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SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) | 12 Months Ended
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Dec. 31, 2019
Extractive Industries [Abstract] |
Disclosure Of Supplementary Oil And Gas Information Explanatory | Supplementary Oil & Gas Information for the Fiscal Year Ended December 31, 2019 (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, 2019, 2018, 2017 and 2016 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 to 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, 2019, 2018, 2017 and 2016 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 2019 reserves for SEC requirements.
Crude Oil and NGLs |  | Natural Gas
WTI Cushing Oklahoma |  |  | WCS |  |  | Canadian Light Sweet |  |  | Cromer LSB |  |  | North Sea Brent |  |  | Edmonton C5+ |  |  | Henry Hub Louisiana |  |  | AECO |  |  | BC Westcoast Station 2 |
(US$/bbl) |  |  | (C$/bbl) |  |  | (C$/bbl) |  |  | (C$/bbl) |  |  | (US$/bbl) |  |  | (C$/bbl) |  |  | (US$/MMBtu) |  |  | (C$/MMBtu) |  |  | (C$/MMBtu) |
55.73 |  |  | 57.29 |  |  | 66.77 |  |  | 66.85 |  |  | 62.54 |  |  | 68.71 |  |  | 2.54 |  |  | 2.02 |  |  | 1.13 |
A foreign exchange rate of US$1.00/C$1.3297 was used in the 2019 evaluation, 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, 2019, 2018, 2017 and 2016, the reports by GLJ Petroleum Consultants 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, 2019, 2018, 2017 and 2016, 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, 2019, 2018, 2017 and 2016:
|  | 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, 2016 |  | 2,542 |  |  | 1,301 |  |  | 504 |  |  | 4,347 |  |  | 93 |  |  | 74 |  |  | 4,514 |
Extensions and discoveries |  | — |  |  | 28 |  |  | 17 |  |  | 45 |  |  | — |  |  | — |  |  | 45 |
Improved recovery |  | — |  |  | 7 |  |  | 19 |  |  | 26 |  |  | 1 |  |  | — |  |  | 27 |
Purchases of reserves in place |  | 2,232 |  |  | 37 |  |  | 67 |  |  | 2,336 |  |  | — |  |  | — |  |  | 2,336 |
Sales of reserves in place |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Production |  | (100 | ) |  | (70 | ) |  | (44 | ) |  | (214 | ) |  | (9 | ) |  | (6 | ) |  | (229 | )
Economic revisions due to prices |  | — |  |  | 18 |  |  | 17 |  |  | 35 |  |  | 18 |  |  | 1 |  |  | 54 |
Revisions of prior estimates |  | 282 |  |  | 44 |  |  | 14 |  |  | 340 |  |  | 4 |  |  | — |  |  | 344 |
Reserves, December 31, 2017 |  | 4,956 |  |  | 1,365 |  |  | 594 |  |  | 6,915 |  |  | 107 |  |  | 69 |  |  | 7,091 |
Extensions and discoveries |  | 744 |  |  | 151 |  |  | 17 |  |  | 912 |  |  | — |  |  | — |  |  | 912 |
Improved recovery |  | — |  |  | 10 |  |  | 50 |  |  | 60 |  |  | 1 |  |  | 3 |  |  | 64 |
Purchases of reserves in place |  | — |  |  | 2 |  |  | 7 |  |  | 9 |  |  | 7 |  |  | — |  |  | 16 |
Sales of reserves in place |  | — |  |  | (4 | ) |  | — |  |  | (4 | ) |  | — |  |  | — |  |  | (4 | )
Production |  | (148 | ) |  | (64 | ) |  | (47 | ) |  | (259 | ) |  | (9 | ) |  | (6 | ) |  | (274 | )
Economic revisions due to prices |  | — |  |  | (45 | ) |  | (18 | ) |  | (63 | ) |  | 11 |  |  | 1 |  |  | (51 | )
Revisions of prior estimates |  | 109 |  |  | 54 |  |  | 1 |  |  | 164 |  |  | (3 | ) |  | 4 |  |  | 165 |
Reserves, December 31, 2018 |  | 5,661 |  |  | 1,469 |  |  | 604 |  |  | 7,734 |  |  | 114 |  |  | 71 |  |  | 7,919 |
Extensions and discoveries |  | 334 |  |  | 18 |  |  | 12 |  |  | 364 |  |  | — |  |  | — |  |  | 364 |
Improved recovery |  | — |  |  | 169 |  |  | 12 |  |  | 181 |  |  | — |  |  | — |  |  | 181 |
Purchases of reserves in place |  | — |  |  | 666 |  |  | 2 |  |  | 668 |  |  | — |  |  | — |  |  | 668 |
Sales of reserves in place |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Production |  | (137 | ) |  | (81 | ) |  | (49 | ) |  | (267 | ) |  | (10 | ) |  | (7 | ) |  | (285 | )
Economic revisions due to prices(3) | (288 | ) |  | 3 |  |  | — |  |  | (285 | ) |  | (1 | ) |  | 1 |  |  | (285 | )
Revisions of prior estimates |  | (17 | ) |  | (27 | ) |  | 17 |  |  | (28 | ) |  | 3 |  |  | 6 |  |  | (19 | )
Reserves, December 31, 2019 |  | 5,554 |  |  | 2,216 |  |  | 598 |  |  | 8,368 |  |  | 105 |  |  | 70 |  |  | 8,544 |
Net proved developed reserves |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 |  | 2,527 |  |  | 384 |  |  | 353 |  |  | 3,264 |  |  | 12 |  |  | 31 |  |  | 3,307 |
December 31, 2017 |  | 4,967 |  |  | 410 |  |  | 399 |  |  | 5,776 |  |  | 28 |  |  | 21 |  |  | 5,825 |
December 31, 2018 |  | 5,661 |  |  | 461 |  |  | 378 |  |  | 6,500 |  |  | 37 |  |  | 34 |  |  | 6,571 |
December 31, 2019 |  | 5,452 |  |  | 661 |  |  | 354 |  |  | 6,466 |  |  | 38 |  |  | 39 |  |  | 6,543 |
(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) | Reflects the impact of increased royalties at Oil Sands Mining and Upgrading (SCO) due to higher Bitumen pricing resulting in higher royalties and lower net reserves.
2019 total proved Crude Oil and NGLs reserves increased by 625 MMbbl:
• | Extensions and discoveries: Increase of 364 MMbbl primarily due to t he transfer of reserves from the probable category at Oil Sands Mining and Upgrading (SCO) and extension drilling/future offset additions at various Bitumen, Crude Oil and natural gas (NGLs) properties.
• | Improved recovery: Increase of 181 MMbbl primarily due to increased steamflood recovery at the Primrose thermal oil (Bitumen) project.
• | Purchases of reserves in place: Increase of 668 MMbbl primarily due to Bitumen property acquisitions from Devon Canada.
• | Production: Decrease of 285 MMbbl.
• | Economic revisions due to prices: Decrease of 285 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) due to higher Bitumen pricing resulting in higher royalties and lower net reserves.
• | Revisions of prior estimates: Decrease of 19 MMbbl primarily due to the 50-year reserves life cutoff at the Primrose thermal oil (Bitumen) project, increased royalties at Oil Sands Mining and Upgrading (SCO) as a result of lower operating costs, and the removal of future extension and infill undeveloped reserves in certain Crude Oil and Bitumen properties because of revised Company development plans, offset by improved performance at the Pelican Lake (Crude Oil) project and various natural gas (NGLs) properties.
2018 total proved Crude Oil and NGLs reserves increased by 828 MMbbl primarily due to the following:
• | Extensions and discoveries: Increase of 912 MMbbl primarily due to the addition of the Horizon South Pit to the Horizon oil sands mining and upgrading Project ("Horizon") (SCO), future thermal (Bitumen) well pad additions at Primrose and extension drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties.
• | Improved recovery: Increase of 64 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen), thermal (Bitumen), Crude Oil and natural gas (NGLs) properties as well as thermal (Bitumen) improved recovery additions.
• | Purchases of reserves in place: Increase of 16 MMbbl primarily due to property acquisitions in North America and North Sea core areas.
• | Sales of reserves in place: Decrease of 4 MMbbl from the primary heavy crude oil (Bitumen) area.
• | Production: Decrease of 274 MMbbl.
• | Economic revisions due to prices: Decrease of 51 MMbbl primarily due to increased royalties at thermal (Bitumen) and Pelican Lake (Crude Oil) projects resulting from higher prices and uneconomic reserves at several North America natural gas (NGLs) core areas, partially offset by improved reserve life economics at the North Sea.
• | Revisions of prior estimates: Increase of 165 MMbbl primarily due to geological model changes and improved mine/extraction/upgrading performance at the oil sands mining and upgrading projects (SCO) and improved recoveries at Primrose (Bitumen).
2017 total proved Crude Oil and NGLs reserves increased by 2,577 MMbbl primarily due to the following:
• | Extensions and discoveries: Increase of 45 MMbbl primarily due to future thermal (Bitumen) well pad additions at Primrose and extension drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties.
• | Improved recovery: Increase of 27 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen) and Crude Oil and natural gas (NGLs) properties.
• | Purchases of reserves in place: Increase of 2,336 MMbbl due to acquisitions of the Athabasca Oil Sands Project (SCO), Peace River thermal and Cliffdale primary heavy crude oil properties (Bitumen) and at Pelican Lake (Crude Oil).
• | Production: Decrease of 229 MMbbl.
• | Economic revisions due to prices: Increase of 54 MMbbl primarily due to improved reserves life economics at several North America Bitumen and Crude Oil core areas.
• | Revisions of prior estimates: Increase of 344 MMbbl primarily due to Horizon (SCO) revising the stratigraphic well density used to define proved reserves quantities and increasing the Horizon (SCO) total-volume-to-bitumen-in-place-ratio, partially offset by Horizon (SCO) adopting a low fines mine plan. Additionally, there were overall positive revisions at several North America Bitumen and Crude Oil core areas including improved recoveries at Primrose (Bitumen).
Natural Gas (Bcf)(1) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Net Proved Reserves |  |  |  |  |  |  |  |
Reserves, December 31, 2016 |  | 4,594 |  |  | 25 |  |  | 25 |  |  | 4,644 |
Extensions and discoveries |  | 261 |  |  | — |  |  | — |  |  | 261 |
Improved recovery |  | 179 |  |  | — |  |  | — |  |  | 179 |
Purchases of reserves in place |  | 106 |  |  | — |  |  | — |  |  | 106 |
Sales of reserves in place |  | — |  |  | — |  |  | — |  |  | — |
Production |  | (558 | ) |  | (14 | ) |  | (7 | ) |  | (579 | )
Economic revisions due to prices |  | 403 |  |  | 5 |  |  | (1 | ) |  | 407 |
Revisions of prior estimates |  | 214 |  |  | 9 |  |  | (1 | ) |  | 222 |
Reserves, December 31, 2017 |  | 5,199 |  |  | 25 |  |  | 16 |  |  | 5,240 |
Extensions and discoveries |  | 90 |  |  | — |  |  | — |  |  | 90 |
Improved recovery |  | 414 |  |  | — |  |  | — |  |  | 414 |
Purchases of reserves in place |  | 67 |  |  | — |  |  | — |  |  | 67 |
Sales of reserves in place |  | (3 | ) |  | — |  |  | — |  |  | (3 | )
Production |  | (523 | ) |  | (11 | ) |  | (8 | ) |  | (542 | )
Economic revisions due to prices |  | (746 | ) |  | — |  |  | (2 | ) |  | (748 | )
Revisions of prior estimates |  | (192 | ) |  | 13 |  |  | 15 |  |  | (164 | )
Reserves, December 31, 2018 |  | 4,306 |  |  | 27 |  |  | 21 |  |  | 4,354 |
Extensions and discoveries |  | 106 |  |  | — |  |  | — |  |  | 106 |
Improved recovery |  | 202 |  |  | — |  |  | — |  |  | 202 |
Purchases of reserves in place |  | 34 |  |  | — |  |  | — |  |  | 34 |
Sales of reserves in place |  | — |  |  | — |  |  | — |  |  | — |
Production |  | (511 | ) |  | (9 | ) |  | (8 | ) |  | (528 | )
Economic revisions due to prices |  | 246 |  |  | — |  |  | 2 |  |  | 248 |
Revisions of prior estimates |  | 346 |  |  | (2 | ) |  | 23 |  |  | 367 |
Reserves, December 31, 2019 |  | 4,728 |  |  | 16 |  |  | 38 |  |  | 4,782 |
Net proved developed reserves |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 |  | 2,805 |  |  | 18 |  |  | 18 |  |  | 2,841 |
December 31, 2017 |  | 3,081 |  |  | 22 |  |  | 9 |  |  | 3,112 |
December 31, 2018 |  | 2,382 |  |  | 23 |  |  | 12 |  |  | 2,417 |
December 31, 2019 |  | 2,342 |  |  | 11 |  |  | 28 |  |  | 2,381 |
(1) | Information in the reserves data tables may not add due to rounding.
2019 total proved Natural Gas reserves increased by 428 Bcf primarily due to the following:
• | Extensions and discoveries: Increase of 106 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
• | Improved recovery: Increase of 202 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 34 Bcf primarily due to property acquisitions in several North America core areas.
• | Production: Decrease of 528 Bcf.
• | Economic revisions due to prices: Increase of 248 Bcf primarily due to increased Natural Gas price in North America.
• | Revisions of prior estimates: Increase of 367 Bcf primarily due to overall positive revisions in several North America and Offshore Africa core areas as a result of increased recovery and category transfers from probable to proved. The increase is also due to improved economics on undeveloped reserves which, when combined with lower long term royalty rates, results in increased net, after royalties, reserves.
2018 total proved Natural Gas reserves decreased by 886 Bcf primarily due to the following:
• | Extensions and discoveries: Increase of 90 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia.
• | Improved recovery: Increase of 414 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 67 Bcf primarily due to property acquisitions in several North America core areas.
• | Sales of reserves in place: Decrease of 3 Bcf.
• | Production: Decrease of 542 Bcf.
• | Economic revisions due to prices: Decrease of 748 Bcf due to uneconomic reserves at several North America Natural Gas core areas.
• | Revisions of prior estimates: Decrease of 164 Bcf primarily due to the removal of future extension and infill undeveloped reserves at several North America properties as a result of revised Company development plans.
2017 total proved Natural Gas reserves increased by 596 Bcf primarily due to the following:
• | Extensions and discoveries: Increase of 261 Bcf primarily due to extension drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia.
• | Improved recovery: Increase of 179 Bcf primarily due to infill drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia.
• | Purchases of reserves in place: Increase of 106 Bcf primarily due to property acquisitions in several North America core areas.
• | Production: Decrease of 579 Bcf.
• | Economic revisions due to prices: Increase of 407 Bcf due to improved reserves life economics at several North America Natural Gas core areas.
• | Revisions of prior estimates: Increase of 222 Bcf primarily due to overall positive revisions at several North America core areas triggered by production optimizations and reduced production costs.
Capitalized Costs Related to Crude Oil and Natural Gas Activities
|  | 2019
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Proved properties |  | $ | 117,643 |  |  | $ | 7,296 |  |  | $ | 3,933 |  |  | $ | 128,872 |
Unproved properties |  | 2,510 |  |  | — |  |  | 69 |  |  | 2,579 |
|  | 120,153 |  |  | 7,296 |  |  | 4,002 |  |  | 131,451 |
Less: accumulated depletion and depreciation |  | (52,824 | ) |  | (5,712 | ) |  | (2,712 | ) |  | (61,248 | )
Net capitalized costs |  | $ | 67,329 |  |  | $ | 1,584 |  |  | $ | 1,290 |  |  | $ | 70,203 |
|  | 2018
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Proved properties |  | $ | 110,154 |  |  | $ | 7,321 |  |  | $ | 5,471 |  |  | $ | 122,946 |
Unproved properties |  | 2,600 |  |  | — |  |  | 37 |  |  | 2,637 |
|  | 112,754 |  |  | 7,321 |  |  | 5,508 |  |  | 125,583 |
Less: accumulated depletion and depreciation |  | (48,862 | ) |  | (5,735 | ) |  | (4,203 | ) |  | (58,800 | )
Net capitalized costs |  | $ | 63,892 |  |  | $ | 1,586 |  |  | $ | 1,305 |  |  | $ | 66,783 |
|  | 2017
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Proved properties |  | $ | 106,900 |  |  | $ | 7,126 |  |  | $ | 4,881 |  |  | $ | 118,907 |
Unproved properties |  | 2,541 |  |  | — |  |  | 91 |  |  | 2,632 |
|  | 109,441 |  |  | 7,126 |  |  | 4,972 |  |  | 121,539 |
Less: accumulated depletion and depreciation |  | (44,779 | ) |  | (5,653 | ) |  | (3,719 | ) |  | (54,151 | )
Net capitalized costs |  | $ | 64,662 |  |  | $ | 1,473 |  |  | $ | 1,253 |  |  | $ | 67,388 |
Costs Incurred in Crude Oil and Natural Gas Activities
|  | 2019
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Property acquisitions |  |  |  |  |  |  |  |
Proved |  | $ | 3,405 |  |  | $ | — |  |  | $ | — |  |  | $ | 3,405 |
Unproved |  | 91 |  |  | — |  |  | — |  |  | 91 |
Exploration |  | 38 |  |  | — |  |  | 33 |  |  | 71 |
Development |  | 4,687 |  |  | 349 |  |  | 233 |  |  | 5,269 |
Costs incurred |  | $ | 8,221 |  |  | $ | 349 |  |  | $ | 266 |  |  | $ | 8,836 |
|  | 2018
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Property acquisitions |  |  |  |  |  |  |  |  |  |  |  |
Proved |  | $ | 214 |  |  | $ | 127 |  |  | $ | — |  |  | $ | 341 |
Unproved |  | 340 |  |  | — |  |  | (89 | ) |  | 251 |
Exploration |  | 116 |  |  | — |  |  | 35 |  |  | 151 |
Development |  | 3,245 |  |  | 110 |  |  | 212 |  |  | 3,567 |
Costs incurred |  | $ | 3,915 |  |  | $ | 237 |  |  | $ | 158 |  |  | $ | 4,310 |
|  | 2017
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Property acquisitions |  |  |  |  |  |  |  |  |  |  |  |
Proved |  | $ | 15,091 |  |  | $ | — |  |  | $ | — |  |  | $ | 15,091 |
Unproved |  | 321 |  |  | — |  |  | — |  |  | 321 |
Exploration |  | 112 |  |  | — |  |  | 15 |  |  | 127 |
Development |  | 3,753 |  |  | 255 |  |  | 101 |  |  | 4,109 |
Costs incurred |  | $ | 19,277 |  |  | $ | 255 |  |  | $ | 116 |  |  | $ | 19,648 |
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, 2019, 2018 and 2017 are summarized in the following tables:
|  | 2019
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs |  | $ | 17,348 |  |  | $ | 920 |  |  | $ | 676 |  |  | $ | 18,944 |
Production |  | (5,701 | ) |  | (391 | ) |  | (109 | ) |  | (6,201 | )
Transportation |  | (968 | ) |  | (19 | ) |  | (2 | ) |  | (989 | )
Depletion, depreciation and amortization |  | (4,982 | ) |  | (308 | ) |  | (242 | ) |  | (5,532 | )
Asset retirement obligation accretion |  | (156 | ) |  | (28 | ) |  | (6 | ) |  | (190 | )
Petroleum revenue tax |  | — |  |  | 88 |  |  | — |  |  | 88 |
Income tax |  | (1,468 | ) |  | (105 | ) |  | (79 | ) |  | (1,652 | )
Results of operations |  | $ | 4,073 |  |  | $ | 157 |  |  | $ | 238 |  |  | $ | 4,468 |
|  | 2018
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs |  | $ | 16,065 |  |  | $ | 891 |  |  | $ | 647 |  |  | $ | 17,603 |
Production |  | (5,772 | ) |  | (405 | ) |  | (208 | ) |  | (6,385 | )
Transportation |  | (929 | ) |  | (22 | ) |  | (2 | ) |  | (953 | )
Depletion, depreciation and amortization |  | (4,689 | ) |  | (257 | ) |  | (201 | ) |  | (5,147 | )
Asset retirement obligation accretion |  | (148 | ) |  | (29 | ) |  | (9 | ) |  | (186 | )
Petroleum revenue tax |  | — |  |  | 12 |  |  | — |  |  | 12 |
Income tax |  | (1,223 | ) |  | (76 | ) |  | (51 | ) |  | (1,350 | )
Results of operations |  | $ | 3,304 |  |  | $ | 114 |  |  | $ | 176 |  |  | $ | 3,594 |
|  | 2017
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs |  | $ | 13,083 |  |  | $ | 784 |  |  | $ | 578 |  |  | $ | 14,445 |
Production |  | (4,962 | ) |  | (400 | ) |  | (226 | ) |  | (5,588 | )
Transportation |  | (790 | ) |  | (31 | ) |  | (1 | ) |  | (822 | )
Depletion, depreciation and amortization |  | (4,463 | ) |  | (509 | ) |  | (205 | ) |  | (5,177 | )
Asset retirement obligation accretion |  | (128 | ) |  | (27 | ) |  | (9 | ) |  | (164 | )
Petroleum revenue tax |  | — |  |  | 78 |  |  | — |  |  | 78 |
Income tax |  | (740 | ) |  | 42 |  |  | (28 | ) |  | (726 | )
Results of operations |  | $ | 2,000 |  |  | $ | (63 | ) |  | $ | 109 |  |  | $ | 2,046 |
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":
|  | 2019
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Future cash inflows |  | $ | 515,864 |  |  | $ | 10,030 |  |  | $ | 5,858 |  |  | $ | 531,752 |
Future production costs |  | (194,076 | ) |  | (4,893 | ) |  | (2,081 | ) |  | (201,050 | )
Future development costs and asset retirement obligations |  | (70,879 | ) |  | (2,648 | ) |  | (1,076 | ) |  | (74,603 | )
Future income taxes |  | (53,759 | ) |  | (936 | ) |  | (547 | ) |  | (55,242 | )
Future net cash flows |  | 197,150 |  |  | 1,553 |  |  | 2,154 |  |  | 200,857 |
10% annual discount for timing of future cash flows |  | (136,616 | ) |  | (1 | ) |  | (715 | ) |  | (137,332 | )
Standardized measure of future net cash flows |  | $ | 60,534 |  |  | $ | 1,552 |  |  | $ | 1,439 |  |  | $ | 63,525 |
|  | 2018
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Future cash inflows |  | $ | 500,557 |  |  | $ | 12,002 |  |  | $ | 6,447 |  |  | $ | 519,006 |
Future production costs |  | (193,387 | ) |  | (5,148 | ) |  | (2,284 | ) |  | (200,819 | )
Future development costs and asset retirement obligations |  | (63,202 | ) |  | (2,909 | ) |  | (1,099 | ) |  | (67,210 | )
Future income taxes |  | (60,526 | ) |  | (1,484 | ) |  | (626 | ) |  | (62,636 | )
Future net cash flows |  | 183,442 |  |  | 2,461 |  |  | 2,438 |  |  | 188,341 |
10% annual discount for timing of future cash flows |  | (126,699 | ) |  | (545 | ) |  | (771 | ) |  | (128,015 | )
Standardized measure of future net cash flows |  | $ | 56,743 |  |  | $ | 1,916 |  |  | $ | 1,667 |  |  | $ | 60,326 |
|  | 2017
(millions of Canadian dollars) |  | North America |  |  | North Sea |  |  | Offshore Africa |  |  | Total |
Future cash inflows |  | $ | 413,180 |  |  | $ | 8,740 |  |  | $ | 4,786 |  |  | $ | 426,706 |
Future production costs |  | (198,304 | ) |  | (4,168 | ) |  | (1,876 | ) |  | (204,348 | )
Future development costs and asset retirement obligations |  | (61,169 | ) |  | (2,853 | ) |  | (1,258 | ) |  | (65,280 | )
Future income taxes |  | (35,645 | ) |  | (595 | ) |  | (248 | ) |  | (36,488 | )
Future net cash flows |  | 118,062 |  |  | 1,124 |  |  | 1,404 |  |  | 120,590 |
10% annual discount for timing of future cash flows |  | (73,171 | ) |  | (59 | ) |  | (455 | ) |  | (73,685 | )
Standardized measure of future net cash flows |  | $ | 44,891 |  |  | $ | 1,065 |  |  | $ | 949 |  |  | $ | 46,905 |
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) |  | 2019 |  |  | 2018 |  |  | 2017 |
Sales of crude oil and natural gas produced, net of production costs |  | $ | (11,807 | ) |  | $ | (10,229 | ) |  | $ | (8,013 | )
Net changes in sales prices and production costs |  | (3,515 | ) |  | 20,386 |  |  | 7,466 |
Extensions, discoveries and improved recovery |  | 5,883 |  |  | 2,807 |  |  | 481 |
Changes in estimated future development costs |  | (1,889 | ) |  | (698 | ) |  | (5,548 | )
Purchases of proved reserves in place |  | 7,418 |  |  | 396 |  |  | 25,782 |
Sales of proved reserves in place |  | — |  |  | (55 | ) |  | — |
Revisions of previous reserve estimates |  | (3,384 | ) |  | 2,711 |  |  | 4,245 |
Accretion of discount |  | 8,062 |  |  | 6,119 |  |  | 3,075 |
Changes in production timing and other |  | 447 |  |  | (955 | ) |  | (662 | )
Net change in income taxes |  | 1,984 |  |  | (7,061 | ) |  | (4,236 | )
Net change |  | 3,199 |  |  | 13,421 |  |  | 22,590 |
Balance - beginning of year |  | 60,326 |  |  | 46,905 |  |  | 24,315 |
Balance - end of year |  | $ | 63,525 |  |  | $ | 60,326 |  |  | $ | 46,905 |

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