.6 net exploratory and development wells were completed.
Mozambique
Net acreage totaled 0.1 million offshore acres at year-end 2024 within Area 4. ExxonMobil participated in the co-venturer-operated Coral South Floating LNG, a gross 3.4 million metric tons per year LNG facility.
Nigeria
Net acreage totaled 0.4 million offshore acres at year-end 2024. During the year, a total of a 0.2 net development well was completed. In December 2024, the Corporation completed a transfer of 100 percent of the shares in its Nigeria affiliate, Mobil Producing Nigeria Unlimited, following the receipt of and compliance with conditions precedent specified in government approvals.
Asia
Azerbaijan
Net acreage totaled 7 thousand offshore acres at year-end 2024. During the year, a total of 1 net development wells were completed.
Indonesia
Net acreage totaled 0.1 million onshore acres at year-end 2024. During the year, a total of 0.9 net development wells were completed.
Kazakhstan
Net acreage totaled 0.3 million acres at year-end 2024, of which 0.2 million acres were offshore. During the year, a total of 1 net development wells were completed. Development activities continued on the Tengiz Expansion project.
Malaysia
Net interests in production sharing contracts covered 0.2 million offshore acres at year-end 2024. During the year, a total of 1.5 net development wells were completed.
Qatar
Through joint ventures with QatarEnergy, net acreage totaled 76 thousand offshore acres at year-end 2024. During the year, a total of 1.4 net development wells were completed. ExxonMobil participated in 52.3 million metric tons per year gross liquefied natural gas capacity and 3.4 billion cubic feet per day of flowing gas capacity at year-end 2024. Development activities continued on the North Field East project and North Field Production Sustainment projects.
Thailand
Net acreage in concessions totaled 16 thousand onshore acres at year-end 2024. During the year, a total of a 0.1 net development well was completed.
United Arab Emirates
Net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 0.1 million acres at year-end 2024. During the year, a total of 2.5 net development wells were completed. Activities continued on the ongoing phased development of the Upper Zakum field.
Australia / Oceania
Australia
Net acreage totaled 1.2 million offshore acres and nine thousand onshore acres at year-end 2024.
The co-venturer-operated Gorgon Jansz liquefied natural gas (LNG) development consists of a subsea infrastructure for offshore production and transportation of the gas, a 15.6 million metric tons per year LNG facility, and a 280 million cubic feet per day
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domestic gas plant located on Barrow Island, Western Australia. During the year, operations began on the Gorgon Stage 2 project and development activities continued on the Jansz Io Compression project.
Papua New Guinea
Net acreage totaled 1.6 million onshore acres at year-end 2024. During the year, a total of 1 net development wells were completed. The Papua New Guinea (PNG) liquefied natural gas (LNG) integrated development includes gas production and processing facilities in the PNG Highlands, onshore and offshore pipelines, and a 6.9 million metric tons per year LNG facility near Port Moresby.
Worldwide Exploration
Exploration activities were under way in several countries in which ExxonMobil has no established production operations and thus are not included above. Net acreage totaled 15.7 million acres at year-end 2024. During the year, a total of a 0.5 net exploratory well was completed.
6. Delivery Commitments
ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 123 million barrels of oil and 2.8 trillion cubic feet of natural gas for the period from 2025 through 2027. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and purchases on the open market as necessary.
7. Oil and Gas Properties, Wells, Operations and Acreage
A. Gross and Net Productive Wells
Gross and Net Productive Wells Year-End 2024
Year-End 2023
Oil Gas Oil Gas
Gross Net Gross Net Gross Net Gross Net
Consolidated Subsidiaries
United States 30,333 17,078 7,579 4,340 21,193 9,503 8,210 4,801
Canada/Other Americas 4,092 4,025 2,865 1,017 4,193 4,131 2,901 1,034
Europe 371 113 359 192 476 125 396 198
Africa 359 94 — — 605 204 21 8
Asia 789 243 151 87 995 293 148 85
Australia/Oceania 326 48 104 40 449 84 98 40
Total Consolidated Subsidiaries 36,270 21,601 11,058 5,676 27,911 14,340 11,774 6,166
Equity Companies
United States 2,573 329 3,303 326 2,634 340 3,322 329
Europe 57 20 332 102 57 20 454 139
Africa — — 6 2 — — 6 2
Asia 233 58 150 31 234 58 145 33
Total Equity Companies 2,863 407 3,791 461 2,925 418 3,927 503
Total gross and net productive wells 39,133 22,008 14,849 6,137 30,836 14,758 15,701 6,669
There were 25,610 gross and 22,837 net operated wells at year-end 2024 and 18,518 gross and 16,171 net operated wells at year-end 2023. The number of wells with multiple completions was 434 gross in 2024 and 467 gross in 2023.
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B. Gross and Net Developed Acreage
Gross and Net Developed Acreage
(thousands of acres)
Year-End 2024
Year-End 2023
Gross Net Gross Net
Consolidated Subsidiaries
United States 10,668 7,021 10,354 6,566
Canada/Other Americas (1)
1,903 1,342 2,145 1,526
Europe 954 555 983 560
Africa 1,455 428 2,109 704
Asia 1,473 427 1,582 451
Australia/Oceania 3,142 1,043 3,174 1,033
Total Consolidated Subsidiaries 19,595 10,816 20,347 10,840
Equity Companies
United States 581 113 583 113
Europe 3,590 1,109 3,590 1,109
Africa 178 44 178 44
Asia 665 152 665 157
Total Equity Companies 5,014 1,418 5,016 1,423
Total gross and net developed acreage 24,609 12,234 25,363 12,263
(1) Includes developed acreage in Other Americas of 379 gross and 190 net thousands of acres for 2024 and 559 gross and 342 net thousands of acres for 2023.
Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.
C. Gross and Net Undeveloped Acreage
Gross and Net Undeveloped Acreage
(thousands of acres)
Year-End 2024
Year-End 2023
Gross Net Gross Net
Consolidated Subsidiaries
United States 6,707 2,632 6,738 2,602
Canada/Other Americas (2)
21,457 9,842 30,773 15,012
Europe 11,988 7,770 12,489 8,173
Africa 17,476 11,301 18,309 12,696
Asia 766 227 766 227
Australia/Oceania 3,554 1,805 4,811 2,309
Total Consolidated Subsidiaries 61,948 33,577 73,886 41,019
Equity Companies
United States — — — —
Europe 381 110 381 110
Africa 418 104 418 104
Asia 298 19 298 19
Total Equity Companies 1,097 233 1,097 233
Total gross and net undeveloped acreage 63,045 33,810 74,983 41,252
(2) Includes undeveloped acreage in Other Americas of 14,914 gross and 6,381 net thousands of acres for 2024 and 24,221 gross and 11,548 net thousands of acres for 2023.
ExxonMobil’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks, and leases. The terms and conditions under which the Corporation maintains exploration and/or production rights to the acreage are property-specific, contractually defined, and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Corporation 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 Corporation has generally been successful in obtaining extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Corporation.
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D. Summary of Acreage Terms
United States
Oil and gas exploration and production rights are acquired from mineral interest owners through a lease. Mineral interest owners include the Federal and State governments, as well as private mineral interest owners. Leases typically have a primary term ranging from one to 10 years, and a production period beyond the primary term that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its primary term even if production has not commenced. In some instances a “fee interest” is acquired in private property where the underlying mineral interests and rights are purchased and owned outright.
Canada / Other Americas
Canada
Exploration licenses or leases in onshore areas are acquired for varying periods of time with renewals or extensions possible. These licenses or leases entitle the holder to continue existing licenses or leases upon completing specified work. In general, these license and lease agreements are held as long as there is proven production capability on the licenses and leases. Offshore exploration licenses are generally held by work commitments of various amounts and rentals. Offshore production licenses are valid for 25 years, with rights of extension for continued production. Significant discovery licenses in the offshore relating to currently undeveloped discoveries do not have a definite term.
Argentina
The Federal Hydrocarbon Law was amended in 2014 and in 2024. Pursuant to the amended law, the production term for an onshore unconventional concession is 35 years and 25 years for a conventional concession. ExxonMobil is actively taking steps to exit Upstream operations in the country.
Brazil
The exploration and production of oil and gas are governed by concession contracts and production sharing contracts (PSCs). Concession contracts provide for an exploration period of up to eight years and a production period of 27 years. PSCs provide for an exploration period of up to seven years and a production period of up to 28 years.
Guyana
The Petroleum Activities Act 2023 authorizes the Government of Guyana to license and enter petroleum agreements for petroleum exploration, development, production, and storage operations. The Act enables petroleum agreements to provide for an exploration period to be established by subsidiary legislation by the Minister (typically up to 10 years) and provide for a production period of 20 years for an oil field and 30 years for a gas field, each with a renewal period of up to 10 years.
Europe
Germany
Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions up to three years each. Extensions are subject to specific minimum work commitments. Production licenses were historically granted for 20 to 25 years with multiple possible extensions subject to production on the license.
Netherlands
Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the license and are based on the Mining Law.
Production rights granted prior to January 1, 2003, remain subject to their existing terms and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988, they were issued for a period as explicitly defined in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976, they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.
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United Kingdom
Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the first four licensing rounds provided an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. At the end of any such 40-year term, licenses may continue in producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a case-by-case basis until they become producing areas; or licenses terminate in all other areas. The majority of traditional licenses currently issued have an initial exploration term of four years with a second term extension of four years, and a final production term of 18 years, with a mandatory relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.
Africa
Angola
Exploration and production activities are governed by either production sharing agreements or other concession contracts with initial exploration terms ranging from three to four years with options to extend from one to five years. The production periods range from 20 to 30 years, with extensions subject to negotiation with the National Concessionaire.
Mozambique
Exploration and production activities are generally governed by concession contracts with the Government of the Republic of Mozambique, represented by the Ministry of Mineral Resources and Energy. An interest in Area 4 offshore Mozambique was acquired in 2017. Terms for Area 4 are governed by the Exploration and Production Concession Contract (EPCC) for Area 4 Offshore of the Rovuma Block. The EPCC expires 30 years after an approved plan of development becomes effective for a given discovery area.
Nigeria
Exploration and production activities are governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Company Limited (NNPCL). NNPCL typically holds the underlying license or lease. The terms of the PSCs are generally 30 years (comprised of a 10-year exploration period and a 20-year production period).
The 2021 Petroleum Industry Act will govern any further renewals to the term of the PSCs, licenses, or leases.
Asia
Azerbaijan
The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field was established for an initial period of 30 years starting from the PSA execution date in 1994. The PSA was amended in September 2017 to extend the term by 25 years to 2049.
Indonesia
Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract (PSC). The current PSCs have an exploration period of six years, which can be extended once for a period of four years with a total contract period of 30 years including an exploitation period. PSC terms can be extended for a maximum of 20 years for each extension with the approval of the government.
Kazakhstan
Onshore exploration and production activities are governed by the production license, which includes exploration activities and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.
Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is 20 years from the date of declaration of commerciality with the possibility of two 10-year extensions.
Malaysia
Production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The PSCs have production terms of 25 years. Extensions are generally subject to the national oil company’s prior written approval.
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Qatar
The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects. The initial terms for these rights generally extend for 25 years. Extensions and terms are subject to State of Qatar approval.
Thailand
The Petroleum Act of 1971 allows production under ExxonMobil’s concessions for 30 years with a 10-year extension at terms generally prevalent at the time.
United Arab Emirates
An interest in the development and production activities of the offshore Upper Zakum field was acquired in 2006. In 2017, the governing agreements were extended to 2051.
Australia / Oceania
Australia
Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable at the time of application but are likely to become commercially viable within 15 years. These are granted for periods of five years, and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter indefinitely, i.e., for the life of the field. Effective from July 1998, new production licenses are granted indefinitely. In each case, a production license may be terminated if no production operations have been carried on for five years.
Papua New Guinea
Exploration and production activities are governed by the Oil and Gas Act. Petroleum prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum development licenses are granted for an initial 25-year period. An extension for further consecutive period(s) of up to 20 years may be granted at the Petroleum Minister’s discretion. Petroleum retention licenses may be granted for gas resources that are not commercially viable at the time of application but may become commercially viable within the maximum possible retention time of 15 years. Petroleum retention licenses are granted for an initial five-year period, and may only be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years.
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Information with regard to refining and chemical capacity:
ExxonMobil manufactures, trades, and sells petroleum and petrochemical products. Our refining and chemical operations are highly integrated and encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, specialty products, feedstocks, olefins, polyolefins, and a wide variety of other products to our customers around the world.
Capacity At Year-End 2024 (1)
ExxonMobil
Interest % ExxonMobil’s Share of Refining Capacity (2)
Ethylene Polyethylene Polypropylene
(thousands of barrels daily) (millions of metric tons per year)
United States
Joliet Illinois ■ 100 264 — — —
Baton Rouge Louisiana ■ ▲ ● 100 523 1.1 1.3 1.0
Baytown Texas ■ ▲ ● 100 565 4.0 — 0.8
Beaumont Texas ■ ▲ ● 100 612 0.9 1.7 —
Corpus Christi Texas ● 50 — 0.9 0.7 —
Mont Belvieu Texas ● 100 — — 2.3 —
Total United States 1,964 6.9 6.0 1.8
Canada
Strathcona Alberta ■ 69.6 197 — — —
Nanticoke Ontario ■ 69.6 113 — — —
Sarnia Ontario ■ ● 69.6 124 0.3 0.5 —
Total Canada 434 0.3 0.5 —
Europe
Antwerp Belgium ■ ● 100 309 — 0.4 —
Meerhout Belgium ● 100 — — 0.5 —
Gravenchon France ■ ▲ ● 82.9/100 (3)
244 — — —
Karlsruhe (4)
Germany ■ 25 78 — — —
Rotterdam Netherlands ■ ▲ ● 100 192 — — —
Fawley United Kingdom ■ ▲ ● 100 262 — — —
Fife United Kingdom ● 50 — 0.4 — —
Total Europe 1,085 0.4 0.9 —
Asia Pacific
Fujian China ■ ● 25 67 0.3 0.2 0.2
Singapore Singapore ■ ▲ ● 100 592 1.9 1.9 1.0
Total Asia Pacific 659 2.2 2.1 1.2
Middle East
Al Jubail Saudi Arabia ▲ ● 50 — 0.7 0.7 —
Yanbu Saudi Arabia ■ ● 50 200 1.0 0.7 0.2
Total Middle East 200 1.7 1.4 0.2
Total Worldwide 4,342 11.5 10.8 3.2
■ Energy Products ▲ Specialty Products ● Chemical Products
(1) ExxonMobil share reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, ExxonMobil share is the greater of ExxonMobil’s interest or that portion of distillation capacity normally available to ExxonMobil.
(2) Refining capacity data is based on 100 percent of rated refinery process unit stream-day capacities to process inputs to atmospheric distillation units under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time. The listing excludes refining capacity for a minor interest held through equity securities in the Laffan Refinery in Qatar for which results are reported in the Upstream segment.
(3) ExxonMobil ownership in Gravenchon is split 82.9 percent and 100 percent between the refining and chemical operations, respectively. In 2024, the Company shut down a portion of its Gravenchon chemical operations including the steamcracker and related derivatives units.
(4) The Corporation announced a sales agreement relating to ExxonMobil's ownership interest in this asset and expects the transaction to close in 2025.
Due to rounding, numbers presented above may not add up precisely to the totals indicated.
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Information with regard to retail fuel sites:
Within the Energy Products segment, retail fuels sites sell products and services throughout the world through our Exxon , Esso, and Mobil brands.
Number of Retail Fuel Sites At Year-End 2024
Owned/leased Distributors/resellers Total
United States — 10,573 10,573
Canada — 2,598 2,598
Europe 169 3,958 4,127
Asia Pacific 264 864 1,128
Latin America — 555 555
Middle East/Africa 169 294 463
Worldwide 602 18,842 19,444