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Supplementary Oil And Gas Information (Unaudited) | 12 Months Ended
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Dec. 31, 2023
Extractive Industries [Abstract] |
Supplementary Oil And Gas Information (Unaudited) |
Supplementary Oil & Gas Information for the Fiscal Year Ended December 31, 2023 (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 ("IFRS"). For the years ended December 31, 2023, 2022, 2021 and 2020 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, 2023, 2022, 2021 and 2020 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 2023 and 2022 reserves for SEC requirements.
| 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)
2023 | 78.10 |  | 79.95 |  | 100.93 |  | 99.48 |  | 82.51 |  | 103.43 |  |  | 2.75 |  | 2.79 |  | 2.10 |
2022 | 94.13 | 99.40 | 118.90 | 117.76 | 97.98 | 119.93 |  | 6.44 | 5.59 | 4.51
A foreign exchange rate of US$0.7407/C$1.00 was used in the 2023 evaluation (2022 - US$0.7709/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, 2023, 2022, 2021 and 2020, the reports by GLJ Ltd. covered 100% of the Company’s SCO 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, 2023, 2022, 2021 and 2020, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s crude oil, 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. The following tables summarize the Company's proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2023, 2022, 2021 and 2020:
| 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, 2020 | 6,847 |  | 2,413 |  | 525 |  | 9,785 |  | 87 |  | 71 |  | 9,943 |
Extensions and discoveries | — |  | 101 |  | 14 |  | 115 |  | — |  | — |  | 115 |
Improved recovery | — |  | 19 |  | 14 |  | 33 |  | — |  | — |  | 33 |
Purchases of reserves in place | — |  | — |  | 52 |  | 52 |  | — |  | — |  | 52 |
Sales of reserves in place | — |  | — |  | — |  | — |  | — |  | — |  | — |
Production | (150) |  | (103) |  | (45) |  | (297) |  | (6) |  | (5) |  | (309) |
Economic revisions due to prices (3) | (927) |  | (296) |  | 108 |  | (1,115) |  | 1 |  | (4) |  | (1,118) |
Revisions of prior estimates | 174 |  | 155 |  | 40 |  | 369 |  | (3) |  | 2 |  | 368 |
Reserves, December 31, 2021 | 5,944 |  | 2,289 |  | 708 |  | 8,941 |  | 79 |  | 64 |  | 9,083 |
Extensions and discoveries | — |  | 195 |  | 11 |  | 205 |  | — |  | — |  | 205 |
Improved recovery | 29 |  | 5 |  | 21 |  | 56 |  | — |  | — |  | 56 |
Purchases of reserves in place | — |  | 267 |  | 21 |  | 288 |  | — |  | — |  | 288 |
Sales of reserves in place | — |  | — |  | — |  | — |  | — |  | — |  | — |
Production | (128) |  | (91) |  | (45) |  | (265) |  | (5) |  | (5) |  | (274) |
Economic revisions due to prices (3) | (455) |  | (263) |  | (73) |  | (791) |  | 1 |  | (2) |  | (792) |
Revisions of prior estimates | — |  | 144 |  | 54 |  | 198 |  | (64) |  | — |  | 134 |
Reserves, December 31, 2022 | 5,390 |  | 2,546 |  | 696 |  | 8,632 |  | 11 |  | 57 |  | 8,700 |
Extensions and discoveries | 162 |  | 67 |  | 51 |  | 280 |  | — |  | — |  | 280 |
Improved recovery | 28 |  | 9 |  | 37 |  | 75 |  | — |  | — |  | 75 |
Purchases of reserves in place | — |  | — |  | — |  | — |  | — |  | — |  | — |
Sales of reserves in place | — |  | — |  | (1) |  | (1) |  | — |  | — |  | (1) |
Production | (141) |  | (102) |  | (47) |  | (289) |  | (5) |  | (4) |  | (298) |
Economic revisions due to prices (3) | 333 |  | 123 |  | 29 |  | 484 |  | — |  | 1 |  | 485 |
Revisions of prior estimates | 68 |  | 26 |  | 1 |  | 94 |  | 3 |  | 1 |  | 98 |
Reserves, December 31, 2023 | 5,840 |  | 2,669 |  | 767 |  | 9,276 |  | 9 |  | 54 |  | 9,339 |
Net Proved Developed Reserves |  |  |  |  |  |  |
December 31, 2020 | 6,770 |  | 628 |  | 285 |  | 7,682 |  | 32 |  | 37 |  | 7,751 |
December 31, 2021 | 5,929 |  | 584 |  | 370 |  | 6,883 |  | 39 |  | 38 |  | 6,960 |
December 31, 2022 | 5,389 |  | 582 |  | 359 |  | 6,330 |  | 5 |  | 34 |  | 6,369 |
December 31, 2023 | 5,804 |  | 610 |  | 337 |  | 6,752 |  | 6 |  | 30 |  | 6,787 |
(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 and primary heavy crude oil reserves have been classified as bitumen. (3)Includes changes due to commodity price and resulting royalty volumes. 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 lower bitumen pricing resulting in lower royalties and higher 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. 2022 total proved Crude Oil and NGLs reserves decreased by 383 MMbbl: ▪Extensions and discoveries: Increase of 205 MMbbl primarily due to extension drilling/future offset additions at various Bitumen properties. ▪Improved recovery: Increase of 56 MMbbl primarily due to improved recovery at Oil Sands Mining and Upgrading (SCO) and infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil properties. ▪Purchases of reserves in place: Increase of 288 MMbbl primarily due to a Bitumen acquisition in Alberta. ▪Production: Decrease of 274 MMbbl. ▪Economic revisions due to prices: Decrease of 792 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 134 MMbbl primarily due to improved performance at various Bitumen, North America Crude Oil and natural gas (NGLs) properties, partially offset by removal of future undeveloped reserves at North Sea. 2021 total proved Crude Oil and NGLs reserves decreased by 860 MMbbl: ▪Extensions and discoveries: Increase of 115 MMbbl primarily due to extension drilling/future offset additions at various Bitumen properties. ▪Improved recovery: Increase of 33 MMbbl primarily due to increased recovery of thermal Bitumen at Jackfish and Kirby properties and infill drilling/future offset additions at various Crude Oil and natural gas (NGLs) properties. ▪Purchases of reserves in place: Increase of 52 MMbbl primarily due to natural gas (NGLs) acquisitions in northeast British Columbia. ▪Production: Decrease of 309 MMbbl. ▪Economic revisions due to prices: Decrease of 1,118 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and thermal Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves. ▪Revisions of prior estimates: Increase of 368 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 North America and Offshore Africa Crude Oil, Bitumen and natural gas (NGLs) properties.
Natural Gas (Bcf) (1) | North America | North Sea | Offshore Africa | Total
Net Proved Reserves |  |  |  |
Reserves, December 31, 2020 | 7,655 |  | 12 |  | 34 |  | 7,701 |
Extensions and discoveries | 545 |  | — |  | — |  | 545 |
Improved recovery | 161 |  | — |  | — |  | 161 |
Purchases of reserves in place | 1,654 |  | — |  | — |  | 1,654 |
Sales of reserves in place | (1) |  | — |  | — |  | (1) |
Production | (581) |  | (1) |  | (4) |  | (587) |
Economic revisions due to prices (2) | 712 |  | — |  | (4) |  | 708 |
Revisions of prior estimates | 1,139 |  | (3) |  | — |  | 1,136 |
Reserves, December 31, 2021 | 11,285 |  | 8 |  | 25 |  | 11,318 |
Extensions and discoveries | 251 |  | — |  | — |  | 251 |
Improved recovery | 192 |  | — |  | — |  | 192 |
Purchases of reserves in place | 228 |  | — |  | — |  | 228 |
Sales of reserves in place | — |  | — |  | — |  | — |
Production | (688) |  | (1) |  | (4) |  | (693) |
Economic revisions due to prices (2) | (572) |  | — |  | (3) |  | (575) |
Revisions of prior estimates | 1,521 |  | (3) |  | 7 |  | 1,526 |
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 |
Net Proved Developed Reserves |  |  |  |
December 31, 2020 | 3,116 |  | 6 |  | 22 |  | 3,144 |
December 31, 2021 | 4,469 |  | 3 |  | 20 |  | 4,492 |
December 31, 2022 | 4,956 |  | 1 |  | 19 |  | 4,975 |
December 31, 2023 | 4,029 |  | 1 |  | 10 |  | 4,040 |
(1)Information in the reserves data tables may not add due to rounding. (2)Includes changes due to commodity price and resulting royalty volumes. 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 northwest 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. 2022 total proved Natural Gas reserves increased by 928 Bcf primarily due to the following: ▪Extensions and discoveries: Increase of 251 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪Improved recovery: Increase of 192 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪Purchases of reserves in place: Increase of 228 Bcf primarily due to property acquisitions in North America core areas. ▪Production: Decrease of 693 Bcf. ▪Economic revisions due to prices: Decrease of 575 Bcf primarily at various North America natural gas properties due to higher natural gas pricing resulting in higher royalties and lower net reserves. ▪Revisions of prior estimates: Increase of 1,526 Bcf primarily due to overall positive revisions in several North American core areas as a result of increased performance and category transfers from probable to proved. 2021 total proved Natural Gas reserves increased by 3,617 Bcf primarily due to the following: ▪Extensions and discoveries: Increase of 545 Bcf primarily due to extension drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪Improved recovery: Increase of 161 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪Purchases of reserves in place: Increase of 1,654 Bcf primarily due to the Storm Resources Ltd. and other acquisitions in northeast British Columbia. ▪Sales of reserves in place: Decrease of 1 Bcf from Natural Gas properties in North America. ▪Production: Decrease of 587 Bcf. ▪Economic revisions due to prices: Increase of 708 Bcf primarily due to increased Natural Gas price in North America. ▪Revisions of prior estimates: Increase of 1,136 Bcf primarily due to overall positive revisions in several North American core areas as a result of increased performance and category transfers from probable to proved. Capitalized Costs Related to Crude Oil and Natural Gas Activities
|  | 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 |
|  | 2022
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Proved properties |  | $ | 128,807 |  |  | $ | 8,258 |  |  | $ | 4,332 |  |  | $ | 141,397 |
Unproved properties |  | 2,128 |  |  | — |  |  | 98 |  |  | 2,226 |
|  | 130,935 |  |  | 8,258 |  |  | 4,430 |  |  | 143,623 |
Less: accumulated depletion and depreciation |  | (65,547) |  |  | (8,106) |  |  | (3,277) |  |  | (76,930) |
Net capitalized costs |  | $ | 65,388 |  |  | $ | 152 |  |  | $ | 1,153 |  |  | $ | 66,693 |
|  | 2021
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Proved properties |  | $ | 124,690 |  |  | $ | 7,438 |  |  | $ | 3,980 |  |  | $ | 136,108 |
Unproved properties |  | 2,159 |  |  | — |  |  | 91 |  |  | 2,250 |
|  | 126,849 |  |  | 7,438 |  |  | 4,071 |  |  | 138,358 |
Less: accumulated depletion and depreciation |  | (61,231) |  |  | (5,951) |  |  | (2,923) |  |  | (70,105) |
Net capitalized costs |  | $ | 65,618 |  |  | $ | 1,487 |  |  | $ | 1,148 |  |  | $ | 68,253 |
Costs Incurred in Crude Oil and Natural Gas Activities
|  | 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 |
|  | 2022
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Property acquisitions |  |  |  |  |  |  |  |
Proved |  | $ | 524 |  |  | $ | — |  |  | $ | — |  |  | $ | 524 |
Unproved |  | — |  |  | — |  |  | — |  |  | — |
Exploration |  | 40 |  |  | — |  |  | 5 |  |  | 45 |
Development |  | 4,387 |  |  | 304 |  |  | 75 |  |  | 4,766 |
Costs incurred |  | $ | 4,951 |  |  | $ | 304 |  |  | $ | 80 |  |  | $ | 5,335 |
|  | 2021
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Property acquisitions |  |  |  |  |  |  |  |
Proved |  | $ | 1,371 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,371 |
Unproved |  | 26 |  |  | — |  |  | — |  |  | 26 |
Exploration |  | 4 |  |  | — |  |  | 8 |  |  | 12 |
Development |  | 4,301 |  |  | 208 |  |  | 48 |  |  | 4,557 |
Costs incurred |  | $ | 5,702 |  |  | $ | 208 |  |  | $ | 56 |  |  | $ | 5,966 |
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, 2023, 2022 and 2021 are summarized in the following tables:
|  | 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 |  | — |  |  | 273 |  |  | — |  |  | 273 |
Income tax |  | (2,700) |  |  | 70 |  |  | (54) |  |  | (2,684) |
Results of operations |  | $ | 8,915 |  |  | $ | (104) |  |  | $ | 164 |  |  | $ | 8,975 |
|  | 2022
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs |  | $ | 31,698 |  |  | $ | 635 |  |  | $ | 687 |  |  | $ | 33,020 |
Production |  | (7,830) |  |  | (437) |  |  | (114) |  |  | (8,381) |
Transportation |  | (1,424) |  |  | (6) |  |  | (1) |  |  | (1,431) |
Depletion, depreciation and amortization |  | (5,417) |  |  | (1,747) |  |  | (173) |  |  | (7,337) |
Asset retirement obligation accretion |  | (241) |  |  | (33) |  |  | (7) |  |  | (281) |
Petroleum revenue tax |  | — |  |  | 483 |  |  | — |  |  | 483 |
Income tax |  | (3,896) |  |  | 442 |  |  | (98) |  |  | (3,552) |
Results of operations |  | $ | 12,890 |  |  | $ | (663) |  |  | $ | 294 |  |  | $ | 12,521 |
|  | 2021
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs |  | $ | 23,111 |  |  | $ | 611 |  |  | $ | 438 |  |  | $ | 24,160 |
Production |  | (6,377) |  |  | (383) |  |  | (91) |  |  | (6,851) |
Transportation |  | (1,176) |  |  | (7) |  |  | (1) |  |  | (1,184) |
Depletion, depreciation and amortization |  | (5,407) |  |  | (160) |  |  | (142) |  |  | (5,709) |
Asset retirement obligation accretion |  | (158) |  |  | (21) |  |  | (6) |  |  | (185) |
Petroleum revenue tax |  | — |  |  | 33 |  |  | — |  |  | 33 |
Income tax |  | (2,317) |  |  | (29) |  |  | (50) |  |  | (2,396) |
Results of operations |  | $ | 7,676 |  |  | $ | 44 |  |  | $ | 148 |  |  | $ | 7,868 |
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":
|  | 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.
|  | 2022
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Future cash inflows |  | $ | 986,672 |  |  | $ | 1,506 |  |  | $ | 7,304 |  |  | $ | 995,482 |
Future production costs |  | (303,270) |  |  | (691) |  |  | (1,998) |  |  | (305,959) |
Future development costs and asset retirement obligations |  | (83,803) |  |  | (1,416) |  |  | (1,439) |  |  | (86,658) |
Future income taxes |  | (136,905) |  |  | 517 |  |  | (900) |  |  | (137,288) |
Future net cash flows |  | 462,694 |  |  | (84) |  |  | 2,967 |  |  | 465,577 |
10% annual discount for timing of future cash flows |  | (327,333) |  |  | 84 |  |  | (1,330) |  |  | (328,579) |
Standardized measure of future net cash flows (1) |  | $ | 135,361 |  |  | $ | — |  |  | $ | 1,637 |  |  | $ | 136,998 |
(1)Includes abandonment cost estimates for the Ninian field.
|  | 2021
(millions of Canadian dollars) |  | North America |  | North Sea |  | Offshore Africa |  | Total
Future cash inflows |  | $ | 679,123 |  |  | $ | 7,791 |  |  | $ | 5,581 |  |  | $ | 692,495 |
Future production costs |  | (238,144) |  |  | (4,074) |  |  | (1,818) |  |  | (244,036) |
Future development costs and asset retirement obligations |  | (77,375) |  |  | (1,857) |  |  | (1,142) |  |  | (80,374) |
Future income taxes |  | (81,860) |  |  | (719) |  |  | (565) |  |  | (83,144) |
Future net cash flows |  | 281,744 |  |  | 1,141 |  |  | 2,056 |  |  | 284,941 |
10% annual discount for timing of future cash flows |  | (201,227) |  |  | (142) |  |  | (788) |  |  | (202,157) |
Standardized measure of future net cash flows |  | $ | 80,517 |  |  | $ | 999 |  |  | $ | 1,268 |  |  | $ | 82,784 |
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) |  | 2023 |  | 2022 |  | 2021
Sales of crude oil and natural gas produced, net of production costs |  | $ | (18,174) |  |  | $ | (23,242) |  |  | $ | (16,149) |
Net changes in sales prices and production costs |  | (47,145) |  |  | 79,291 |  |  | 74,558 |
Extensions, discoveries and improved recovery |  | 8,196 |  |  | 6,198 |  |  | 2,948 |
Changes in estimated future development costs |  | (1,511) |  |  | (3,640) |  |  | (2,773) |
Purchases of proved reserves in place |  | — |  |  | 5,745 |  |  | 4,010 |
Sales of proved reserves in place |  | (47) |  |  | — |  |  | (1) |
Revisions of previous reserve estimates |  | 6,647 |  |  | (9,956) |  |  | (186) |
Accretion of discount |  | 17,769 |  |  | 10,712 |  |  | 3,460 |
Changes in production timing and other |  | (2,831) |  |  | 5,463 |  |  | 6,638 |
Net change in income taxes |  | 8,834 |  |  | (16,357) |  |  | (17,232) |
Net change |  | (28,262) |  |  | 54,214 |  |  | 55,273 |
Balance - beginning of year |  | 136,998 |  |  | 82,784 |  |  | 27,511 |
Balance - end of year |  | $ | 108,736 |  |  | $ | 136,998 |  |  | $ | 82,784 |

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