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Supplementary Oil & Gas Information for the Fiscal Year Ended December 31, 2025 (Unaudited) |
This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board ("FASB") Topic 932 – "Extractive Activities – Oil and Gas" and where applicable, financial information is prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.
For the years ended December 31, 2025, 2024, 2023, and 2022 the Company filed its reserves information under National Instrument 51-101 – "Standards of Disclosure of Oil and Gas Activities" ("NI 51-101"), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada.
There are significant differences in the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission ("SEC") requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards can be material.
For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2025, 2024, 2023, and 2022 the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The Company has used the following 12-month average benchmark prices to determine its 2025 and 2024 reserves for SEC requirements.
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| Crude Oil and NGLs | | Natural Gas |
| WTI | WCS | Canadian Light Sweet | Cromer LSB | Brent | Edmonton C5+ | | Henry Hub | AECO | BC Westcoast Station 2 |
| (US$/bbl) | (C$/bbl) | (C$/bbl) | (C$/bbl) | (US$/bbl) | (C$/bbl) | | (US$/MMBtu) | (C$/MMBtu) | (C$/MMBtu) |
| 2025 | 65.68 | | 76.91 | | 87.03 | | 85.79 | | 68.59 | | 90.25 | | | 3.70 | | 1.75 | | 1.10 | |
| 2024 | 74.88 | 80.78 | 96.35 | 93.44 | 78.81 | 98.90 | | 2.37 | 1.28 | 0.91 |
A foreign exchange rate of US$0.7131/C$1.00 was used in the 2025 evaluation (2024 - US$0.7325/C$1.00), determined on the same basis as the 12-month average price.
Net Proved Crude Oil and Natural Gas Reserves
The Company retains Independent Qualified Reserves Evaluators to evaluate and review the Company's proved crude oil, bitumen, synthetic crude oil ("SCO"), natural gas, and natural gas liquids ("NGLs") reserves.
▪For the years ended December 31, 2025, 2024, 2023, and 2022, the reports by GLJ Ltd. ("GLJ") covered 100% of the Company’s Oil Sands Mining and Upgrading SCO reserves. As of December 31, 2025, GLJ also evaluated the Company's mining bitumen reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules, effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals.
▪For the years ended December 31, 2025 and 2024, the reports by Sproule International Limited, and for the years ended December 31, 2023 and 2022, the reports by Sproule Associates Limited and Sproule International Limited, covered 100% of the Company’s crude oil, thermal bitumen, natural gas and NGLs reserves.
Proved crude oil and natural gas reserves, as defined within the SEC's Regulation S-X, are the estimated quantities of oil and gas that by analysis of geoscience and engineering data demonstrate with reasonable certainty to be economically producible, from a given date forward, from known reservoirs under existing economic conditions, operating methods and government regulations. Developed crude oil and natural gas reserves are reserves of any category that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped crude oil and natural gas reserves are reserves of any category 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.
Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change.
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1 | Canadian Natural 2025 Annual Report |
The following tables summarize the Company's proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2025, 2024, 2023 and 2022:
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| | North America | | | |
Crude Oil and NGLs (MMbbl) (1) | Synthetic
Crude Oil | Bitumen (2) | Crude Oil | NGLs | | North
America
Total | North
Sea | Offshore
Africa | Total |
Net Proved Reserves | | | | | | | | | |
Reserves, December 31, 2022 | 5,390 | 2,546 | 321 | 375 | | 8,632 | 11 | 57 | 8,700 |
Extensions and discoveries | 162 | 67 | 14 | 37 | | 280 | — | — | 280 |
Improved recovery | 28 | 9 | 7 | 30 | | 75 | — | — | 75 |
Purchases of reserves in place | — | — | — | — | | — | — | — | — |
Sales of reserves in place | — | — | — | (1) | | (1) | — | — | (1) |
Production | (141) | (102) | (27) | (20) | | (289) | (5) | (4) | (298) |
Economic revisions due to prices (3) | 333 | 123 | 10 | 18 | | 484 | — | 1 | 485 |
Revisions of prior estimates | 68 | 26 | (2) | 3 | | 94 | 3 | 1 | 98 |
Reserves, December 31, 2023 | 5,840 | 2,669 | 325 | 442 | | 9,276 | 9 | 54 | 9,339 |
Extensions and discoveries | — | 62 | 13 | 18 | | 93 | — | — | 93 |
Improved recovery | 1 | 7 | 2 | 10 | | 21 | — | — | 21 |
Purchases of reserves in place | 701 | 1 | 7 | 131 | | 839 | — | — | 839 |
Sales of reserves in place | — | — | (1) | (2) | | (2) | — | — | (2) |
Production | (141) | (101) | (26) | (23) | | (291) | (4) | (4) | (299) |
Economic revisions due to prices (3) | (106) | (38) | — | (34) | | (180) | — | — | (179) |
Revisions of prior estimates | 18 | 77 | 37 | 4 | | 136 | 1 | (2) | 136 |
Reserves, December 31, 2024 | 6,313 | 2,676 | 356 | 547 | | 9,892 | 6 | 48 | 9,947 |
Extensions and discoveries | — | 58 | 13 | 7 | | 78 | — | — | 78 |
Improved recovery | 1 | 21 | 4 | 32 | | 58 | — | — | 58 |
Purchases of reserves in place | — | 336 | 57 | 55 | | 448 | — | — | 448 |
Sales of reserves in place | — | — | — | — | | — | — | — | — |
Production | (167) | (112) | (31) | (35) | | (345) | (3) | (1) | (349) |
Economic revisions due to prices (3) | 17 | 155 | 10 | 62 | | 244 | — | 1 | 246 |
Revisions of prior estimates | (261) | 309 | 10 | (9) | | 50 | (3) | (9) | 38 |
Reserves, December 31, 2025 | 5,903 | 3,443 | 420 | 660 | | 10,425 | — | 40 | 10,465 |
Net Proved Developed Reserves | | | | | | | | | |
December 31, 2022 | 5,389 | 582 | 238 | 121 | | 6,330 | 5 | 34 | 6,369 |
December 31, 2023 | 5,804 | 610 | 225 | 112 | | 6,752 | 6 | 30 | 6,787 |
December 31, 2024 | 6,268 | 629 | 232 | 127 | | 7,256 | 6 | 25 | 7,288 |
December 31, 2025 | 5,855 | 1,326 | 258 | 183 | | 7,622 | — | 25 | 7,647 |
(1)Information in the reserves data tables may not add due to rounding.
(2)Bitumen as defined by the SEC, "is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis." Under this definition, all the Company's thermal bitumen, mining bitumen and primary heavy crude oil reserves have been classified as bitumen.
(3)Includes changes due to commodity price and resulting royalty volumes.
| | | | | |
| Canadian Natural 2025 Annual Report | 2 |
2025 total proved Crude Oil and NGLs reserves increased by 518 MMbbl:
▪Extensions and discoveries: Increase of 78 MMbbl primarily due to extension drilling/future offset additions at various Bitumen, Crude Oil and natural gas (NGLs) properties.
▪Improved recovery: Increase of 58 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs), Bitumen and Crude Oil properties as well as improved recovery at Oil Sands Mining and Upgrading (SCO) properties.
▪Purchases of reserves in place: Increase of 448 MMbbl primarily due to acquisitions at various Bitumen, Crude Oil and natural gas (NGLs) properties.
▪Production: Decrease of 349 MMbbl.
▪Economic revisions due to prices: Increase of 246 MMbbl primarily at various Bitumen and Oil Sands Mining and Upgrading (SCO) properties due to lower bitumen pricing, resulting in lower royalties and higher net reserves.
▪Revisions of prior estimates: Increase of 38 MMbbl primarily due to improved performance at various Bitumen and Crude Oil properties, partially offset by negative revisions at various natural gas (NGLs), Offshore Africa and North Sea properties, as well as a category transfer at Oil Sands Mining and Upgrading from SCO to Bitumen.
2024 total proved Crude Oil and NGLs reserves increased by 607 MMbbl:
▪Extensions and discoveries: Increase of 93 MMbbl primarily due to extension drilling/future offset additions at various Bitumen, natural gas (NGLs) and Crude Oil properties.
▪Improved recovery: Increase of 21 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil and Bitumen properties as well as improved recovery at Oil Sands Mining and Upgrading (SCO) properties.
▪Purchases of reserves in place: Increase of 839 MMbbl primarily due to acquisitions at Oil Sands Mining and Upgrading (SCO) and various natural gas (NGLs) and Crude Oil properties in Alberta.
▪Sales of reserves in place: Decrease of 2 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in Alberta.
▪Production: Decrease of 299 MMbbl.
▪Economic revisions due to prices: Decrease of 179 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and various Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves.
▪Revisions of prior estimates: Increase of 136 MMbbl primarily due to improved performance at various Bitumen, natural gas (NGLs) and Crude Oil properties as well as transfers from beyond the 50-year reserves life cutoff at Oil Sands Mining and Upgrading (SCO).
2023 total proved Crude Oil and NGLs reserves increased by 639 MMbbl:
▪Extensions and discoveries: Increase of 280 MMbbl primarily due to pit extensions at Oil Sands Mining and Upgrading (SCO) and infill drilling/future offset additions at various Bitumen, natural gas (NGLs) and Crude Oil properties.
▪Improved recovery: Increase of 75 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil properties as well as improved recovery at Oil Sands Mining and Upgrading (SCO) and Bitumen properties.
▪Sales of reserves in place: Decrease of 1 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in Alberta.
▪Production: Decrease of 298 MMbbl.
▪Economic revisions due to prices: Increase of 485 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and various Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves.
▪Revisions of prior estimates: Increase of 98 MMbbl primarily due to transfers from beyond the 50-year reserves life cutoff at Oil Sands Mining and Upgrading (SCO) and improved performance at various Bitumen properties.
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3 | Canadian Natural 2025 Annual Report |
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Natural Gas (Bcf) (1) | North America | North Sea | Offshore Africa | Total |
Net Proved Reserves | | | | |
Reserves, December 31, 2022 | 12,217 | 4 | 25 | 12,246 |
Extensions and discoveries | 1,185 | — | — | 1,185 |
Improved recovery | 603 | — | — | 603 |
Purchases of reserves in place | — | — | — | — |
Sales of reserves in place | (6) | — | — | (6) |
Production | (750) | (1) | (4) | (755) |
Economic revisions due to prices (2) | 87 | — | 1 | 88 |
Revisions of prior estimates | 57 | (1) | 1 | 58 |
Reserves, December 31, 2023 | 13,393 | 3 | 23 | 13,419 |
Extensions and discoveries | 202 | — | — | 202 |
Improved recovery | 152 | — | — | 152 |
Purchases of reserves in place | 1,090 | — | — | 1,090 |
Sales of reserves in place | (44) | — | — | (44) |
Production | (765) | (1) | (3) | (769) |
Economic revisions due to prices (2) | (3,860) | — | — | (3,860) |
Revisions of prior estimates | 988 | 1 | (2) | 987 |
Reserves, December 31, 2024 | 11,155 | 3 | 18 | 11,177 |
Extensions and discoveries | 105 | — | — | 105 |
Improved recovery | 180 | — | — | 180 |
Purchases of reserves in place | 799 | — | — | 799 |
Sales of reserves in place | — | — | — | — |
Production | (900) | (1) | (2) | (903) |
Economic revisions due to prices (2) | 1,667 | — | — | 1,667 |
Revisions of prior estimates | 700 | (2) | (10) | 688 |
Reserves, December 31, 2025 | 13,706 | — | 6 | 13,712 |
Net Proved Developed Reserves | | | | |
December 31, 2022 | 4,956 | 1 | 19 | 4,975 |
December 31, 2023 | 4,029 | 1 | 10 | 4,040 |
December 31, 2024 | 3,347 | 3 | 7 | 3,357 |
December 31, 2025 | 4,455 | — | 2 | 4,457 |
(1)Information in the reserves data tables may not add due to rounding.
(2)Includes changes due to commodity price and resulting royalty volumes.
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| Canadian Natural 2025 Annual Report | 4 |
2025 total proved Natural Gas reserves increased by 2,536 Bcf primarily due to the following:
▪Extensions and discoveries: Increase of 105 Bcf primarily due to extension drilling/future offset additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.
▪Improved recovery: Increase of 180 Bcf primarily due to infill drilling additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.
▪Purchases of reserves in place: Increase of 799 Bcf primarily due to acquisitions at various Natural Gas properties in Alberta.
▪Production: Decrease of 903 Bcf.
▪Economic revisions due to prices: Increase of 1,667 Bcf primarily due to higher natural gas pricing.
▪Revisions of prior estimates: Increase of 688 Bcf primarily due to improved performance at various North America Natural Gas properties, partially offset by negative revisions at North Sea and Offshore Africa properties.
2024 total proved Natural Gas reserves decreased by 2,242 Bcf primarily due to the following:
▪Extensions and discoveries: Increase of 202 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
▪Improved recovery: Increase of 152 Bcf primarily due to infill drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
▪Purchases of reserves in place: Increase of 1,090 Bcf primarily due to acquisitions at various Natural Gas properties in Alberta.
▪Sales of reserves in place: Decrease of 44 Bcf primarily due to dispositions from various Natural Gas properties in Alberta.
▪Production: Decrease of 769 Bcf.
▪Economic revisions due to prices: Decrease of 3,860 Bcf primarily due to lower natural gas pricing.
▪Revisions of prior estimates: Increase of 987 Bcf primarily due to improved performance at various Natural Gas properties as well as category transfers from probable to proved.
2023 total proved Natural Gas reserves increased by 1,173 Bcf primarily due to the following:
▪Extensions and discoveries: Increase of 1,185 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
▪Improved recovery: Increase of 603 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia.
▪Sales of reserves in place: Decrease of 6 Bcf primarily due to dispositions from various Natural Gas properties in Alberta.
▪Production: Decrease of 755 Bcf.
▪Economic revisions due to prices: Increase of 88 Bcf primarily at various North America Natural Gas properties due to lower natural gas pricing resulting in lower royalties and higher net reserves.
▪Revisions of prior estimates: Increase of 58 Bcf primarily due to category transfers from probable to proved partially offset by negative revisions in various North American core areas as a result of decreased performance.
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5 | Canadian Natural 2025 Annual Report |
Capitalized Costs Related to Crude Oil and Natural Gas Activities
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2025 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Proved properties | | $ | 153,466 | | | $ | 9,270 | | | $ | 5,316 | | | $ | 168,052 | |
Unproved properties | | 2,651 | | | — | | | — | | | 2,651 | |
| | 156,117 | | | 9,270 | | | 5,316 | | | 170,703 | |
Less: accumulated depletion and depreciation | | (77,557) | | | (9,270) | | | (4,035) | | | (90,862) | |
Net capitalized costs | | $ | 78,560 | | | $ | — | | | $ | 1,281 | | | $ | 79,841 | |
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| | 2024 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Proved properties | | $ | 146,309 | | | $ | 9,731 | | | $ | 5,023 | | | $ | 161,063 | |
Unproved properties | | 2,478 | | | — | | | 48 | | | 2,526 | |
| | 148,787 | | | 9,731 | | | 5,071 | | | 163,589 | |
Less: accumulated depletion and depreciation | | (74,775) | | | (9,392) | | | (3,885) | | | (88,052) | |
Net capitalized costs | | $ | 74,012 | | | $ | 339 | | | $ | 1,186 | | | $ | 75,537 | |
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| | 2023 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Proved properties | | $ | 132,858 | | | $ | 8,606 | | | $ | 4,409 | | | $ | 145,873 | |
Unproved properties | | 2,108 | | | — | | | 100 | | | 2,208 | |
| | 134,966 | | | 8,606 | | | 4,509 | | | 148,081 | |
Less: accumulated depletion and depreciation | | (69,945) | | | (8,382) | | | (3,358) | | | (81,685) | |
Net capitalized costs | | $ | 65,021 | | | $ | 224 | | | $ | 1,151 | | | $ | 66,396 | |
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| Canadian Natural 2025 Annual Report | 6 |
Costs Incurred in Crude Oil and Natural Gas Activities
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| | | 2025 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Property acquisitions | | | | | | | | |
Proved | | $ | 3,534 | | | $ | — | | | $ | — | | | $ | 3,534 | |
Unproved | | 172 | | | — | | | — | | | 172 | |
Exploration | | 36 | | | — | | | (46) | | | (10) | |
Development | | 4,938 | | | 1,223 | | | 547 | | | 6,708 | |
Costs incurred | | $ | 8,680 | | | $ | 1,223 | | | $ | 501 | | | $ | 10,404 | |
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| | 2024 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Property acquisitions | | | | | | | | |
Proved | | $ | 8,901 | | | $ | — | | | $ | — | | | $ | 8,901 | |
Unproved | | 320 | | | — | | | — | | | 320 | |
Exploration | | 102 | | | — | | | (56) | | | 46 | |
Development | | 5,543 | | | 352 | | | 205 | | | 6,100 | |
Costs incurred | | $ | 14,866 | | | $ | 352 | | | $ | 149 | | | $ | 15,367 | |
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| | 2023 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Property acquisitions | | | | | | | | |
Proved | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Unproved | | — | | | — | | | — | | | — | |
Exploration | | 43 | | | — | | | 3 | | | 46 | |
Development | | 5,039 | | | 558 | | | 187 | | | 5,784 | |
Costs incurred | | $ | 5,082 | | | $ | 558 | | | $ | 190 | | | $ | 5,830 | |
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7 | Canadian Natural 2025 Annual Report |
Results of Operations from Crude Oil and Natural Gas Producing Activities
The Company's results of operations from crude oil and natural gas producing activities for the years ended December 31, 2025, 2024, and 2023 are summarized in the following tables:
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| | | 2025 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | | $ | 29,490 | | | $ | 339 | | | $ | 187 | | | $ | 30,016 | |
Production | | (8,260) | | | (469) | | | (79) | | | (8,808) | |
Transportation | | (2,716) | | | (10) | | | — | | | (2,726) | |
Depletion, depreciation and amortization | | (7,362) | | | (1,573) | | | (432) | | | (9,367) | |
Asset retirement obligation accretion | | (307) | | | (64) | | | (9) | | | (380) | |
Petroleum revenue tax recovery | | — | | | 561 | | | — | | | 561 | |
Income tax | | (2,509) | | | 486 | | | 83 | | | (1,940) | |
Results of operations | | $ | 8,336 | | | $ | (730) | | | $ | (250) | | | $ | 7,356 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2024 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | | $ | 26,501 | | | $ | 478 | | | $ | 458 | | | $ | 27,437 | |
Production | | (7,170) | | | (440) | | | (109) | | | (7,719) | |
Transportation | | (2,038) | | | (10) | | | (1) | | | (2,049) | |
Depletion, depreciation and amortization | | (6,089) | | | (279) | | | (297) | | | (6,665) | |
Asset retirement obligation accretion | | (315) | | | (65) | | | (9) | | | (389) | |
Petroleum revenue tax recovery | | — | | | 232 | | | — | | | 232 | |
Income tax | | (2,526) | | | 34 | | | (12) | | | (2,504) | |
Results of operations | | $ | 8,363 | | | $ | (50) | | | $ | 30 | | | $ | 8,343 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | | $ | 26,773 | | | $ | 442 | | | $ | 581 | | | $ | 27,796 | |
Production | | (7,606) | | | (342) | | | (141) | | | (8,089) | |
Transportation | | (1,550) | | | (7) | | | (1) | | | (1,558) | |
Depletion, depreciation and amortization | | (5,690) | | | (494) | | | (213) | | | (6,397) | |
Asset retirement obligation accretion | | (312) | | | (46) | | | (8) | | | (366) | |
Petroleum revenue tax recovery | | — | | | 273 | | | — | | | 273 | |
Income tax | | (2,700) | | | 70 | | | (54) | | | (2,684) | |
Results of operations | | $ | 8,915 | | | $ | (104) | | | $ | 164 | | | $ | 8,975 | |
| | | | | |
| Canadian Natural 2025 Annual Report | 8 |
Standardized Measure of Discounted Future Net Cash Flows from Proved Crude Oil and Natural Gas Reserves and Changes Therein
The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been computed using the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including:
▪Future production will include production not only from proved properties, but may also include production from probable and possible reserves;
▪Future production of crude oil and natural gas from proved properties will differ from reserves estimated;
▪Future production rates will vary from those estimated;
▪Future prices and costs rather than 12-month average prices and costs as at the balance sheet date will apply;
▪Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change;
▪Future estimated income taxes do not take into account the effects of future exploration and evaluation expenditures; and
▪Future development and asset retirement obligations will differ from those estimated.
Future net revenues, development, production and asset retirement obligation costs have been based upon the estimates referred to above. The following tables summarize the Company's future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 - "Extractive Activities - Oil and Gas":
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2025 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Future cash inflows | | $ | 833,999 | | | $ | — | | | $ | 3,742 | | | $ | 837,741 | |
Future production costs | | (296,918) | | | — | | | (997) | | | (297,915) | |
Future development costs and asset retirement obligations | | (94,826) | | | — | | | (1,052) | | | (95,878) | |
Future income taxes | | (97,315) | | | — | | | (233) | | | (97,548) | |
Future net cash flows | | 344,940 | | | — | | | 1,460 | | | 346,400 | |
10% annual discount for timing of future cash flows | | (240,827) | | | — | | | (585) | | | (241,412) | |
Standardized measure of future net cash flows (1) | | $ | 104,113 | | | $ | — | | | $ | 875 | | | $ | 104,988 | |
(1)In 2025, the Company determined its North Sea reporting jurisdiction was no longer economic and de-booked all related reserves. With no proved reserves remaining, the table no longer includes future net cash flows or its components. Results from operations, income taxes, and asset retirement obligations will continue to be reported in the Company's consolidated financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2024 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Future cash inflows | | $ | 876,917 | | | $ | 722 | | | $ | 5,329 | | | $ | 882,968 | |
Future production costs | | (286,440) | | | (414) | | | (1,661) | | | (288,515) | |
Future development costs and asset retirement obligations | | (92,455) | | | (1,970) | | | (1,804) | | | (96,229) | |
Future income taxes | | (111,073) | | | 1,144 | | | (413) | | | (110,342) | |
Future net cash flows | | 386,949 | | | (518) | | | 1,451 | | | 387,882 | |
10% annual discount for timing of future cash flows | | (275,139) | | | 136 | | | (721) | | | (275,724) | |
Standardized measure of future net cash flows (1) | | $ | 111,810 | | | $ | (382) | | | $ | 730 | | | $ | 112,158 | |
(1)Includes abandonment cost estimates for the Ninian field.
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9 | Canadian Natural 2025 Annual Report |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 |
| (millions of Canadian dollars) | | North America | | North Sea | | Offshore Africa | | Total |
Future cash inflows | | $ | 863,544 | | | $ | 1,067 | | | $ | 6,144 | | | $ | 870,755 | |
Future production costs | | (276,498) | | | (636) | | | (1,880) | | | (279,014) | |
Future development costs and asset retirement obligations | | (86,615) | | | (1,873) | | | (1,927) | | | (90,415) | |
Future income taxes | | (113,516) | | | 967 | | | (508) | | | (113,057) | |
Future net cash flows | | 386,915 | | | (475) | | | 1,829 | | | 388,269 | |
10% annual discount for timing of future cash flows | | (278,814) | | | 168 | | | (887) | | | (279,533) | |
Standardized measure of future net cash flows (1) | | $ | 108,101 | | | $ | (307) | | | $ | 942 | | | $ | 108,736 | |
(1)Includes abandonment cost estimates for the Ninian field.
The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table:
| | | | | | | | | | | | | | | | | | | | |
| (millions of Canadian dollars) | | 2025 | | 2024 | | 2023 |
Sales of crude oil and natural gas produced, net of production costs | | $ | (18,544) | | | $ | (17,672) | | | $ | (18,174) | |
Net changes in sales prices and production costs | | (19,233) | | | (11,189) | | | (47,145) | |
Extensions, discoveries and improved recovery | | 3,104 | | | 2,576 | | | 8,196 | |
Changes in estimated future development costs | | (890) | | | (2,101) | | | (1,511) | |
Purchases of proved reserves in place | | 5,971 | | | 15,463 | | | — | |
Sales of proved reserves in place | | — | | | (63) | | | (47) | |
Revisions of previous reserve estimates | | 5,322 | | | (485) | | | 6,647 | |
Accretion of discount | | 14,369 | | | 14,059 | | | 17,769 | |
Changes in production timing and other | | 671 | | | 2,507 | | | (2,831) | |
Net change in income taxes | | 2,060 | | | 327 | | | 8,834 | |
Net change | | (7,170) | | | 3,422 | | | (28,262) | |
Balance – beginning of year | | 112,158 | | | 108,736 | | | 136,998 | |
Balance – end of year | | $ | 104,988 | | | $ | 112,158 | | | $ | 108,736 | |
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| Canadian Natural 2025 Annual Report | 10 |