Cover
Cover | 12 Months Ended |
Dec. 31, 2023 shares | |
Document Information [Line Items] | |
Document Type | 40-F |
Document Registration Statement | false |
Document Annual Report | true |
Document Period End Date | Dec. 31, 2023 |
Current Fiscal Year End Date | --12-31 |
Entity File Number | 1-34513 |
Entity Registrant Name | CENOVUS ENERGY INC. |
Entity Incorporation, State or Country Code | Z4 |
Entity Address, Address Line One | 4100, 225 – 6 Avenue S.W. |
Entity Address, City or Town | Calgary |
Entity Address, State or Province | AB |
Entity Address, Country | CA |
Entity Address, Postal Zip Code | T2P 1N2 |
City Area Code | 403 |
Local Phone Number | 766-2000 |
Title of 12(b) Security | Common shares, no par value (together with associated common share purchase rights) |
Trading Symbol | CVE |
Security Exchange Name | NYSE |
Annual Information Form | true |
Audited Annual Financial Statements | true |
Entity Common Stock, Shares Outstanding | 1,871,868,729 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity Emerging Growth Company | false |
ICFR Auditor Attestation Flag | true |
Document Financial Statement Error Correction [Flag] | true |
Document Financial Statement Restatement Recovery Analysis [Flag] | false |
Entity Central Index Key | 0001475260 |
Document Fiscal Year Focus | 2023 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Auditor Firm ID | 271 |
Warrants | |
Document Information [Line Items] | |
Title of 12(b) Security | Warrants (each warrant entitles the holder to purchase one common share at an exercise price of C$6.54 per share) |
Trading Symbol | CVE WS |
Security Exchange Name | NYSE |
Business Contact | |
Document Information [Line Items] | |
Entity Address, Address Line One | 28 Liberty Street |
Entity Address, City or Town | New York |
Entity Address, State or Province | NY |
Entity Address, Postal Zip Code | 10005 |
City Area Code | 212 |
Local Phone Number | 894-8940 |
Contact Personnel Name | CT Corporation System |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Name | PricewaterhouseCoopers LLP |
Auditor Location | Calgary, Alberta, Canada |
Auditor Firm ID | 271 |
Consolidated Statements of Earn
Consolidated Statements of Earnings (Loss) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Revenues | |||
Gross Sales | $ 55,474 | $ 71,765 | |
Less: Royalties | 3,270 | 4,868 | |
Revenues | 52,204 | 66,897 | |
Expenses | |||
Purchased Product | [1] | 24,715 | 33,958 |
Transportation and Blending | [1] | 10,141 | 11,126 |
Operating | [1] | 6,352 | 5,816 |
(Gain) Loss on Risk Management | 61 | 1,636 | |
Depreciation, Depletion and Amortization | 4,644 | 4,679 | |
Exploration Expense | 42 | 101 | |
(Income) Loss From Equity-Accounted Affiliates | (51) | (15) | |
General and Administrative | 688 | 865 | |
Finance Costs | 671 | 820 | |
Interest Income | (133) | (81) | |
Integration, Transaction and Other Costs | 85 | 106 | |
Foreign Exchange (Gain) Loss, Net | (67) | 343 | |
Revaluation (Gain) Loss | 34 | (549) | |
Re-measurement of Contingent Payments | 59 | 162 | |
(Gain) Loss on Divestiture of Assets | (14) | (269) | |
Other (Income) Loss, Net | (63) | (532) | |
Earnings (Loss) Before Income Tax | 5,040 | 8,731 | |
Income Tax Expense (Recovery) | 931 | 2,281 | |
Net Earnings (Loss) | $ 4,109 | $ 6,450 | |
Net Earnings (Loss) Per Common Share ($) | |||
Net Earnings (Loss) Per Share — Basic (CAD per share) | $ 2.15 | $ 3.29 | |
Net Earnings (Loss) Per Share — Diluted (CAD per share) | $ 2.12 | $ 3.20 | |
[1] Comparative periods reflect certain revisions. See Note 39. |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Statement of comprehensive income [abstract] | |||
Net Earnings (Loss) | $ 4,109 | $ 6,450 | |
Items That Will not be Reclassified to Profit or Loss: | |||
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits | (44) | 71 | |
Change in the fair value of equity instruments at FVOCI | [1] | 56 | 2 |
Items That may be Reclassified to Profit or Loss: | |||
Foreign Currency Translation Adjustment | (274) | 713 | |
Total Other Comprehensive Income (Loss), Net of Tax | (262) | 786 | |
Comprehensive Income (Loss) | $ 3,847 | $ 7,236 | |
[1] Fair value through other comprehensive income (loss) (“FVOCI”). |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Current Assets | ||
Cash and Cash Equivalents | $ 2,227 | $ 4,524 |
Accounts Receivable and Accrued Revenues | 3,035 | 3,473 |
Income Tax Receivable | 416 | 121 |
Inventories | 4,030 | 4,312 |
Total Current Assets | 9,708 | 12,430 |
Restricted Cash | 211 | 209 |
Exploration and Evaluation Assets, Net | 738 | 685 |
Property, Plant and Equipment, Net | 37,250 | 36,499 |
Right-of-Use Assets, Net | 1,680 | 1,845 |
Income Tax Receivable | 25 | 25 |
Investments in Equity-Accounted Affiliates | 366 | 365 |
Other Assets | 318 | 342 |
Deferred Income Taxes | 696 | 546 |
Goodwill | 2,923 | 2,923 |
Total Assets | 53,915 | 55,869 |
Current Liabilities | ||
Accounts Payable and Accrued Liabilities | 5,480 | 6,124 |
Income Tax Payable | 88 | 1,211 |
Short-Term Borrowings | 179 | 115 |
Lease Liabilities | 299 | 308 |
Contingent Payments | 164 | 263 |
Total Current Liabilities | 6,210 | 8,021 |
Long-Term Debt | 7,108 | 8,691 |
Lease Liabilities | 2,359 | 2,528 |
Contingent Payments | 0 | 156 |
Decommissioning Liabilities | 4,155 | 3,559 |
Other Liabilities | 1,183 | 1,042 |
Deferred Income Taxes | 4,188 | 4,283 |
Total Liabilities | 25,203 | 28,280 |
Shareholders’ Equity | 28,698 | 27,576 |
Non-Controlling Interest | 14 | 13 |
Total Liabilities and Equity | 53,915 | 55,869 |
Commitments And Contingencies |
Consolidated Statements of Equi
Consolidated Statements of Equity $ in Millions | CAD ($) | Common Shares CAD ($) | Preference shares CAD ($) | Common Shares CAD ($) | Common Shares Common Shares CAD ($) | Preferred Shares CAD ($) | Warrants CAD ($) | Paid in Surplus CAD ($) | Paid in Surplus Common Shares CAD ($) | Retained Earnings CAD ($) | Retained Earnings Common Shares CAD ($) | Retained Earnings Preference shares CAD ($) | AOCI CAD ($) | [1] | Non-Controlling Interest CAD ($) | |
Beginning balance at Dec. 31, 2021 | $ 23,596 | $ 17,016 | $ 519 | $ 215 | $ 4,284 | $ 878 | $ 684 | $ 12 | ||||||||
Net Earnings (Loss) | 6,450 | 6,450 | ||||||||||||||
Other Comprehensive Income (Loss), Net of Tax | 786 | 786 | ||||||||||||||
Comprehensive Income (Loss) | 7,236 | 6,450 | 786 | |||||||||||||
Common shares issued under stock option plans (in shares) | 170 | |||||||||||||||
Common Shares Issued Under Stock Option Plans | $ (138) | $ 32 | ||||||||||||||
Purchase of Common Shares Under NCIBs | [2] | (2,530) | $ (959) | (1,571) | ||||||||||||
Warrants Exercised | 62 | 93 | (31) | |||||||||||||
Stock-Based Compensation Expense | 10 | 10 | ||||||||||||||
Dividends paid | (682) | $ (35) | $ (682) | $ (35) | ||||||||||||
Variable Dividends on Common Shares | (219) | (219) | ||||||||||||||
Non-Controlling Interest | 1 | |||||||||||||||
Ending balance at Dec. 31, 2022 | 27,576 | 16,320 | 519 | 184 | 2,691 | 6,392 | 1,470 | 13 | ||||||||
Net Earnings (Loss) | 4,109 | 4,109 | ||||||||||||||
Other Comprehensive Income (Loss), Net of Tax | (262) | (262) | ||||||||||||||
Comprehensive Income (Loss) | 3,847 | 4,109 | (262) | |||||||||||||
Common shares issued under stock option plans (in shares) | 58 | |||||||||||||||
Common Shares Issued Under Stock Option Plans | (46) | 12 | ||||||||||||||
Purchase of Common Shares Under NCIBs | [2] | (1,061) | $ (373) | $ (688) | ||||||||||||
Warrants Exercised | 18 | 26 | (8) | |||||||||||||
Stock-Based Compensation Expense | 11 | 11 | ||||||||||||||
Dividends paid | (990) | $ (36) | $ (990) | $ (36) | ||||||||||||
Variable Dividends on Common Shares | $ 0 | |||||||||||||||
Warrants Purchased and Cancelled | (713) | (151) | (562) | |||||||||||||
Non-Controlling Interest | 1 | |||||||||||||||
Ending balance at Dec. 31, 2023 | $ 28,698 | $ 16,031 | $ 519 | $ 25 | $ 2,002 | $ 8,913 | $ 1,208 | $ 14 | ||||||||
[1] Accumulated other comprehensive income (loss) (“AOCI”). Normal course issuer bid (“NCIB”). |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Operating Activities | ||
Net Earnings (Loss) | $ 4,109 | $ 6,450 |
Depreciation, Depletion and Amortization | 4,644 | 4,679 |
Deferred Income Tax Expense (Recovery) | (250) | 642 |
Unrealized (Gain) Loss on Risk Management | 52 | (126) |
Unrealized Foreign Exchange (Gain) Loss | (210) | 365 |
Realized Foreign Exchange (Gain) Loss on Non-Operating Items | 98 | 146 |
Revaluation (Gain) Loss | 34 | (549) |
Re-measurement of Contingent Payments | 59 | (469) |
(Gain) Loss on Divestiture of Assets | (14) | (269) |
Unwinding of Discount on Decommissioning Liabilities | 220 | 176 |
(Income) Loss From Equity-Accounted Affiliates | (51) | (15) |
Distributions Received From Equity-Accounted Affiliates | 149 | 65 |
Other | (37) | (117) |
Settlement of Decommissioning Liabilities | (222) | (150) |
Net Change in Non-Cash Working Capital | (1,193) | 575 |
Cash From (Used in) Operating Activities | 7,388 | 11,403 |
Investing Activities | ||
Acquisitions, Net of Cash Acquired | (515) | (397) |
Capital Investment | (4,298) | (3,708) |
Proceeds From Divestitures | 12 | 1,514 |
Payment on Divestiture of Assets | 0 | (50) |
Net Change in Investments and Other | (125) | (211) |
Net Change in Non-Cash Working Capital | (369) | 538 |
Cash From (Used in) Investing Activities | (5,295) | (2,314) |
Net Cash Provided (Used) Before Financing Activities | 2,093 | 9,089 |
Financing Activities | ||
Net Issuance (Repayment) of Short-Term Borrowings | 58 | 34 |
Repayment of Long-Term Debt | (1,346) | (4,149) |
Principal Repayment of Leases | (288) | (302) |
Common Shares Issued Under Stock Option Plans | 46 | 138 |
Purchase of Common Shares Under NCIB | (1,061) | (2,530) |
Payment for Purchase of Warrants | (711) | 0 |
Proceeds From Exercise of Warrants | 18 | 62 |
Other inflows (outflows) of cash | (3) | (2) |
Cash From (Used in) Financing Activities | (4,313) | (7,676) |
Effect of Foreign Exchange on Cash and Cash Equivalents | (77) | 238 |
Increase (Decrease) in Cash and Cash Equivalents | (2,297) | 1,651 |
Cash and Cash Equivalents, Beginning of Year | 4,524 | 2,873 |
Cash and Cash Equivalents, End of Year | 2,227 | 4,524 |
Common Shares | ||
Financing Activities | ||
Dividends paid | (990) | (682) |
Variable Dividends Paid on Common Shares | 0 | (219) |
Preference shares | ||
Financing Activities | ||
Dividends paid | $ (36) | $ (26) |
Description of Business and Seg
Description of Business and Segmented Disclosures | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Reportable Segments [Abstract] | |
DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES | 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES Cenovus Energy Inc. (“Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States (“U.S.”). Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. The executive and registered office is located at 4100, 225 6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2. Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin. The Company operates through the following reportable segments: Upstream Segments • Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification. • Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification. • Offshore, Downstream Segments • Canadian Refining, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value. The Company renamed its Canadian Manufacturing segment to Canadian Refining in 2023. • U.S. Refining, Corporate and Eliminations Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for feedstock and internal usa ge of crude oil, nat ural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices. A) Results of Operations – Segment and Operational Information Upstream For the years ended December 31, Oil Sands Conventional Offshore Total 2023 2022 2023 2022 2023 2022 2023 2022 Revenues Gross Sales (1) 26,192 34,683 3,273 4,439 1,617 2,020 31,082 41,142 Less: Royalties 3,059 4,493 112 298 99 77 3,270 4,868 23,133 30,190 3,161 4,141 1,518 1,943 27,812 36,274 Expenses Purchased Product (1) 1,457 4,718 1,695 2,023 — — 3,152 6,741 Transportation and Blending (1) 10,774 12,036 298 250 16 15 11,088 12,301 Operating 2,716 2,930 590 541 384 318 3,690 3,789 Realized (Gain) Loss on Risk 17 1,527 (5) 92 — — 12 1,619 Operating Margin 8,169 8,979 583 1,235 1,118 1,610 9,870 11,824 Unrealized (Gain) Loss on Risk Management 15 (68) (19) 13 — — (4) (55) Depreciation, Depletion and 2,993 2,763 386 370 487 585 3,866 3,718 Exploration Expense 19 9 6 1 17 91 42 101 (Income) Loss From Equity- 6 8 — — (57) (23) (51) (15) Segment Income (Loss) 5,136 6,267 210 851 671 957 6,017 8,075 Downstream Canadian Refining U.S. Refining Total For the years ended December 31, 2023 2022 2023 2022 2023 2022 Revenues Gross Sales (1) 6,233 7,792 26,393 30,218 32,626 38,010 Less: Royalties — — — — — — 6,233 7,792 26,393 30,218 32,626 38,010 Expenses Purchased Product (1) 4,919 6,389 23,354 26,020 28,273 32,409 Transportation and Blending — — — — — — Operating 639 704 2,562 2,346 3,201 3,050 Realized (Gain) Loss on Risk — — — 112 — 112 Operating Margin 675 699 477 1,740 1,152 2,439 Unrealized (Gain) Loss on Risk Management — — (17) 18 (17) 18 Depreciation, Depletion and 185 208 486 640 671 848 Exploration Expense — — — — — — (Income) Loss From Equity-Accounted — — — — — — Segment Income (Loss) 490 491 8 1,082 498 1,573 (1) Comparative periods reflect certain revisions. See Note 39. Corporate and Eliminations Consolidated For the years ended December 31, 2023 2022 2023 2022 Revenues Gross Sales (1) (8,234) (7,387) 55,474 71,765 Less: Royalties — — 3,270 4,868 (8,234) (7,387) 52,204 66,897 Expenses Purchased Product (1) (6,710) (5,192) 24,715 33,958 Transportation and Blending (1) (947) (1,175) 10,141 11,126 Operating (1) (539) (1,023) 6,352 5,816 Realized (Gain) Loss on Risk Management (3) 31 9 1,762 Unrealized (Gain) Loss on Risk Management 73 (89) 52 (126) Depreciation, Depletion and Amortization 107 113 4,644 4,679 Exploration Expense — — 42 101 (Income) Loss From Equity-Accounted Affiliates — — (51) (15) Segment Income (Loss) (215) (52) 6,300 9,596 General and Administrative 688 865 688 865 Finance Costs 671 820 671 820 Interest Income (133) (81) (133) (81) Integration, Transaction and Other Costs 85 106 85 106 Foreign Exchange (Gain) Loss, Net (67) 343 (67) 343 Revaluation (Gain) Loss 34 (549) 34 (549) Re-measurement of Contingent Payment 59 162 59 162 (Gain) Loss on Divestiture of Assets (14) (269) (14) (269) Other (Income) Loss, Net (63) (532) (63) (532) 1,260 865 1,260 865 Earnings (Loss) Before Income Tax 5,040 8,731 Income Tax Expense (Recovery) 931 2,281 Net Earnings (Loss) 4,109 6,450 (1) Comparative periods reflect certain revisions. See Note 39. B) Revenues by Product For the years ended December 31, 2023 2022 Upstream Oil Sands Crude Oil (1) 22,550 28,921 NGLs (2) 352 877 Natural Gas and Other 231 392 Conventional Crude Oil 589 429 NGLs (2) 799 926 Natural Gas and Other (1) 1,773 2,786 Offshore Crude Oil 385 581 NGLs 280 354 Natural Gas 853 1,008 Total Upstream 27,812 36,274 Downstream Canadian Refining Synthetic Crude Oil 2,124 2,360 Diesel 1,752 2,164 Asphalt 571 620 Gasoline 522 948 Other Products and Services 1,264 1,700 U.S. Refining Gasoline 12,375 14,116 Distillates 9,612 11,453 Asphalt 864 533 Other Products (1) 3,542 4,116 Total Downstream 32,626 38,010 Corporate and Eliminations (1) (8,234) (7,387) Consolidated 52,204 66,897 (1) Comparative periods reflect certain revisions. See Note 39. (2) Third-party condensate sales are included within NGLs. C) Geographical Information Revenues (1) For the years ended December 31, 2023 2022 Canada (2) 25,128 33,314 United States (2) 25,943 32,221 China 1,133 1,362 Consolidated 52,204 66,897 (1) Revenues by country are classified based on where the operations are located. (2) Comparative periods reflect certain revisions. See Note 39. Non-Current Assets (1) As at December 31, 2023 2022 Canada 35,876 35,194 United States 5,230 4,824 China 1,608 2,064 Indonesia 344 365 Consolidated 43,058 42,447 (1) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill. Major Customers D) Assets by Segment E&E Assets PP&E ROU Assets As at December 31, 2023 2022 2023 2022 2023 2022 Oil Sands 729 674 24,443 24,657 849 638 Conventional — 6 2,209 2,020 1 2 Offshore 9 5 2,798 2,549 102 152 Canadian Refining — — 2,469 2,466 28 252 U.S. Refining — — 5,014 4,482 268 329 Corporate and Eliminations — — 317 325 432 472 Consolidated 738 685 37,250 36,499 1,680 1,845 Goodwill Total Assets As at December 31, 2023 2022 2023 2022 Oil Sands 2,923 2,923 31,673 32,248 Conventional — — 2,429 2,410 Offshore — — 3,511 3,339 Canadian Refining — — 2,960 3,172 U.S. Refining — — 8,660 8,324 Corporate and Eliminations — — 4,682 6,376 Consolidated 2,923 2,923 53,915 55,869 E) Capital Expenditures (1) For the years ended December 31, 2023 2022 Capital Investment Oil Sands 2,382 1,792 Conventional 452 344 Offshore Asia Pacific 7 8 Atlantic 635 302 Total Upstream 3,476 2,446 Canadian Refining 145 117 U.S. Refining 602 1,059 Total Downstream 747 1,176 Corporate and Eliminations 75 86 4,298 3,708 Acquisitions (Note 5) Oil Sands (2) 37 1,609 Conventional 5 12 U.S. Refining (3) 385 — 427 1,621 Total Capital Expenditures 4,725 5,329 (1) Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the HCML joint venture. (2) In 2022, Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-existing interest in SOSP of $1.6 billion. (3) In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) and reacquired it at fair value as required by IFRS 3. The acquisition capital above does not include the fair value of the pre-existing interest in Toledo of $368 million. |
Basis of Preparation and Statem
Basis of Preparation and Statement of Compliance | 12 Months Ended |
Dec. 31, 2023 | |
Basis Of Preparation And Statement Of Compliance [Abstract] | |
Basis of Preparation and Statement of Compliance | 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars. These Consolidated Financial Statements were prepared in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee. These Consolidated Financial Statements were prepared on a historical cost basis, except as detailed in the Company’s accounting policies as disclosed in Note 3. These Consolidated Financial Statements were approved by the Board of Directors effective February 14, 2024. |
Summary of Accounting Policies
Summary of Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Summary Of Significant Accounting Policies [Abstract] | |
Summary of Accounting Policies | 3. SUMMARY OF ACCOUNTING POLICIES A) Principles of Consolidation The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation. Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s accounts reflect its share of the assets, liabilities, revenues and expenses from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s activities relate to joint ventures, which are accounted for using the equity method of accounting. An associate is an entity for which the Company has significant influence over but does not control or jointly control the affiliate. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter to recognize the Company’s share of the associate’s profit or loss and other comprehensive income (“OCI”). B) Foreign Currency Translation The Company’s functional and presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in OCI as cumulative translation adjustments. When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests. Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the reporting date. Any gains or losses are recorded in the Consolidated Statements of Earnings (Loss). C) Revenue Recognition Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided. Cenovus recognizes revenue from the following major products and services: • Sale of crude oil, NGLs and natural gas. • Sale of petroleum and refined products. • Crude oil and natural gas processing services. • Pipeline transportation, the blending of crude oil and the storage of crude oil, diluent and natural gas. • Fee-for-service hydrocarbon transloading services. • Construction services. The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products, which is generally at a point in time. Performance obligations for crude oil and natural gas processing revenue, transportation services and transloading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Revenue associated with crude oil, NGLs and natural gas production is recorded net of royalties. Revenue associated with natural gas processing, transportation services and transloading services are generally based on fixed price contracts. Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and revenue from cost-plus contracts are recognized as services are performed. The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date, the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered or the deferral provision can no longer be extended. The costs of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market, are recorded as purchased product. E) Transportation and Blending The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of diluent used in blending, are recognized when the product is sold. F) Exploration Expense Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense. Certain costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense. G) Employee Benefit Plans The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component. Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans, benefits are not funded before retirement. Pension expense for the defined contribution pension is recorded as the benefits are earned. The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans. Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows: • Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs. • Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. • Re-measurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Re-measurements are not reclassified to net earnings in subsequent periods. Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded. H) Government Grants Government grants are recognized when there is reasonable assurance that the grant will be received and all conditions associated with the grant are met. If a grant is received, but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. Grants related to assets are recorded as a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the services were performed. I) Income Taxes Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that were enacted or substantively enacted at the Consolidated Balance Sheet date. Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively. Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes. Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current. J) Related Party Transactions The Company enters into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value. Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds. K) Net Earnings per Share Amounts Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share. L) Cash and Cash Equivalents Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a maturity of three months or less. Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within twelve months, it is classified as a non-current asset. M) Inventories Product inventories are valued at the lower of cost, using a first-in, first-out or weighted average cost basis, and net realizable value. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand. N) Exploration and Evaluation Assets E&E assets consist of exploratory projects for crude oil, natural gas and NGLs that are pending the determination of proved reserves. Certain costs incurred after obtaining the legal right to explore an area and before establishing the technical feasibility and commercial viability of the field/project/area, are capitalized as E&E assets. E&E assets are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired or the future economic value has decreased. E&E assets are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources. Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as depreciation, depletion and amortization (“DD&A”), is recognized on this production using a unit-of-production method based on estimated proved reserves determined using forward prices and costs and considering any estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an energy equivalent basis. Non-producing assets classified as E&E are not depleted. Once technical feasibility and commercial viability is established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E. Any gains or losses from the divestiture of E&E assets are recognized in net earnings. O) Property, Plant and Equipment PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals. Expenditures related to renewals or enhancements that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated. Crude Oil and Natural Gas Properties Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties and related infrastructure facilities, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves. For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations, natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to be incurred in developing those reserves. Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of either the asset received, or the asset given up, cannot be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired. Included in crude oil and natural gas properties are information technology assets used to support the upstream business and are depreciated on a straight-line basis over their useful lives of three years. Refining Assets The initial costs of refining and upgrading PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs. Refining and upgrading assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows: • Land improvements and buildings: 15 to 40 years. • Office improvements and buildings: 3 to 15 years. • Refining equipment: 10 to 60 years. Also included in refining assets are information technology assets used to support the downstream business that are depreciated on a straight-line basis over their useful lives of three years. The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate. Processing, Transportation and Storage Assets, Commercial Fuels Business and Other Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, which range from three The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a prospective basis, if appropriate. P) Impairment and Impairment Reversals of Non-Financial Assets PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually. If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is estimated based on the discounted after-tax cash flows of reserves using forward prices, costs to develop and operating costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions. For Cenovus's downstream assets, FVLCOD is estimated based on discounted after-tax cash flows of refined product production using forward crude oil prices, forward crack spreads , operating expenses and future capital expenditures. E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill is allocated to the CGUs to which it contributes to the future cash flows. If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed. Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings. Q) Leases The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company has elected not to separate non-lease components. As Lessee Leases are recognized as a ROU asset and a corresponding lease liability on the date that the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments, restoration and removal costs, variable lease payments that are based on an index or a rate, estimated residual value guarantees, purchase options expected to be exercised, and termination penalties, less lease incentive receivables. These payments are discounted using the Company’s incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with reasonably similar characteristics. Lease payments are allocated between the liability and finance costs. Finance costs are charged to net earnings over the lease term. The lease liability is measured at amortized cost using the effective interest method. It is re-measured when there is a change in the future lease payments due to a change in an index or rate, if there is a change in the expected residual value guarantee or if the Company reconsiders the exercise of a purchase, extension or termination option that is within the Company's control. When the lease liability is re-measured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero. The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability, any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date. The ROU asset is depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or lease term. Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating, transportation or general and administrative expense. A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will re-measure the lease liability using the Company’s incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope. As Lessor Leases where the Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments received under operating leases as income on a straight-line basis over the lease term as other income. When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the sublease is classified as an operating lease. R) Intangible Assets Intangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset. Impairment losses are recognized in the Consolidated Statements of Earnings (Loss) as DD&A. S) Business Combinations and Goodwill Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited to net earnings. Acquisition costs are expensed as incurred. At acquisition, goodwill is allocated to the CGU to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses. Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity in accordance with the terms of the agreement. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity. When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings. T) Provisions A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings (Loss). Decommissioning Liabilities Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, surface and subsea plant and equipment, refining facilities and the crude-by-rail terminal. Cenovus recognizes decommissioning liabilities when the disturbances occur. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset. Actual expenditures incurred are charged against the accumulated liability. Onerous Contract Provisions Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss). Renewable Fuel Obligations The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured at the expected market price or on a contracted forward rate, if applicable, of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the month purchased. RINs purchased on a secondary market are measured at cost. RINs are not amortized. A net RIN position is presented in other assets and a net RVO position is included in other liabilities. U) Share Capital and Warrants Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the Company’s option. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative. Transaction costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common shares are reduced by the |
Critical Accounting Judgments a
Critical Accounting Judgments and Key Sources of Estimation Uncertainty | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of joint operations [abstract] | |
Critical Accounting Judgments and Key Sources of Estimation Uncertainty | 4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur. A) Critical Judgments in Applying Accounting Policies Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements. Joint Arrangements The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the definition of a joint operation under IFRS 11, “ Joint Arrangements ” ( “ IFRS 11 ” ); therefore, the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with BP Products North America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo, as defined under IFRS 10 , “Consolidated Financial Statements” (“IFRS 10”) , and, accordingly, Toledo was consolidated. Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP , which was jointly controlled with BP Canada Energy Group ULC (“bp Canada”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to August 31, 2022, Cenovus controls SOSP, as defined under IFRS 10, and, accordingly, SOSP was consolidated. In determining the classification of its joint arrangements under IFRS 11, the Company considered the following: • The original intention of the joint arrangements was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities. • The agreements require the partners to make contributions if funds are insufficient to meet the obligations or liabilities of the corporation and partnerships. The past development of Toledo and SOSP, and the past and future development of WRB, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans. • WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt facility. • Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services, purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does not have employees and, as such, is not capable of performing these roles. • As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. SOSP was operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants in accordance with the partnership agreement. • In each arrangement, output is taken by the partners, indicating that the partners have the rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements. Exploration and Evaluation Assets The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process. Identification of Cash-Generating Units CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and impairment reversals. Assessment of Impairment Indicators or Impairment Reversals PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. The identification of indicators of impairment or reversal of impairment requires significant judgment. B) Key Sources of Estimation Uncertainty Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could change assumptions used to determine the recoverable amount of the Company ’ s PP&E and E&E assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects, may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built into estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate market expectations and the evolving worldwide demand for energy. Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. Crude Oil and Natural Gas Reserves There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the expected future production volumes, future development and operating expenses, forward commodity prices, estimated royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands, Conventional and Offshore segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs. Recoverable Amounts Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include quantity of reserves, expected production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts f or the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets. Decommissioning Costs Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of liabilities and estimate the future value. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors. Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination The fair value of assets acquired, liabilities assumed and assets given up in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparable transactions and discounted cash flows. For the Company’s upstream assets, key assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected production volumes, quantity of reserves, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined product production , forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired. Income Tax Provisions The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination [Abstract] | |
Acquisitions | 5. ACQUISITIONS A) BP-Husky Refining LLC i) Summary of the Acquisition On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash, including cost of working capital. The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at fair value on the date of acquisition and the total consideration is allocated to the assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is recorded as goodwill. ii) Identifiable Assets Acquired and Liabilities Assumed The final purchase price allocation was based on Management’s best estimate of fair value and was retrospectively adjusted to reflect items identified with new information obtained between February 28, 2023, and December 31, 2023, about conditions that existed at the acquisition date. Changes to identifiable assets acquired and liabilities assumed includes increases to PP&E of $96 million, partially offset by decreases of $66 million to inventories, $3 million to other liabilities and $1 million to accounts payable and accrued liabilities. The impact to DD&A as a result of these measurement period adjustments was not material and prior quarters have not been restated to reflect the impact of the measurement period adjustments. The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition. As at February 28, 2023 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed Cash 69 Accounts Receivable and Accrued Revenues 3 Inventories 387 Property, Plant and Equipment 770 Right-of-Use Assets 33 Other Assets 10 Accounts Payable and Accrued Liabilities (139) Lease Liabilities (33) Decommissioning Liabilities (5) Other Liabilities (73) Total Identifiable Net Assets 1,022 The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which was collected. iii) Goodwill As at February 28, 2023 Total Purchase Consideration 514 Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo 508 Fair Value of Identifiable Net Assets (1,022) Goodwill — Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11. Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, and, accordingly Toledo was consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss of $34 million ($23 million, after tax) on the re-measurement of its pre-existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign currency translation adjustments. iv) Transaction Costs For the year ended December 31, 2023, transaction costs of $11 million (2022 – $9 million), were recognized in the Consolidated Statements of Earnings (Loss). v) Revenue and Profit Contribution The acquired business contributed revenues of $4.1 billion and a net loss of $85 million for the period from February 28, 2023, to December 31, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The Toledo Refinery returned to full operations in June 2023. If the closing of the Toledo Acquisition had occurred on January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2023, would be $52.2 billion and $4.0 billion, respectively. These amounts were calculated using results from the acquired business, adjusting them for: • Additional DD&A that would be charged assuming the fair value adjustments to PP&E had applied from January 1, 2023. • Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023. • The consequential tax effects. This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had actually occurred on January 1, 2023. B) Sunrise Oil Sands Partnership i) Summary of the Acquisition On August 31, 2022, Cenovus closed a transaction with bp Canada to purchase the remaining 50 percent interest in SOSP, in northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core strength in the oil sands. The Sunrise Acquisition was accounted for using the acquisition method pursuant to IFRS 3. The following table summarizes the fair value of total consideration: As at August 31, 2022 Cash, Net of Closing Adjustments 394 Bay Du Nord 40 Variable Payment 600 Total Consideration 1,034 Cenovus agreed to make quarterly variable payments to bp Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a specified threshold. The maximum cumulative variable payment is $600 million. ii) Identifiable Assets Acquired and Liabilities Assumed As at August 31, 2022 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed Cash 9 Accounts Receivable and Accrued Revenues 164 Inventories 88 Property, Plant and Equipment 3,218 Accounts Payable and Accrued Liabilities (313) Income Tax Payable (39) Decommissioning Liabilities (48) Deferred Income Tax Liabilities (486) Total Identifiable Net Assets 2,593 iii) Goodwill As at August 31, 2022 Total Purchase Consideration 1,034 Fair Value of Pre-Existing 50 Percent Ownership Interest in SOSP 1,559 Fair Value of Identifiable Net Assets (2,593) Goodwill — Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with bp Canada and met the definition of a joint operation under IFRS 11. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. The acquisition-date fair value of the previously held interest was estimated to be $1.6 billion . The net carrying value of the SOSP assets was $960 million, including previously recorded goodwill (see Note 23). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million , after-tax) on the re-measurement of its pre-existing interest in SOSP to fair valu e. iv) Transaction Costs For the year ended December 31, 2022, transaction costs of $2 million were recognized in the Consolidated Statements of Earnings (Loss). 8. INTEGRATION, TRANSACTION AND OTHER COSTS For the years ended December 31, 2023 2022 Integration Costs (1) 46 95 Transaction Costs (Note 5) 11 11 Other (2) 28 — 85 106 (1) For the year ended December 31, 2023, integration costs includes $46 million related to the Toledo Acquisition (2022 – $5 million related to the Toledo Acquisition and $90 million related to the Husky Arrangement). (2) Includes costs related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. |
General and Administrative
General and Administrative | 12 Months Ended |
Dec. 31, 2023 | |
General And Administrative Expenses [Abstract] | |
General and Administrative | 6. GENERAL AND ADMINISTRATIVE For the years ended December 31, 2023 2022 Salaries and Benefits 249 204 Administrative and Other 342 297 Stock-Based Compensation Expense (Recovery) (Note 32) 97 373 Other Incentive Benefits Expense (Recovery) — (9) 688 865 |
Finance Costs
Finance Costs | 12 Months Ended |
Dec. 31, 2023 | |
Finance Costs [Abstract] | |
Finance Costs | 7. FINANCE COSTS For the years ended December 31, 2023 2022 Interest Expense – Short-Term Borrowings and Long-Term Debt 362 478 Net Premium (Discount) on Redemption of Long-Term Debt (1) (84) (29) Interest Expense – Lease Liabilities (Note 20) 161 163 Unwinding of Discount on Decommissioning Liabilities (Note 27) 220 176 Other 32 37 691 825 Capitalized Interest (20) (5) 671 820 (1) Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments. |
Integration, Transaction and Ot
Integration, Transaction and Other Costs | 12 Months Ended |
Dec. 31, 2023 | |
Integration Costs [Abstract] | |
Integration, Transaction and Other Costs | 5. ACQUISITIONS A) BP-Husky Refining LLC i) Summary of the Acquisition On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash, including cost of working capital. The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at fair value on the date of acquisition and the total consideration is allocated to the assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is recorded as goodwill. ii) Identifiable Assets Acquired and Liabilities Assumed The final purchase price allocation was based on Management’s best estimate of fair value and was retrospectively adjusted to reflect items identified with new information obtained between February 28, 2023, and December 31, 2023, about conditions that existed at the acquisition date. Changes to identifiable assets acquired and liabilities assumed includes increases to PP&E of $96 million, partially offset by decreases of $66 million to inventories, $3 million to other liabilities and $1 million to accounts payable and accrued liabilities. The impact to DD&A as a result of these measurement period adjustments was not material and prior quarters have not been restated to reflect the impact of the measurement period adjustments. The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition. As at February 28, 2023 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed Cash 69 Accounts Receivable and Accrued Revenues 3 Inventories 387 Property, Plant and Equipment 770 Right-of-Use Assets 33 Other Assets 10 Accounts Payable and Accrued Liabilities (139) Lease Liabilities (33) Decommissioning Liabilities (5) Other Liabilities (73) Total Identifiable Net Assets 1,022 The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which was collected. iii) Goodwill As at February 28, 2023 Total Purchase Consideration 514 Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo 508 Fair Value of Identifiable Net Assets (1,022) Goodwill — Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11. Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, and, accordingly Toledo was consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss of $34 million ($23 million, after tax) on the re-measurement of its pre-existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign currency translation adjustments. iv) Transaction Costs For the year ended December 31, 2023, transaction costs of $11 million (2022 – $9 million), were recognized in the Consolidated Statements of Earnings (Loss). v) Revenue and Profit Contribution The acquired business contributed revenues of $4.1 billion and a net loss of $85 million for the period from February 28, 2023, to December 31, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The Toledo Refinery returned to full operations in June 2023. If the closing of the Toledo Acquisition had occurred on January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2023, would be $52.2 billion and $4.0 billion, respectively. These amounts were calculated using results from the acquired business, adjusting them for: • Additional DD&A that would be charged assuming the fair value adjustments to PP&E had applied from January 1, 2023. • Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023. • The consequential tax effects. This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had actually occurred on January 1, 2023. B) Sunrise Oil Sands Partnership i) Summary of the Acquisition On August 31, 2022, Cenovus closed a transaction with bp Canada to purchase the remaining 50 percent interest in SOSP, in northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core strength in the oil sands. The Sunrise Acquisition was accounted for using the acquisition method pursuant to IFRS 3. The following table summarizes the fair value of total consideration: As at August 31, 2022 Cash, Net of Closing Adjustments 394 Bay Du Nord 40 Variable Payment 600 Total Consideration 1,034 Cenovus agreed to make quarterly variable payments to bp Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a specified threshold. The maximum cumulative variable payment is $600 million. ii) Identifiable Assets Acquired and Liabilities Assumed As at August 31, 2022 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed Cash 9 Accounts Receivable and Accrued Revenues 164 Inventories 88 Property, Plant and Equipment 3,218 Accounts Payable and Accrued Liabilities (313) Income Tax Payable (39) Decommissioning Liabilities (48) Deferred Income Tax Liabilities (486) Total Identifiable Net Assets 2,593 iii) Goodwill As at August 31, 2022 Total Purchase Consideration 1,034 Fair Value of Pre-Existing 50 Percent Ownership Interest in SOSP 1,559 Fair Value of Identifiable Net Assets (2,593) Goodwill — Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with bp Canada and met the definition of a joint operation under IFRS 11. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. The acquisition-date fair value of the previously held interest was estimated to be $1.6 billion . The net carrying value of the SOSP assets was $960 million, including previously recorded goodwill (see Note 23). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million , after-tax) on the re-measurement of its pre-existing interest in SOSP to fair valu e. iv) Transaction Costs For the year ended December 31, 2022, transaction costs of $2 million were recognized in the Consolidated Statements of Earnings (Loss). 8. INTEGRATION, TRANSACTION AND OTHER COSTS For the years ended December 31, 2023 2022 Integration Costs (1) 46 95 Transaction Costs (Note 5) 11 11 Other (2) 28 — 85 106 (1) For the year ended December 31, 2023, integration costs includes $46 million related to the Toledo Acquisition (2022 – $5 million related to the Toledo Acquisition and $90 million related to the Husky Arrangement). (2) Includes costs related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. |
Foreign Exchange (Gain) Loss, N
Foreign Exchange (Gain) Loss, Net | 12 Months Ended |
Dec. 31, 2023 | |
Foreign Exchange Gains Losses [Abstract] | |
Foreign Exchange (Gain) Loss, Net | 9. FOREIGN EXCHANGE (GAIN) LOSS, NET For the years ended December 31, 2023 2022 Unrealized Foreign Exchange (Gain) Loss on Translation of: U.S. Dollar Debt Issued From Canada (231) 365 Other 21 — Unrealized Foreign Exchange (Gain) Loss (210) 365 Realized Foreign Exchange (Gain) Loss 143 (22) (67) 343 |
Divestitures
Divestitures | 12 Months Ended |
Dec. 31, 2023 | |
Non-Current Assets Held For Sale And Discontinued Operations [Abstract] | |
Divestitures | 10. DIVESTITURES A) 2023 Divestitures There were no material divestitures in the year end December 31, 2023. B) 2022 Divestitures On January 31, 2022, the Company closed the sale of its Tucker asset in its Oil Sands segment for net proceeds of $730 million and recorded a before-tax gain of $165 million (after-tax gain – $126 million). On February 28, 2022, the Company closed the sale of its Wembley assets in its Conventional segment for net proceeds of $221 million and recorded a before-tax gain of $76 million (after-tax gain – $58 million). On May 31, 2022, the Company completed the transfer of 12.5 percent of Cenovus’s working interest in the White Rose field and satellite extensions in the Atlantic region. Cenovus paid $50 million associated with transferring the Company’s working interest, resulting in a before-tax gain of $62 million (after-tax gain – $47 million). On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. for proceeds of $110 million, with no gain or loss recognized as the investment was recorded at fair value prior to the sale. On September 13, 2022, the Company closed the sales of 337 gas stations in the retail fuels business, l oca ted across Western Canada and Ontario, for net cash proceeds of $404 million and recorded a before-tax loss of $74 million (after-tax loss – $56 million). |
Impairment Charges and Reversal
Impairment Charges and Reversals | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of impairment loss recognised or reversed for cash-generating unit [abstract] | |
Impairment Charges and Reversals | 11. IMPAIRMENT CHARGES AND REVERSALS At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest that the carrying amount may exceed the recoverable amount. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. Goodwill is tested for impairment at least annually. For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. A) Upstream Cash-Generating Units i) 2023 Impairment Charges The Company tested CGUs with associated goodwill for impairment as at December 31, 2023, and there were no impairments. No impairment indicators were identified for the remaining CGUs. Key Assumptions The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs with associated goodwill that were tested for impairment were estimated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include expected production volumes, quantity of reserves, forward commodity prices, future development and operating expenses, all consistent with Cenovus’s IQREs, and discount rates. Fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2023. All reserves were evaluated as at December 31, 2023, by the Company’s IQREs. Crude Oil, NGLs and Natural Gas Prices The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: 2024 2025 2026 2027 2028 Average Annual Increase Thereafter West Texas Intermediate (“WTI”) (US$/bbl) (1) 73.67 74.98 76.14 77.66 79.22 2.00 % Western Canadian Select at Hardisty (2) (C$/bbl) 76.74 79.77 81.12 82.88 85.04 2.00 % Condensate at Edmonton (C$/bbl) 96.79 98.75 100.71 102.72 104.78 2.00 % Alberta Energy Company Natural Gas (C$/Mcf) (3) 2.20 3.37 4.05 4.13 4.21 2.00 % (1) Barrel ("bbl"). (2) Western Canadian Select at Hardisty (“WCS”). (3) One thousand cubic feet (“Mcf”). Discount Rates Discounted future cash flows were determined by applying a discount rate of 14 percent. Sensitivities A one percent increase in the discount rate or a five percent decrease in forward commodity price estimates would not impact the results of the impairment tests performed on CGUs with associated goodwill. ii) 2022 Impairment Charges The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its carrying amount and no impairment was recorded. i) 2023 Impairment Charges and Reversals As at December 31, 2023, there were no indicators of impairment or impairment reversals for the Company's downstream CGUs. ii) 2022 Impairment Charges and Reversals As at December 31, 2022, the Company identified indicators of impairment for the Toledo CGU due to the pending acquisition of the remaining 50 percent from bp and an incident at the Toledo Refinery, and for the Superior CGU with the commissioning of the asset in preparation for restart. The total carrying amount of the Toledo and Superior CGUs was greater than the recoverable amoun t. An impairment charge of $1.5 billion was recorded as additional DD&A in the U.S. Refining segment. A s at December 31, 2022, there were also indicators of impairment reversals for the Company’s Borger, Wood River and Lima CGUs due to an increase in forward crack spreads, resulting in higher margins for refined products. An assessment indicated the recoverable amount was greater than the carrying value of the associated CGUs. As at December 31, 2022, the Company reversed impairment charges of $1.2 billion, net of DD&A that would have been recorded had no impairment been recorded. As at December 31, 2022, the aggregate recoverable amount of the U.S. Refining CGUs was estimated to be $5.4 billion. Key Assumptions The recoverable amount (Level 3) of the U.S. Refining CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included refined product production, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts. Crude Oil and Crack Spreads Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were: (US$/bbl) 2023 2024 2025 2026 2027 WTI 80.33 78.50 76.95 77.61 79.16 Differential WTI – WTS (1) (0.56) (0.56) (0.56) (0.56) (0.56) Differential WTI – WCS (23.32) (19.09) (17.42) (15.87) (15.74) Chicago 3-2-1 Crack Spread 29.37 24.10 22.12 21.70 21.67 (1) West Texas Sour (“WTS”). Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032. Discount Rates Discounted future cash flows were determined by applying a discount rate between 15 percent and 18 percent based on the individual characteristics of the CGU, and other economic and operating factors. Sensitivities The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have on the impairment amount and impairment reversal amount recorded as at December 31, 2022, for the U.S. Refining segment CGUs: One Percent Increase in the Discount Rate One Percent Decrease in the Discount Rate Five Percent Increase in the Forward Price Estimates Five Percent Decrease in the Forward Price Estimates Increase (Decrease) to Impairment Amount 69 (65) (268) 268 Increase (Decrease) to Impairment Reversal Amount (72) 14 168 (342) |
Other Income (Loss), Net
Other Income (Loss), Net | 12 Months Ended |
Dec. 31, 2023 | |
Analysis of income and expense [abstract] | |
Other Income (Loss), Net | 12. OTHER INCOME (LOSS), NET |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Income Tax Expense Continuing Operations [Abstract] | |
Income Taxes | 13. INCOME TAXES A) Income Tax Expense (Recovery) For the years ended December 31, 2023 2022 Current Tax Canada 1,041 1,252 United States (109) 104 Asia Pacific 224 262 Other International 25 21 Total Current Tax Expense (Recovery) 1,181 1,639 Deferred Tax Expense (Recovery) (250) 642 931 2,281 In December 2021, the Organization for Economic Co-operation and Development (“OECD”) issued model rules for a new global minimum tax framework (“Pillar Two”). In May 2023, the IASB issued amendments to IAS 12, “Income Taxes” (“IAS 12”) to address Pillar Two, which provide clarity on the impacts and additional disclosure requirements once legislation is substantively enacted. Cenovus has applied the mandatory temporary exemption of IAS 12 and in turn, has not recognized the impacts of Pillar Two in the deferred income tax calculation. The Company is not expecting a material impact as a result of Pillar Two. For the year ended December 31, 2023, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The decrease from the prior year is due to lower earnings compared to 2022 and a deferred income tax recovery in the U.S. of which $115 million related to a step-up in the U.S. tax basis on the Toledo Acquisition. The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: For the years ended December 31, 2023 2022 Earnings (Loss) Before Income Tax 5,040 8,731 Canadian Statutory Rate (percent) 23.7 23.7 Expected Income Tax Expense (Recovery) 1,194 2,069 Effect on Taxes Resulting From: Statutory and Other Rate Differences (38) 17 Non-Taxable Capital (Gains) Losses (15) 84 Non-Recognition of Capital (Gains) Losses (30) 84 Adjustments Arising From Prior Year Tax Filings (16) 15 Recognition of U.S. Tax Basis (115) — Other (49) 12 Total Tax Expense (Recovery) 931 2,281 Effective Tax Rate (percent) 18.5 26.1 B) Deferred Income Tax Assets and Liabilities The breakdown of deferred income tax assets and deferred income tax liabilities, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows: For the years ended December 31, 2023 2022 Deferred Income Tax Assets Deferred Income Tax Assets to be Settled Within Twelve Months (315) (31) Deferred Income Tax Assets to be Settled After More Than Twelve Months (1,174) (747) (1,489) (778) Deferred Income Tax Liabilities Deferred Income Tax Liabilities to be Settled Within Twelve Months 138 55 Deferred Income Tax Liabilities to be Settled After More Than Twelve Months 4,843 4,460 4,981 4,515 Net Deferred Income Tax Liability 3,492 3,737 The deferred income tax assets and liabilities to be settled within twelve months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year. The movement in deferred income tax assets and liabilities, without taking into consideration the offsetting of balances within the same tax jurisdiction, is: Deferred Income Tax Assets Unused Tax Losses Risk Management Other Total As at December 31, 2021 (655) (11) (788) (1,454) Charged (Credited) to Earnings 490 11 158 659 Charged (Credited) to Other Comprehensive Income 9 — 8 17 As at December 31, 2022 (156) — (622) (778) Charged (Credited) to Earnings (777) — 54 (723) Charged (Credited) to Other Comprehensive Income 19 — (7) 12 As at December 31, 2023 (914) — (575) (1,489) Deferred Income Tax Liabilities PP&E Risk Management Other Total As at December 31, 2021 3,949 — 97 4,046 Charged (Credited) to Earnings 25 11 (53) (17) Charged (Credited) to Sunrise Purchase Price Allocation 486 — — 486 As at December 31, 2022 4,460 11 44 4,515 Charged (Credited) to Earnings 495 (8) (14) 473 Charged (Credited) to Other Comprehensive Income (7) — — (7) As at December 31, 2023 4,948 3 30 4,981 Net Deferred Income Tax Liabilities Total As at December 31, 2021 2,592 Charged (Credited) to Earnings 642 Charged (Credited) to Sunrise Purchase Price Allocation 486 Charged (Credited) to Other Comprehensive Income 17 As at December 31, 2022 3,737 Charged (Credited) to Earnings (250) Charged (Credited) to Other Comprehensive Income 5 As at December 31, 2023 3,492 The deferred income tax asset of $696 million as at December 31, 2023 ( December 31, 2022 – $546 million) represents net deductible temporary differences in the U.S. jurisdiction, which have been fully recognized, as the probability of realization is expected due to forecasted taxable income. No deferred tax liability was recognized as at December 31, 2023, or December 31, 2022, on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. C) Tax Pools The approximate amounts of tax pools available, including tax losses, are: As at December 31, 2023 2022 Canada 8,547 8,505 United States 8,058 6,477 Asia Pacific 347 457 16,952 15,439 A s at December 31, 2023, the above tax pools included $126 million (December 31, 2022 – $115 million) of Canadian federal non-capital losses and $3.7 billion (December 31, 2022 – $468 million) of U.S. net operating losses. These losses expire no earlier than 2038. As at December 31, 2023, the Company had Canadian net capital losses totaling $59 million (December 31, 2022 – $28 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $141 million (December 31, 2022 – $504 million) of deductible temporary differences associated with unrealized foreign exchange losses on its U.S. denominated debt. |
Per Share Amounts
Per Share Amounts | 12 Months Ended |
Dec. 31, 2023 | |
Earnings per share [abstract] | |
Per Share Amounts | 14. PER SHARE AMOUNTS A) Net Earnings (Loss) Per Common Share – Basic and Diluted For the years ended December 31, 2023 2022 Net Earnings (Loss) 4,109 6,450 Effect of Cumulative Dividends on Preferred Shares (36) (35) Net Earnings (Loss) – Basic and Diluted 4,073 6,415 Basic – Weighted Average Number of Shares (thousands) 1,895,487 1,951,262 Dilutive Effect of Warrants 22,223 44,845 Dilutive Effect of Net Settlement Rights 7,150 10,045 Dilutive Effect of Cenovus Replacement Stock Options 580 — Diluted – Weighted Average Number of Shares (thousands) 1,925,440 2,006,152 Net Earnings (Loss) Per Common Share – Basic ($) 2.15 3.29 Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($) 2.12 3.20 (1) For the year ended December 31, 2023, net earnings of $nil (2022 – $52 million) and no common shares (2022 – 1.6 million) related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive. (2) For the year ended December 31, 2023, 1.5 million NSRs (2022 – 52 thousand) were excluded from the calculation of diluted weighted average number of shares as the effect was anti-dilutive. B) Common Share Dividends 2023 2022 For the years ended December 31, Per Share Amount Per Share Amount Base Dividends 0.525 990 0.350 682 Variable Dividends — — 0.114 219 Total Common Share Dividends Declared and Paid 0.525 990 0.464 901 The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. On February 14, 2024, the Company’s Board of Directors declared a first quarter base dividend of $0.140 per common share, payable on March 28, 2024, to common shareholders of record as at March 15, 2024. C) Preferred Share Dividends For the years ended December 31, 2023 2022 Series 1 First Preferred Shares 7 7 Series 2 First Preferred Shares 2 1 Series 3 First Preferred Shares 12 12 Series 5 First Preferred Shares 9 9 Series 7 First Preferred Shares 6 6 Total Preferred Share Dividends Declared 36 35 The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. For the year ended December 31, 2023, the Company paid $36 million in preferred share dividends (December 31, 2022 – $26 million). On January 2, 2024, the Company paid preferred share dividends of $9 million, as declared on November 1, 2023. On January 3, 2023, the Company paid preferred share dividends of $9 million, as declared on November 1, 2022. O n February 14, 2024, the Company’s Board of Directors declared first quarter divide nds of $9 million payable on April 1, 2024, to preferred shareholders of record as at March 15, 2024. |
Cash and Cash Equivalents
Cash and Cash Equivalents | 12 Months Ended |
Dec. 31, 2023 | |
Cash and cash equivalents [abstract] | |
Cash and Cash Equivalents | 15. CASH AND CASH EQUIVALENTS As at December 31, 2023 2022 Cash 2,109 3,195 Short-Term Investments 118 1,329 2,227 4,524 |
Accounts Receivable and Accrued
Accounts Receivable and Accrued Revenues | 12 Months Ended |
Dec. 31, 2023 | |
Trade and other current receivables [abstract] | |
Accounts Receivable and Accrued Revenues | 16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES As at December 31, 2023 2022 Trade and Accruals 2,722 2,962 Prepaids and Deposits 242 402 Joint Operations Receivables 49 51 Other 22 58 3,035 3,473 |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2023 | |
Classes of current inventories [abstract] | |
Inventories | 17. INVENTORIES As at December 31, 2023 2022 Product Crude Oil 2,084 2,424 Diluent 379 366 Natural Gas and NGLs 68 50 Refined Products 1,073 1,169 Total Product 3,604 4,009 Parts and Supplies 426 303 4,030 4,312 For the year ended December 31, 2023, approximately $39.1 billion of produced and purchased inventory was recorded as an expense (2022 – approximately $49.1 billion). |
Exploration and Evaluation Asse
Exploration and Evaluation Assets, Net | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Exploration And Evaluation Assets [Abstract] | |
Exploration and Evaluation Assets, Net | 18. EXPLORATION AND EVALUATION ASSETS, NET Total As at December 31, 2021 720 Additions 37 Write-downs (1) (64) Change in Decommissioning Liabilities (12) Exchange Rate Movements and Other 4 As at December 31, 2022 685 Acquisition 31 Additions 84 Transfer to PP&E (Note 19) (60) Write-downs (1) (29) Change in Decommissioning Liabilities 28 Exchange Rate Movements and Other (1) As at December 31, 2023 738 (1) For the year ended December 31, 2023 , previously capitalized E&E costs of $14 million, $6 million and $9 million in the Oil Sands, Conventional and Offshore segments, respectively, were written off as exploration expense (2022 – $2 million and $62 million in the Oil Sands and Offshore segments, respectively), as the carrying value was not considered to be recoverable. |
Property, Plant and Equipment,
Property, Plant and Equipment, Net | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of detailed information about property, plant and equipment [abstract] | |
Property, Plant and Equipment, Net | 19. PROPERTY, PLANT AND EQUIPMENT, NET Crude Oil and Natural Gas Properties Processing, Transportation and Storage Assets Refining Assets Other Assets (1) Total COST As at December 31, 2021 38,443 228 10,495 1,735 50,901 Acquisitions (Note 5) (2) 3,230 — — — 3,230 Additions 2,409 11 1,143 108 3,671 Change in Decommissioning Liabilities (186) (6) (29) (32) (253) Divestitures (Notes 5 and 10) (2) (557) — — — (557) Exchange Rate Movements and Other 189 21 523 14 747 As at December 31, 2022 43,528 254 12,132 1,825 57,739 Acquisitions (Note 5) (3) 11 — 770 — 781 Additions 3,392 14 719 89 4,214 Transfer from E&E (Note 18) 60 — — — 60 Change in Decommissioning Liabilities 542 — 21 18 581 Divestitures (Note 5) (3) (17) — (633) (17) (667) Exchange Rate Movements and Other (91) 4 (239) (7) (333) As at December 31, 2023 47,425 272 12,770 1,908 62,375 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION As at December 31, 2021 10,912 53 4,572 1,139 16,676 Depreciation, Depletion and Amortization (4) 3,461 37 466 103 4,067 Impairment Charges (Note 11) — — 1,499 — 1,499 Impairment Reversals (Note 11) — — (1,233) — (1,233) Divestitures (Notes 5 and 10) (2) (84) — — — (84) Exchange Rate Movements and Other 13 16 243 43 315 As at December 31, 2022 14,302 106 5,547 1,285 21,240 Depreciation, Depletion and Amortization (4) 3,692 19 554 86 4,351 Divestitures (Note 5) (3) (8) — (299) (12) (319) Exchange Rate Movements and Other (11) 4 (135) (5) (147) As at December 31, 2023 17,975 129 5,667 1,354 25,125 CARRYING VALUE As at December 31, 2022 29,226 148 6,585 540 36,499 As at December 31, 2023 29,450 143 7,103 554 37,250 (1) Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft. (2) In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million. (3) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million. (4) For the year ended December 31, 2023, DD&A includes asset write-downs of $20 million, $12 million and $38 million in the Oil Sands, Canadian Refining and U.S. Refining segments, respectively, (2022 – $26 million and $25 million in the Offshore and Canadian Refining segments, respectively). Assets Under Construction PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A: As at December 31, 2023 2022 Crude Oil and Natural Gas Properties 2,507 2,142 Refining Assets 243 137 2,750 2,279 |
Right of Use Assets, Net
Right of Use Assets, Net | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of quantitative information about right-of-use assets [abstract] | |
Right of Use Assets, Net | 20. LEASES A) Right-of-Use Assets, Net Real Estate Transportation and Storage Assets (1) Refining Assets Other Assets (2) Total COST As at December 31, 2021 592 1,841 161 62 2,656 Additions — 22 1 2 25 Exchange Rate Movements and Other 7 (23) 12 10 6 As at December 31, 2022 599 1,840 174 74 2,687 Acquisitions (Note 5) (3) 1 24 8 — 33 Additions 1 56 — — 57 Divestitures (Note 5) (3) — — (19) — (19) Exchange Rate Movements and Other (13) 44 (2) (4) 25 As at December 31, 2023 588 1,964 161 70 2,783 ACCUMULATED DEPRECIATION As at December 31, 2021 92 520 33 1 646 Depreciation 36 226 21 14 297 Exchange Rate Movements and Other (1) (101) 4 (3) (101) As at December 31, 2022 127 645 58 12 842 Depreciation 36 223 22 12 293 Divestitures (Note 5) (3) — — (12) — (12) Exchange Rate Movements and Other (7) (5) (3) (5) (20) As at December 31, 2023 156 863 65 19 1,103 CARRYING VALUE As at December 31, 2022 472 1,195 116 62 1,845 As at December 31, 2023 432 1,101 96 51 1,680 (1) Includes railcars, barges, vessels, pipelines, caverns and storage tanks. (2) Includes assets in the commercial fuels business, fleet vehicles and other equipment. (3) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million. |
Joint Arrangements
Joint Arrangements | 12 Months Ended |
Dec. 31, 2023 | |
Subclassifications of assets, liabilities and equities [abstract] | |
JOINT ARRANGEMENTS | 21. JOINT ARRANGEMENTS A) Joint Operations Cenovus has a number of joint operations in the Upstream segments. At December 31, 2023, the Company also has a 50 percent interest in WRB in the U.S. Refining segment. Phillips 66 holds the remaining 50 percent interest and is the operator of the Wood River Refinery in Illinois and the Borger Refinery in Texas. Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with bp. Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP , which was jointly controlled with bp Canada. Subsequent to these dates, both of these joint operations are fully controlled by Cenovus and have been consolidated, refer to Note 5 for more information on these transactions. B) Joint Ventures Husky-CNOOC Madura Ltd. The Company holds a 40 percent interest in the jointly controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture, distributions received and contributions paid are recorded in (income) loss from equity-accounted affiliates. Summarized below is the financial information for HCML accounted for using the equity method. Results of Operations For the years ended December 31, 2023 2022 Revenue 615 383 Expenses 545 350 Net Earnings (Loss) 70 33 Balance Sheet As at December 31, 2023 2022 Current Assets (1) 334 247 Non-Current Assets 1,751 1,926 Current Liabilities 140 160 Non-Current Liabilities 1,188 1,293 Net Assets 757 720 (1) Includes cash and cash equivalents of $111 million (December 31, 2022 – $64 million). For the year ended December 31, 2023 , the Company’s share o f income from the equity-accounted affiliate was $57 million (2022 – $23 million ). As at December 31, 2023 , the carrying amount of the Company’s share of net assets was $344 million (December 31, 2022 – $365 million ). These amounts do not equal the 40 percent joint control of the revenues, expenses and net assets of HCML due to differences in the values attributed to the investment and accounting policies between the joint venture and the Company. For the year ended December 31, 2023 , the Company received $93 million of distributions from HCML (2022 – $42 million ) and paid $35 million in contributions (2022 – $54 million). Husky Midstream Limited Partnership The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. The Company’s share of equity investment income related to the joint venture, in excess of cumulated unrecognized losses, distributions received and contributions paid, is recorded in (income) loss from equity-accounted affiliates . For the years ended December 31, 2023 2022 HMLP Net Earnings (Loss) 231 190 Cenovus's Share of HMLP Net Earnings (Loss) (1) (1) (23) Cenovus's Share of HMLP Other Comprehensive Income (Loss) (1) (2) 8 Distributions Received 56 23 Contributions Paid 62 31 (1) Cenovus does not receive 35 percent of HMLP's net earnings and OCI due to the nature of the profit sharing agreement. |
Other Assets
Other Assets | 12 Months Ended |
Dec. 31, 2023 | |
Other Noncurrent Assets [Abstract] | |
Other Assets | 22. OTHER ASSETS As at December 31, 2023 2022 Private Equity Investments (Note 35) 131 55 Precious Metals 76 86 Net Investment in Finance Leases 61 62 Long-Term Receivables and Prepaids 50 120 Intangible Assets (1) — 19 318 342 (1) For the year ended December 31, 2022, $49 million of |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill [Abstract] | |
Goodwill | 23. GOODWILL 2023 2022 Carrying Value, Beginning of Year 2,923 3,473 Goodwill Disposed (Note 5) — (550) Carrying Value, End of Year 2,923 2,923 The carrying amount of goodwill is allocated to the following CGUs: As at December 31, 2023 2022 Primrose (Foster Creek) 1,171 1,171 Christina Lake 1,101 1,101 Lloydminster Thermal 651 651 2,923 2,923 |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Trade and other current payables [abstract] | |
Accounts Payable and Accrued Liabilities | 24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, 2023 2022 Accruals 3,931 3,412 Trade 1,075 2,331 Employee Long-Term Incentives 284 162 Interest 69 80 Joint Operations Payable 75 66 Risk Management 19 39 Provisions for Onerous and Unfavourable Contracts 18 25 Other 9 9 5,480 6,124 |
Debt and Capital Structure
Debt and Capital Structure | 12 Months Ended |
Dec. 31, 2023 | |
Borrowings [abstract] | |
Debt and Capital Structure | 25. DEBT AND CAPITAL STRUCTURE For the year ended December 31, 2023, the annualized weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings, was 4.7 percent (2022 – 4.7 percent). As at December 31, Notes 2023 2022 Uncommitted Demand Facilities i — — WRB Uncommitted Demand Facilities ii 179 115 Total Debt Principal 179 115 i) Uncommitted Demand Facilities As at December 31, 2023, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2022 – $1.9 billion) in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at December 31, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) and no direct borrowings. ii) WRB Uncommitted Demand Facilities WRB has uncommitted demand facilities of US$450 million that may be used to cover short-term working capital requirements, of which Cenovus’s proportionate share is 50 percent. As at December 31, 2023, US$270 million was drawn on these facilities, of which Cenovus’s proportionate share was US$135 million ( C$179 million) . As at December 31, 2022, Cenovus’s proportionate share of the capacity was US$225 million and US$85 million (C$115 million) of this capacity was drawn. B) Long-Term Debt As at December 31, Notes 2023 2022 Committed Credit Facility (1) i — — U.S. Dollar Denominated Unsecured Notes ii 5,028 6,537 Canadian Dollar Unsecured Notes ii 2,000 2,000 Total Debt Principal 7,028 8,537 Debt Premiums (Discounts), Net, and Transaction Costs 80 154 Long-Term Debt 7,108 8,691 (1) The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans. i) Committed Credit Facility As at December 31, 2023, the Company had in place a committed credit facility that consists of a $1.8 billion tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at December 31, 2023, no amount was drawn on the credit facility (December 31, 2022 – $nil). ii) U.S. Dollar Denominated and Canadian Dollar Denominated Unsecured Notes For the year ended December 31, 2023, the Company purchased US$1.0 billion (2022 – US$2.6 billion and C$750 million) in principal of its outstanding unsecured notes. The principal amounts of the Company’s outstanding unsecured notes are: 2023 2022 As at December 31, US$ Principal C$ Principal and Equivalent US$ Principal C$ Principal and Equivalent U.S. Dollar Denominated Unsecured Notes 5.38% due July 15, 2025 133 176 133 181 4.25% due April 15, 2027 373 493 373 505 4.40% due April 15, 2029 183 241 240 324 2.65% due January 15, 2032 500 661 500 677 5.25% due June 15, 2037 333 441 583 790 6.80% due September 15, 2037 191 253 387 524 6.75% due November 15, 2039 652 862 935 1,267 4.45% due September 15, 2042 91 121 97 131 5.20% due September 15, 2043 27 36 29 39 5.40% due June 15, 2047 569 752 800 1,083 3.75% due February 15, 2052 750 992 750 1,016 3,802 5,028 4,827 6,537 Canadian Dollar Unsecured Notes 3.60% due March 10, 2027 750 750 3.50% due February 7, 2028 1,250 1,250 2,000 2,000 Total Unsecured Notes 7,028 8,537 C) Mandatory Debt Payments U.S. Dollar Canadian Dollar Unsecured Notes Total As at December 31, 2023 US$ Principal C$ Principal Equivalent C$ Principal C$ Principal and Equivalent 2024 — — — — 2025 133 176 — 176 2026 — — — — 2027 373 493 750 1,243 2028 — — 1,250 1,250 Thereafter 3,296 4,359 — 4,359 3,802 5,028 2,000 7,028 D) Capital Structure Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. Net Debt is used in managing the Company’s capital structure. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase the Company’s common shares or preferred shares for cancellation, issue new debt, or issue new shares. Cenovus monitors its capital structure and financing requirements using, among other things, Total Debt, Net Debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times and Net Debt at or below $4 billion over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices. On November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements. Net Debt to Adjusted EBITDA As at December 31, 2023 2022 Short-Term Borrowings 179 115 Current Portion of Long-Term Debt — — Long-Term Portion of Long-Term Debt 7,108 8,691 Total Debt 7,287 8,806 Less: Cash and Cash Equivalents (2,227) (4,524) Net Debt 5,060 4,282 Net Earnings (Loss) 4,109 6,450 Add (Deduct): Finance Costs 671 820 Interest Income (133) (81) Income Tax Expense (Recovery) 931 2,281 Depreciation, Depletion and Amortization 4,644 4,679 Exploration and Evaluation Asset Write-downs 29 64 (Income) Loss From Equity-Accounted Affiliates (51) (15) Unrealized (Gain) Loss on Risk Management 52 (126) Foreign Exchange (Gain) Loss, Net (67) 343 Revaluation (Gain) Loss 34 (549) Re-measurement of Contingent Payments 59 162 (Gain) Loss on Divestiture of Assets (14) (269) Other (Income) Loss, Net (63) (532) Adjusted EBITDA (1) 10,201 13,227 Net Debt to Adjusted EBITDA (times) 0.5 0.3 (1) Calculated on a trailing twelve-month basis. Net Debt to Adjusted Funds F low As at December 31, 2023 2022 Net Debt 5,060 4,282 Cash From (Used in) Operating Activities 7,388 11,403 (Add) Deduct: Settlement of Decommissioning Liabilities (222) (150) Net Change in Non-Cash Working Capital (1,193) 575 Adjusted Funds Flow (1) 8,803 10,978 Net Debt to Adjusted Funds Flow (times) 0.6 0.4 (1) Calculated on a trailing twelve-month basis. Net Debt to Capitalization As at December 31, 2023 2022 Net Debt 5,060 4,282 Shareholders’ Equity 28,698 27,576 Capitalization 33,758 31,858 Net Debt to Capitalization (percent) 15 13 |
Contingent Payments
Contingent Payments | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of contingent liabilities in business combination [abstract] | |
Contingent Payments | 26. CONTINGENT PAYMENTS A) Sunrise Oil Sands Partnership In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments, up to $600 million, from SOSP to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum payment over the remaining term of the contract is $194 million. The variable payment will be re-measured to fair value at each reporting date, with changes in fair value recorded to re-measurement of contingent payments. In the year ended December 31, 2023, payments totaled $299 million for the quarterly payment periods ending November 30, 2022, February 28, 2023, May 31, 2023, and August 31, 2023. 2023 2022 Contingent Payments, Beginning of Year 419 — Initial Recognition — 600 Liabilities Settled or Payable (314) (92) Re-measurement 59 (89) Contingent Payments, End of Year 164 419 Less: Current Portion 164 263 Long-Term Portion — 156 B) FCCL Partnership On May 17, 2022, the contingent payment obligation associated with the acquisition of 50 percent interest in the FCCL Partnership from ConocoPhillips Company and certain of its subsidiaries ended. The final payment of $177 million was made in July 2022. 2022 Contingent Payments, Beginning of Year 236 Re-measurement 251 Liabilities Settled (487) Contingent Payments, End of Year — |
Lease Liabilities
Lease Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Lease liabilities [abstract] | |
Lease Liabilities | 2023 2022 Lease Liabilities, Beginning of Year 2,836 2,957 Acquisitions (Note 5) (1) 33 — Additions 57 25 Interest Expense (Note 7) 161 163 Lease Payments (449) (465) Divestitures (Note 5) (1) (11) — Exchange Rate Movements and Other 31 156 Lease Liabilities, End of Year 2,658 2,836 Less: Current Portion 299 308 Long-Term Portion 2,359 2,528 (1) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The Company has variable lease payments related to property taxes for real estate contracts. The Company includes extension options in the calculation of lease liabilities when the Company has the right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company does not have any significant termination options and the residual amounts are not material. |
Decommissioning Liabilities
Decommissioning Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Provision for decommissioning, restoration and rehabilitation costs [abstract] | |
Decommissioning Liabilities | 27. DECOMMISSIONING LIABILITIES 2023 2022 Decommissioning Liabilities, Beginning of Year 3,559 3,906 Liabilities Incurred 14 22 Liabilities Acquired (Note 5) (1) (2) 5 48 Liabilities Settled (221) (215) Liabilities Divested (Note 5) (1) (2) (5) (89) Change in Estimated Future Cash Flows 330 693 Change in Discount Rates 265 (980) Unwinding of Discount on Decommissioning Liabilities (Note 7) 220 176 Exchange Rate Movements and Other (12) (2) Decommissioning Liabilities, End of Year 4,155 3,559 (1) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s decommissioning liabilities w as $2 million. (2) In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million. As at December 31, 2023, the undiscounted amount of estimated future cash flows required to settle the obligation is $15.0 billion (December 31, 2022 – $14.2 billion). Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $259 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning liabilities over the estimated life of the reserves and an increase in cost estimates. These obligations were discounted using a credit-adjusted risk-free rate of 5.5 percent (December 31, 2022 – 6.1 percent) and assumes an inflation rate of two percent (December 31, 2022 – two percent). The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2023, the Company had $211 million in restricted cash (December 31, 2022 – $209 million). Sensitivities Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities: Sensitivity 2023 2022 As at December 31, Range Increase Decrease Increase Decrease Credit-Adjusted Risk-Free Rate ± one percent (387) 515 (319) 419 Inflation Rate ± one percent 519 (392) 419 (320) |
Other Liabilities
Other Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Miscellaneous non-current liabilities [abstract] | |
Other Liabilities | 28. OTHER LIABILITIES As at December 31, 2023 2022 Renewable Volume Obligation, Net (1) 397 101 Pension and Other Post-Employment Benefit Plan 276 201 Provision for West White Rose Expansion Project (2) 156 204 Provisions for Onerous and Unfavourable Contracts 72 95 Employee Long-Term Incentives 100 245 Drilling Provisions 25 31 Deferred Revenue — 45 Other 157 120 1,183 1,042 (1) The gross amounts of the RVO and RINs asset were $785 million and $388 million, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively). (2) |
Pensions and Other Post-Employm
Pensions and Other Post-Employment Benefits | 12 Months Ended |
Dec. 31, 2023 | |
Pensions And Other Post Employment Benefits [Abstract] | |
Pensions and Other Post-Employment Benefits | 29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS The Company provides the majority of employees with a defined contribution pension plan (“DC Pension Plan”). The Company also provides OPEB plans to retirees and sponsors defined benefit pension plans in Canada and the U.S. (together, the “DB Pension Plan”). The DB Pension Plan provides pension benefits at retirement based on years of service and final average earnings. In Canada, future enrollment is limited to eligible employees who may elect to move from the defined contribution component to the defined benefit component for their future service. In the U.S., the defined benefit pension is closed to new members. The Company’s OPEB plans provides certain retired employees with health care and dental benefits. The Company is req uired to file actuarial valuations of its registered defined benefit pension plans with regulators on a periodic basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2022, and the next required actuarial valuation will be as at December 31, 2025. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2023, and the next required actuarial valuati on will be as at January 1, 2024. A) Plan Obligations, Assets and Funded Status DB Pension Plan OPEB Plans 2023 2022 2023 2022 Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year 172 220 174 225 Current Service Costs 10 16 14 8 Past Service Costs - Curtailment and Plan Amendments — — 10 — Interest Costs (1) 9 7 10 7 Benefits Paid (8) (12) (9) (8) Plan Participant Contributions 3 2 — — Re-measurements: (Gains) Losses From Experience Adjustments 4 1 1 (2) (Gains) Losses From Changes in Financial Assumptions 13 (64) 50 (57) Exchange Rate Movements and Other (1) 2 (1) 1 Defined Benefit Obligation, End of Year 202 172 249 174 Plan Assets Fair Value of Plan Assets, Beginning of Year 147 159 — — Employer Contributions 18 16 9 8 Plan Participant Contributions 3 2 — — Benefits Paid (7) (10) (9) (8) Interest Income (1) 8 4 — — Re-measurements: Return on Plan Assets (Excluding Interest Income) 10 (26) — — Exchange Rate Movements and Other (1) 2 — — Fair Value of Plan Assets, End of Year 178 147 — — Defined Benefit Pension and OPEB Asset (Liability) (2) (24) (25) (249) (174) (1) Based on the discount rate of the defined benefit obligation at the beginning of the year. (2) Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities. The weighted average duration of the obligations for the DB Pension Plan and OPEB plans are 15 years and 14 years, respectively. B) Costs OPEB Plans For the years ended December 31, 2023 2022 2023 2022 Defined Benefit Plan Cost Current Service Costs 10 16 14 8 Past Service Costs – Curtailments and Plan Amendments — — 10 — Net Interest Costs 1 3 10 7 Re-measurements: Return on Plan Assets (Excluding Interest Income) (10) 26 — — (Gains) Losses From Experience Adjustments 4 1 1 (2) (Gains) Losses From Changes in Demographic Assumptions — — — — (Gains) Losses From Changes in Financial Assumptions 13 (64) 50 (57) Defined Benefit Plan Cost (Recovery) 18 (18) 85 (44) Defined Contribution Plan Cost (1) 99 72 — — Total Plan Cost 117 54 85 (44) (1) Includes defined contribution and U.S. 401(k) plans. C) Investment Objectives and Fair Value of Plan Assets The objective of the asset allocation is to manage the funded status of the DB Pension Plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints that reduce risk by limiting exposure to individual equity investment and credit rating categories. The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced as necessary. The Canadian defined benefit pension plan and U.S. defined benefit pension plan are managed independently of each other and, accordingly, the target asset allocation is reflective of their different liability profiles. The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods. The fair value of the DB Pension Plan assets, as represented by fair value hierarchy levels are as follows: As at December 31, 2023 2022 Level 1 – Cash and Cash Equivalents 5 7 Level 2 – Equity and Fixed Income Funds 161 130 Level 3 – Real Estate Funds and Other 12 10 178 147 The DB Pension Plan does not hold any direct investment in Cenovus common shares or preferred shares. D) Funding The DB Pension Plan is funded in accordance with applicable pension legislation. Contributions are made to trust funds administered by independent trustees. The Company’s contributions to the DB Pension Plan are based on the most recent actuarial valuations and the direction of the Management Pension Committees and Human Resources and Compensation Committee of the Board of Directors. Employees participating in the Canadian defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. In the year ended December 31, 2024, the Company expects to contribute $11 million to the DB Pension Plan. The OPEB plans are funded on an as required basis. For the year ended December 31, 2024, the Company expects to contribute $13 million to the OPEB plans. E) Actuarial Assumptions and Sensitivities Actuarial Assumptions The principal weighted average actuarial assumptions used to determine benefit obligations are as follows: Defined Benefit Plan OPEB Plans For the years ended December 31, 2023 2022 2023 2022 Discount Rate (percent) 4.58 5.12 4.65 5.13 Future Salary Growth Rate (percent) 4.00 4.05 N/A N/A Average Longevity (years) 88.4 88.4 88.4 88.4 Health Care Cost Trend Rate (percent) N/A N/A 5.24 5.24 Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations. Sensitivities The sensitivity of the DB Pension Plan and OPEB plan obligations to a one percent change in future salary growth rate, health care cost trend rate, or a one 2023 2022 As at December 31, Increase Decrease Increase Decrease Discount Rate (54) 66 (43) 51 |
Share Capital and Warrants
Share Capital and Warrants | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of classes of share capital [abstract] | |
Share Capital and Warrants | 30. SHARE CAPITAL AND WARRANTS Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject to the Company’s articles. B) Issued and Outstanding – Common Shares 2023 2022 Number of Common Shares (thousands) Amount Number of Common Shares (thousands) Amount Outstanding, Beginning of Year 1,909,190 16,320 2,001,211 17,016 Issued Upon Exercise of Warrants 2,610 26 9,399 93 Issued Under Stock Option Plans 3,679 58 11,069 170 Purchase of Common Shares under NCIB (43,611) (373) (112,489) (959) Outstanding, End of Year 1,871,868 16,031 1,909,190 16,320 As at December 31, 2023, there were 45.5 million (December 31, 2022 – 43.1 million) common shares available for future issuance under the stock option plan. C) Normal Course Issuer Bid On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 133.2 million common shares during the period from November 9, 2023, to November 8, 2024. For the year ended December 31, 2023, the Company purchased and cancelled 43.6 million common shares (2022 – 112.5 million) through the NCIB. The shares were purchased at a volume weighted average price of $24.32 per common share (2022 – $22.49) for a total of $1.1 billion (2022 – $2.5 billion) . Paid in surplus was reduced by $688 million (2022 – $1.6 billion) , representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million. As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the NCIB. D) Issued and Outstanding – Preferred Shares For the year ended December 31, 2023, there were no preferred shares issued. As at December 31, 2023, there were 36 million preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 – $519 million). As at December 31, 2023 Dividend Reset Date Dividend Rate (percent) Number of Preferred Shares (thousands) Series 1 First Preferred Shares March 31, 2026 2.58 10,740 Series 2 First Preferred Shares (1) Quarterly 6.77 1,260 Series 3 First Preferred Shares December 31, 2024 4.69 10,000 Series 5 First Preferred Shares March 31, 2025 4.59 8,000 Series 7 First Preferred Shares June 30, 2025 3.94 6,000 (1) The floating-rate dividend was 5.86 percent from December 31, 2022, to March 30, 2023 (December 31, 2021, to March 30, 2022 – 1.86 percent); 6.29 percent from March 31, 2023, to June 29, 2023 (March 31, 2022, to June 29, 2022 – 2.35 percent); 6.29 percent from June 30, 2023, to September 29, 2023 (June 30, 2022, to September 29, 2022 – 3.21 percent); and 6.89 percent from September 30, 2023, to December 30, 2023 (September 30, 2022, to December 30, 2022 – 5.05 percent). Every five five five five five Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five Every five Second Preferred Shares There were no second preferred shares outstanding as at December 31, 2023 (December 31, 2022 – nil). E) Issued and Outstanding – Warrants 2023 2022 Number of Warrants (thousands) Amount Number of Warrants (thousands) Amount Outstanding, Beginning of Year 55,720 184 65,119 215 Exercised (2,610) (8) (9,399) (31) Purchased and Cancelled (45,485) (151) — — Outstanding, End of Year 7,625 25 55,720 184 The exercise price of the warrants is $6.54 per share . On June 14, 2023, Cenovus purchased and cancelled 45.5 million warrants. The price for each warrant purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million. Retained earnings was reduced by $560 million, representing the excess of the purchase price of the warrants over their average carrying value, and $2 million in transaction costs. The purchased warrants were paid in full by December 31, 2023. F) Paid in Surplus Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as Ovintiv Inc. (“Ovintiv”)) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In addition, paid in surplus includes the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIB and stock-based compensation expense related to the Company’s NSRs discussed in Note 32. Retained Earnings Prior to Ovintiv Split Stock-Based Compensation Total As at December 31, 2021 3,966 318 4,284 Stock-Based Compensation Expense — 10 10 Purchase of Common Shares Under NCIB (1,571) — (1,571) Common Shares Issued on Exercise of Stock Options — (32) (32) As at December 31, 2022 2,395 296 2,691 Stock-Based Compensation Expense — 11 11 Purchase of Common Shares Under NCIB (688) — (688) Common Shares Issued on Exercise of Stock Options — (12) (12) As at December 31, 2023 1,707 295 2,002 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | 31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Pension and Other Post-Retirement Benefits Private Equity Instruments Foreign Currency Translation Adjustment Total As at December 31, 2021 28 27 629 684 Other Comprehensive Income (Loss), Before Tax 96 2 713 811 Income Tax (Expense) Recovery (25) — — (25) As at December 31, 2022 99 29 1,342 1,470 Other Comprehensive Income (Loss), Before Tax (58) 63 (286) (281) Reclassification on Divestiture (Note 5) — — 12 12 Income Tax (Expense) Recovery 14 (7) — 7 As at December 31, 2023 55 85 1,068 1,208 |
Stock-Based Compensation Plans
Stock-Based Compensation Plans | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of terms and conditions of share-based payment arrangement [abstract] | |
Stock-Based Compensation Plans | 32. STOCK-BASED COMPENSATION PLANS A) Employee Stock Options Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market value for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years. Options issued by the Company have associated NSRs. The NSR, in lieu of exercising the option, gives the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus's common shares at the time of exercise over the exercise price of the option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the excess of the market price received from the sale of the common shares over the exercise price of the option. The NSRs vest and expire under the same term and conditions of the underlying option. Stock Options With Associated Net Settlement Rights The weighted average unit fair value of NSRs granted during the year ended December 31, 2023, was $7.41 b efore considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate (percent) 3.42 Expected Dividend Yield (percent) 1.78 Expected Volatility (1) (percent) 31.95 Expected Life (years) 5.45 (1) Expected volatility has been based on historical share volatility of the Company. Number of Stock Options with Associated Net Settlement Rights Weighted For the year ended December 31, 2023 (thousands) ($/unit) Outstanding, Beginning of Year 14,349 12.38 Granted 1,571 24.34 Exercised (3,839) 13.08 Forfeited (128) 15.78 Expired (58) 19.89 Outstanding, End of Year 11,895 13.66 Outstanding Exercisable As at December 31, 2023 Number of Weighted Average Remaining Contractual Life Weighted Average Exercise Price Number of Weighted Average Exercise Price Range of Exercise Price ($) (thousands) (years) ($/unit) (thousands) ($/unit) 5.00 to 9.99 4,303 3.83 8.77 2,218 8.85 10.00 to 14.99 4,163 2.92 11.93 3,894 11.94 15.00 to 19.99 1,851 5.13 19.88 536 19.88 20.00 to 24.99 1,561 6.17 24.25 10 22.75 25.00 to 29.99 17 6.70 27.71 — — 11,895 4.03 13.66 6,658 11.56 Cenovus Replacement Stock Options For the year ended December 31, 2023, 2.1 million Cenovus replacement stock options, with a weighted average exercise price of $9.98, were exercised and net settled for cash and 3 thousand Cenovus replacement stock options were exercised with a weighted average price of $3.54 and settled for 2 thousand common shares. The Company recorded a liability of $12 million as at December 31, 2023, (December 31, 2022 – $42 million) for Cenovus replacement stock options based on the fair value at year end using the Black-Scholes-Merton valuation model. Number of Cenovus Replacement Stock Options Weighted Average Exercise Price For the year ended December 31, 2023 (thousands) ($/unit) Outstanding, Beginning of Year 3,467 9.99 Exercised (2,113) 9.97 Forfeited (23) 6.58 Expired (326) 21.09 Outstanding, End of Year 1,005 6.49 Outstanding Exercisable As at December 31, 2023 Number of Cenovus Replacement Stock Options Weighted Average Remaining Contractual Life Weighted Average Exercise Price Number of Cenovus Replacement Stock Options Weighted Average Exercise Price Range of Exercise Price ($) (thousands) (years) ($/unit) (thousands) ($/unit) 3.00 to 4.99 782 1.22 3.54 782 3.54 5.00 to 9.99 28 0.42 6.19 28 6.19 10.00 to 14.99 — — — — — 15.00 to 19.99 195 0.18 18.35 195 18.35 1,005 0.99 6.49 1,005 6.49 B) Performance Share Units In addition to the Performance Share Unit Plan for Local Employees in the Asia Pacific Region, Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. The PSUs are time-vested whole-share units that entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible to vest is determined by a multiplier that ranges from zero percent to 200 percent and is based on the Company achieving key pre-determined performance measures. PSUs vest after three years. The Company has recorded a liability o f $238 million as at December 31, 2023, (December 31, 2022 – $216 million) for PSUs based on the market value of Cenovus’s common shares at the end of the year. PSUs are paid out upon vesting and, as a result, the intrinsic value was $nil as at December 31, 2023. Number of Performance Share Units For the year ended December 31, 2023 (thousands) Outstanding, Beginning of Year 8,678 Granted 2,539 Vested and Paid Out (972) Forfeited (231) Units in Lieu of Base Dividends 229 Outstanding, End of Year 10,243 C) Restricted Share Units In addition to the Restricted Share Unit Plan for Local Employees in the Asia Pacific Region, Cenovus granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs generally vest over three The Company recorded a liability of $97 million as at December 31, 2023, (December 31, 2022 – $109 million) for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $ nil as at December 31, 2023. Number of Restricted Share Units For the year ended December 31, 2023 (thousands) Outstanding, Beginning of Year 6,655 Granted 2,961 Vested and Paid Out (2,300) Forfeited (243) Units in Lieu of Base Dividends 161 Outstanding, End of Year 7,234 D) Deferred Share Units Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25, 50, 75 or 100 percent of their annual bonus award into DSUs. DSUs vest immediately, are settled in cash and are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment. The Company recorded a liability of $37 million as at December 31, 2023 (December 31, 2022 – $40 million) for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant. Number of Deferred For the year ended December 31, 2023 (thousands) Outstanding, Beginning of Year 1,506 Granted to Directors 126 Granted 59 Units in Lieu of Dividends 37 Redeemed (37) Outstanding, End of Year 1,691 E) Total Stock-Based Compensation For the years ended December 31, 2023 2022 Stock Options With Associated Net Settlement Rights 11 15 Cenovus Replacement Stock Options (5) 53 Performance Share Units 47 183 Restricted Share Units 46 100 Deferred Share Units (2) 22 Total Stock-Based Compensation Expense (Recovery) 97 373 |
Employee Salaries and Benefit E
Employee Salaries and Benefit Expenses | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Salaries And Employee Benefits [Abstract] | |
Employee Salaries and Benefit Expenses | 33. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, 2023 2022 Salaries, Bonuses and Other Short-Term Employee Benefits 1,344 1,246 Pension and Post-Employment Benefits 125 92 Stock-Based Compensation (Note 32) 97 373 Other Incentive Benefits (Recovery) — (9) Termination Benefits 14 27 1,580 1,729 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of transactions between related parties [abstract] | |
RELATED PARTY TRANSACTIONS | 34. RELATED PARTY TRANSACTIONS A) Key Management Compensation Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is: For the years ended December 31, 2023 2022 Salaries, Director Fees and Other Short-Term Benefits 40 40 Pension and Post-Employment Benefits 3 4 Stock-Based Compensation 40 140 Termination Benefits — 3 83 187 B) Other Related Party Transactions Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 21). As the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs. The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or on a cost recovery basis with certain restrictions. For the year ended December 31, 2023, the Company charged HMLP $160 million (2022 – $188 million) for construction costs and management services. The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the year ended December 31, 2023, the Company incurred costs of $295 million (2022 – $263 million) for the use of HMLP’s pipeline systems, as well as transportation and storage services. |
Financial Instruments
Financial Instruments | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of detailed information about financial instruments [abstract] | |
FINANCIAL INSTRUMENTS | 35. FINANCIAL INSTRUMENTS Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and certain portions of other assets and other liabilities. Risk management assets and liabilities arise from the use of derivative financial instruments. A) Fair Value of Non-Derivative Financial Instruments The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments. The fair values of restricted cash, certain portions of other assets and other liabilities, approximate their carrying amount due to the specific non-tradeable nature of these instruments. Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end trading prices of long-term debt on the secondary market (Level 2). As at December 31, 2023, the carrying value of Cenovus’s long-term debt was $7.1 billion and the fair value was $6.6 billion (December 31, 2022 carrying value – $8.7 billion, fair value – $7.8 billion). The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI: 2023 2022 Fair Value, Beginning of Year 55 53 Acquisition 13 — Changes in Fair Value 63 2 Fair Value, End of Year 131 55 B) Fair Value of Risk Management Assets and Liabilities Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable and accrued liabilities (for short-term positions), other liabilities and other assets (for long-term positions). Changes in fair value are recorded in (gain) loss on risk management. The Company’s risk manag ement assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures, as well as renewable power, power and foreign exchange contracts. The Company may also enter into swaps, forwards, and options to manage commodity, foreign exchange and interest rate exposures. Crude oil, natural gas, condensate, refined product and power contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable market data and foreign exchange forward curves (Level 2). The fair value of renewable power contracts are calculated using internal valuation models that incorporate broker pricing for relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The f air value of renewable power contracts are calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have experience in fair value techniques. Summary of Risk Management Positions 2023 2022 Risk Management Risk Management As at December 31, Asset Liability Net Asset Liability Net Crude Oil, Natural Gas, Condensate and Refined Products 11 19 (8) 2 40 (38) Power Swap Contracts 2 — 2 1 7 (6) Renewable Power Contracts 18 — 18 90 — 90 31 19 12 93 47 46 The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value: As at December 31, 2023 2022 Level 2 – Prices Sourced From Observable Data or Market Corroboration (6) (44) Level 3 – Prices Sourced From Partially Unobservable Data 18 90 12 46 The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities: 2023 2022 Fair Value of Contracts, Beginning of Year 46 (68) Change in Fair Value of Contracts in Place at Beginning of Year — (5) Change in Fair Value of Contracts Entered Into During the Year (45) (1,641) Fair Value of Contracts Realized During the Year 9 1,762 Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts 2 (2) Fair Value of Contracts, End of Year 12 46 Offsetting Financial Assets and Liabilities Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same. 2023 2022 Risk Management Risk Management As at December 31, Asset Liability Net Asset Liability Net Recognized Risk Management Positions Gross Amount 71 59 12 153 107 46 Amount Offset (40) (40) — (60) (60) — Net Amount 31 19 12 93 47 46 The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial. Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. As at December 31, 2023, $47 million was pledged as cash collateral (December 31, 2022 – $211 million). C) Earnings Impact of (Gains) Losses From Risk Management Positions For the years ended December 31, 2023 2022 Realized (Gain) Loss 9 1,762 Unrealized (Gain) Loss 52 (126) (Gain) Loss on Risk Management 61 1,636 Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. D) Fair Value of Contingent Payments The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value in the contingent payments. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing that was discounted using a credit-adjusted risk-free rate. Fair value of the variable payment was calculated by Cenovus’s internal valuation team, which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2023, the fair value of the variable payment was estimated to be $164 million applying a credit-adjusted risk-free rate of 5.6 percent. As at December 31, 2023, average WCS forward pricing for the remaining term of the variable payment is $71.86 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 39.4 percent and 5.8 percent, respectively. As at December 31, 2023 and December 31, 2022, changes in WCS forward prices, with fluctuations in all other variables held constant, could have impacted earnings before income tax as follows: 2023 2022 As at December 31, Sensitivity Range Increase Decrease Increase Decrease WCS Forward Prices ± $10.00 per barrel (21) 45 (68) 157 As at December 31, 2023 and December 31, 2022, a 10 percent increase or decrease in WTI option price volatility, or a five percent increase or decrease in Canadian to U.S. dollar foreign exchange rate option volatility would have resulted in nominal changes to earnings before income tax. |
Risk Management
Risk Management | 12 Months Ended |
Dec. 31, 2023 | |
Risk Management [Abstract] | |
Risk Management | 36. RISK MANAGEMENT Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates, commo dity power prices as w ell as credit risk and liquidity risk. To manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus, the Company may periodically enter into financial positions as a part of ongoing operations to market the Company’s production and physical inventory positions of crude oil, natural gas, condensate, refined products, and power consumption. The Company may also enter into arrangements, such as renewable power contracts or power swaps, to manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions. To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2023, the fair value of risk management positions was a net asset of $12 million (see Note 35). As at December 31, 2023, there were no foreign exchange contracts, interest rate contracts or cross currency interest rate swap contracts outstanding. As at December 31, 2022, there were forward exchange contracts with a notional value of US$168 million outstanding and there were no interest rate contracts or cross currency interest rate swap contracts outstanding. Net Fair Value of Risk Management Positions As at December 31, 2023 Notional Volumes (1) (2) Terms (3) Weighted Average Price (1) (2) Fair Value Asset (Liability) Futures Contracts Related to Blending (4) WTI Fixed – Sell 3.5 MMbbls January 2024 – December 2024 US$75.22/bbl 16 WTI Fixed – Buy 1.5 MMbbls January 2024 – December 2024 US$73.69/bbl (4) Power Swap Contacts 2 Renewable Power Contracts 18 Other Financial Positions (5) (20) Total Fair Value 12 (1) Million barrels ("MMbbls"). (2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month. (3) Includes individual contracts with varying terms, the longest of which is 13 months. (4) WTI futures contracts are used to help manage price exposure to condensate used for blending. (5) Includes risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts and the Company’s U.S. refining and marketing activities. A) Commodity Price and Foreign Exchange Rate Risk i) Commodity Price Risk Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes. The Company has used crude oil, natural gas and refined product swaps, futures, basis price risk management contracts and, if entered into, forwards, options, as well as condensate futures and swaps. These derivative instruments are used to partially mitigate exposure to the commodity price risk on its crude oil and condensate transactions and to protect both near-term and future cash flows. Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials and to manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus. In addition, the Company has entered into risk management positions to help mitigate the risk to incremental margin expected to be received in future periods at the time products will be sold. The Company has used commodity futures and swaps, as well as differential price risk management contracts to partially mitigate its exposure to the commodity price risk on its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate its natural gas commodity price risk. ii) Foreign Exchange Risk Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results. Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada (see Note 9). As at December 31, 2023, Cenovus had US$3.8 billion in U.S. dollar debt (December 31, 2022 – US$4.8 billion). iii) Commodity Price and Foreign Exchange Rate Sensitivities The following tables summarize the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the tables below are a reasonable measure of volatility. The impact of the below on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows: As at December 31, 2023 Sensitivity Range Increase Decrease Power Commodity Price ± C$20.00/MWh (1) Applied to Power Hedges 92 (92) (1) One thousand kilowatts of electricity per hour (“MWh”). As at December 31, 2023, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax: • A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price (primarily WTI). • A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential price. • A US$5.00 per barrel increase or decrease in the WCS differential price. • A US$10.00 per barrel increase or decrease in refined products commodity prices. • A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. • A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. • A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate. As at December 31, 2022 Sensitivity Range Increase Decrease WCS and Condensate Differential Price ± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production 13 (13) Power Commodity Price ± C$20.00/MWh Applied to Power Hedges 113 (113) U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate 14 (17) As at December 31, 2022, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax: • A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price (primarily WTI). • A US$5.00 per barrel increase or decrease in the WCS differential price. • A US$10.00 per barrel increase or decrease in refined products commodity prices. • A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. • A $0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows: As at December 31, 2023 2022 $0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate 197 246 $0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate (197) (246) B) Credit Risk Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee and the Board of Directors, which is designed to ensure that its credit exposures are within an acceptable risk level. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits. Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within its credit policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, net investment in finance leases, risk management assets and long-term receivables is the total carrying value. As at December 31, 2023, approximately 83 percent ( December 31, 2022 – 85 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 98 percent of th e Company’s accounts receivable were outstanding for less than 60 days. The associated average ECL on these accounts w as 0.4 percent as at December 31, 2023 (December 31, 2022 – 0.4 percent). C) Liquidity Risk Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt, by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings, and by ensuring that it has access to multiple sources of capital. As disclosed in Note 25, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at the bottom of the commodity price cycle to manage the Company’s overall debt position. As at December 31, 2023, the Company’s sources of capital included: • $2.2 billion in cash and cash equivalents. • $5.5 billion available on its committed credit facility. • $1.4 billion available on its uncommitted demand facilities, of which $1.1 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. • US$90 million (C$119 million) on the Company’s proportionate share of the uncommitted demand facilities from WRB. • The base shelf prospectus, availability of which is dependent on market conditions. Undiscounted cash outflows relating to financial liabilities are: As at December 31, 2023 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total Accounts Payable and Accrued Liabilities (1) 5,480 — — — 5,480 Short-Term Borrowings 179 — — — 179 Contingent Payments 168 — — — 168 Lease Liabilities (2) 438 712 569 2,635 4,354 Long-Term Debt (2) 313 792 3,007 7,145 11,257 As at December 31, 2022 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total Accounts Payable and Accrued Liabilities (1) 6,124 — — — 6,124 Short-Term Borrowings 115 — — — 115 Contingent Payments 271 167 — — 438 Lease Liabilities (2) 426 746 596 2,889 4,657 Long-Term Debt (2) 401 983 2,014 11,196 14,594 (1) Includes current risk management liabilities. (2) Principal and interest, including current portion, if applicable. |
Supplementary Cash Flow Informa
Supplementary Cash Flow Information | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Supplementary Cash Flow Information [Abstract] | |
Supplementary Cash Flow Information | 37. SUPPLEMENTARY CASH FLOW INFORMATION A) Working Capital As at December 31, 2023 2022 Total Current Assets 9,708 12,430 Total Current Liabilities 6,210 8,021 Working Capital 3,498 4,409 As at December 31, 2023, adjusted working capital, which excludes the current portion of the contingent payments, was $3.7 billion (December 31, 2022 – $4.7 billion). Changes in non-cash working capital is as follows: For the years ended December 31, 2023 2022 Accounts Receivable and Accrued Revenues 314 838 Income Tax Receivable (295) (58) Inventories 216 (143) Accounts Payable and Accrued Liabilities (685) (524) Income Tax Payable (1,112) 1,000 Total Change in Non-Cash Working Capital (1,562) 1,113 Net Change in Non-Cash Working Capital – Operating Activities (1,193) 575 Net Change in Non-Cash Working Capital – Investing Activities (369) 538 Total Change in Non-Cash Working Capital (1,562) 1,113 For the years ended December 31, 2023 2022 Interest Paid 402 647 Interest Received 130 78 Income Taxes Paid 2,595 723 B) Reconciliation of Liabilities The following table provides a reconciliation of liabilities to cash flows arising from financing activities: Dividends Payable Warrant Purchase Payable Short-Term Borrowings Long-Term Debt Lease Liabilities As at December 31, 2021 — — 79 12,385 2,957 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings — — 34 — — Repayment of Long-Term Debt — — — (4,149) — Principal Repayment of Leases — — — — (302) Base Dividends Paid on Common Shares (682) — — — — Variable Dividends Paid on Common Shares (219) — — — — Dividends Paid on Preferred Shares (26) — — — — Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt — — — (29) — Finance and Transaction Costs — — — (28) — Lease Additions — — — — 25 Base Dividends Declared on Common Shares 682 — — — — Variable Dividends Declared on Common Shares 219 — — — — Dividends Declared on Preferred Shares 35 — — — — Exchange Rate Movements and Other — — 2 512 156 As at December 31, 2022 9 — 115 8,691 2,836 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings — — 58 — — Repayment of Long-Term Debt — — — (1,346) — Principal Repayment of Leases — — — — (288) Base Dividends Paid on Common Shares (990) — — — — Dividends Paid on Preferred Shares (36) — — — — Payment for Purchase of Warrants — (711) — — — Finance and Transaction Costs — (2) — — — Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt — — — (84) — Finance and Transaction Costs — 2 — (19) — Lease Acquisitions — — — — 33 Lease Additions — — — — 57 Lease Divestitures — — — — (11) Base Dividends Declared on Common Shares 990 — — — — Dividends Declared on Preferred Shares 36 — — — — Warrants Purchased and Cancelled — 711 — — — Exchange Rate Movements and Other — — 6 (134) 31 As at December 31, 2023 9 — 179 7,108 2,658 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Commitments And Contingencies [Abstract] | |
Commitments and Contingencies | 38. COMMITMENTS AND CONTINGENCIES A) Commitments Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities less than one year are excluded from the table below. Future payments for the Company’s commitments are below: As at December 31, 2023 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Transportation and Storage (1) (2) 2,018 1,927 1,680 1,663 1,641 15,738 24,667 Product Purchases 617 — — — — — 617 Real Estate 57 57 59 63 58 604 898 Obligation to Fund HCML 94 94 94 89 52 90 513 Other Long-Term Commitments (3) 417 194 184 175 166 965 2,101 Total Commitments 3,203 2,272 2,017 1,990 1,917 17,397 28,796 As at December 31, 2022 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Transportation and Storage (1) (2) 1,747 2,011 1,542 1,416 1,360 13,005 21,081 Product Purchases 1,626 1,509 922 922 922 3,457 9,358 Real Estate 48 50 50 50 54 604 856 Obligation to Fund HCML 92 105 96 96 91 143 623 Other Long-Term Commitments 381 90 75 74 65 395 1,080 Total Commitments 3,894 3,765 2,685 2,558 2,492 17,604 32,998 (1) Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 – $9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator. (2) As at December 31, 2023, includes $2.1 billion related to long-term transportation and storage commitments with HMLP (December 31, 2022 – $2.2 billion). (3) The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023. There were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) issued as security for financial and performance conditions under certain contracts. Subsequent to December 31, 2023, Cenovus entered into a new transportation commitment for $587 million. B) Contingencies Legal Proceedings Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements. Income Tax Matters The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate. |
Prior Period Revisions
Prior Period Revisions | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Prior Period Revisions | 39. PRIOR PERIOD REVISIONS Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was revised for classification changes. In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made: • Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense. • Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which resulted in a reclassification between gross sales and purchased product. Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) and segmented disclosures to the corresponding revised amounts: Year Ended December 31, 2022 Oil Sands Segment Previously Reported Revisions Revised Balance Gross Sales 34,775 (92) 34,683 Purchased Product 4,810 (92) 4,718 29,965 — 29,965 Conventional Segment Gross Sales 4,332 107 4,439 Transportation and Blending 143 107 250 4,189 — 4,189 U.S. Refining Segment Gross Sales 30,310 (92) 30,218 Purchased Product 26,112 (92) 26,020 4,198 — 4,198 Corporate and Eliminations Segment Gross Sales (7,464) 77 (7,387) Purchased Product (5,533) 341 (5,192) Transportation and Blending (664) (511) (1,175) Operating (1,270) 247 (1,023) 3 — 3 Consolidated Purchased Product 33,801 157 33,958 Transportation and Blending 11,530 (404) 11,126 Operating 5,569 247 5,816 50,900 — 50,900 |
Summary of Accounting Policies
Summary of Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Summary Of Significant Accounting Policies [Abstract] | |
Principles of Consolidation | A) Principles of Consolidation The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation. Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s accounts reflect its share of the assets, liabilities, revenues and expenses from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s activities relate to joint ventures, which are accounted for using the equity method of accounting. |
Foreign Currency Translation | B) Foreign Currency Translation The Company’s functional and presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in OCI as cumulative translation adjustments. When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests. Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the reporting date. Any gains or losses are recorded in the Consolidated Statements of Earnings (Loss). |
Revenue Recognition | C) Revenue Recognition Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided. Cenovus recognizes revenue from the following major products and services: • Sale of crude oil, NGLs and natural gas. • Sale of petroleum and refined products. • Crude oil and natural gas processing services. • Pipeline transportation, the blending of crude oil and the storage of crude oil, diluent and natural gas. • Fee-for-service hydrocarbon transloading services. • Construction services. The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products, which is generally at a point in time. Performance obligations for crude oil and natural gas processing revenue, transportation services and transloading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Revenue associated with crude oil, NGLs and natural gas production is recorded net of royalties. Revenue associated with natural gas processing, transportation services and transloading services are generally based on fixed price contracts. Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and revenue from cost-plus contracts are recognized as services are performed. The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date, the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered or the deferral provision can no longer be extended. |
Purchased Product | Purchased ProductThe costs of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market, are recorded as purchased product. |
Transportation and Blending | E) Transportation and Blending The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of diluent used in blending, are recognized when the product is sold. |
Exploration Expense | F) Exploration Expense Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense. Certain costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense. |
Employee Benefit Plans | G) Employee Benefit Plans The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component. Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans, benefits are not funded before retirement. Pension expense for the defined contribution pension is recorded as the benefits are earned. The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans. Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows: • Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs. • Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. • Re-measurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Re-measurements are not reclassified to net earnings in subsequent periods. |
Government Grants | H) Government Grants |
Income Taxes | I) Income Taxes Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that were enacted or substantively enacted at the Consolidated Balance Sheet date. Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively. Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes. Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current. |
Related Party Transactions | J) Related Party Transactions The Company enters into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value. Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds. |
Net Earnings per Share Amounts | K) Net Earnings per Share Amounts Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share. |
Cash and Cash Equivalents | L) Cash and Cash Equivalents Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a maturity of three months or less. |
Inventories | M) Inventories Product inventories are valued at the lower of cost, using a first-in, first-out or weighted average cost basis, and net realizable value. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand. |
Exploration and Evaluation Assets | N) Exploration and Evaluation Assets E&E assets consist of exploratory projects for crude oil, natural gas and NGLs that are pending the determination of proved reserves. Certain costs incurred after obtaining the legal right to explore an area and before establishing the technical feasibility and commercial viability of the field/project/area, are capitalized as E&E assets. E&E assets are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired or the future economic value has decreased. E&E assets are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources. Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as depreciation, depletion and amortization (“DD&A”), is recognized on this production using a unit-of-production method based on estimated proved reserves determined using forward prices and costs and considering any estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an energy equivalent basis. Non-producing assets classified as E&E are not depleted. Once technical feasibility and commercial viability is established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E. Any gains or losses from the divestiture of E&E assets are recognized in net earnings. |
Property, Plant and Equipment | O) Property, Plant and Equipment PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals. Expenditures related to renewals or enhancements that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated. Crude Oil and Natural Gas Properties Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties and related infrastructure facilities, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves. For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations, natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to be incurred in developing those reserves. Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of either the asset received, or the asset given up, cannot be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired. Included in crude oil and natural gas properties are information technology assets used to support the upstream business and are depreciated on a straight-line basis over their useful lives of three years. Refining Assets The initial costs of refining and upgrading PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs. Refining and upgrading assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows: • Land improvements and buildings: 15 to 40 years. • Office improvements and buildings: 3 to 15 years. • Refining equipment: 10 to 60 years. Also included in refining assets are information technology assets used to support the downstream business that are depreciated on a straight-line basis over their useful lives of three years. The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate. Processing, Transportation and Storage Assets, Commercial Fuels Business and Other Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, which range from three |
Impairment and Impairment Reversals of Non-Financial Assets | P) Impairment and Impairment Reversals of Non-Financial Assets PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually. If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is estimated based on the discounted after-tax cash flows of reserves using forward prices, costs to develop and operating costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions. For Cenovus's downstream assets, FVLCOD is estimated based on discounted after-tax cash flows of refined product production using forward crude oil prices, forward crack spreads , operating expenses and future capital expenditures. E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill is allocated to the CGUs to which it contributes to the future cash flows. If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed. Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings. |
Leases | Q) Leases The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company has elected not to separate non-lease components. As Lessee Leases are recognized as a ROU asset and a corresponding lease liability on the date that the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments, restoration and removal costs, variable lease payments that are based on an index or a rate, estimated residual value guarantees, purchase options expected to be exercised, and termination penalties, less lease incentive receivables. These payments are discounted using the Company’s incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with reasonably similar characteristics. Lease payments are allocated between the liability and finance costs. Finance costs are charged to net earnings over the lease term. The lease liability is measured at amortized cost using the effective interest method. It is re-measured when there is a change in the future lease payments due to a change in an index or rate, if there is a change in the expected residual value guarantee or if the Company reconsiders the exercise of a purchase, extension or termination option that is within the Company's control. When the lease liability is re-measured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero. The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability, any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date. The ROU asset is depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or lease term. Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating, transportation or general and administrative expense. A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will re-measure the lease liability using the Company’s incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope. As Lessor Leases where the Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments received under operating leases as income on a straight-line basis over the lease term as other income. When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the sublease is classified as an operating lease. |
Intangible Assets | R) Intangible Assets Intangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset. Impairment losses are recognized in the Consolidated Statements of Earnings (Loss) as DD&A. |
Business Combinations and Goodwill | S) Business Combinations and Goodwill Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited to net earnings. Acquisition costs are expensed as incurred. At acquisition, goodwill is allocated to the CGU to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses. Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity in accordance with the terms of the agreement. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity. When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings. |
Provisions | T) Provisions A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings (Loss). Decommissioning Liabilities Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, surface and subsea plant and equipment, refining facilities and the crude-by-rail terminal. Cenovus recognizes decommissioning liabilities when the disturbances occur. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset. Actual expenditures incurred are charged against the accumulated liability. Onerous Contract Provisions Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss). Renewable Fuel Obligations The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured at the expected market price or on a contracted forward rate, if applicable, of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the month purchased. RINs purchased on a secondary market are measured at cost. RINs are not amortized. A net RIN position is presented in other assets and a net RVO position is included in other liabilities. |
Share Capital and Warrants | U) Share Capital and Warrants Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the Company’s option. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative. Transaction costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s paid in surplus. Common shares are cancelled subsequent to being purchased. |
Stock-Based Compensation | V) Stock-Based Compensation Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expenses. Stock Options With Associated Net Settlement Rights NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation over the vesting period, with a corresponding increase recorded as paid in surplus in shareholders’ equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital. Cenovus Replacement Stock Options Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the stock option is recorded as share capital. Performance, Restricted and Deferred Share Units |
Financial Instruments | W) Financial Instruments The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets, net investment in finance leases, investments in the equity of companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, risk management liabilities and long-term debt. Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows: • Level 1 inputs are quoted prices in active markets for identical assets and liabilities. • Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly. • Level 3 inputs are unobservable inputs for the asset or liability. Classification and Measurement of Financial Assets The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets: • Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest. • FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest. • Fair Value through Profit or Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets. On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis. At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings. Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or are transferred, and the Company has transferred substantially all the risks and rewards of ownership. Impairment of Financial Assets The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e., the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component. Classification and Measurement of Financial Liabilities A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable. Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is re-measured based on the new cash flows and a gain or loss is recorded in net earnings. Derivatives Derivative financial instruments are primarily used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction. Derivative financial instruments are measured at FVTPL unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts. |
Recent Accounting Pronouncements | X) Recent Accounting Pronouncements New Accounting Standards and Interpretations not yet Adopted |
Description of Business and S_2
Description of Business and Segmented Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Reportable Segments [Abstract] | |
Schedule of Segment and Operational Information | A) Results of Operations – Segment and Operational Information Upstream For the years ended December 31, Oil Sands Conventional Offshore Total 2023 2022 2023 2022 2023 2022 2023 2022 Revenues Gross Sales (1) 26,192 34,683 3,273 4,439 1,617 2,020 31,082 41,142 Less: Royalties 3,059 4,493 112 298 99 77 3,270 4,868 23,133 30,190 3,161 4,141 1,518 1,943 27,812 36,274 Expenses Purchased Product (1) 1,457 4,718 1,695 2,023 — — 3,152 6,741 Transportation and Blending (1) 10,774 12,036 298 250 16 15 11,088 12,301 Operating 2,716 2,930 590 541 384 318 3,690 3,789 Realized (Gain) Loss on Risk 17 1,527 (5) 92 — — 12 1,619 Operating Margin 8,169 8,979 583 1,235 1,118 1,610 9,870 11,824 Unrealized (Gain) Loss on Risk Management 15 (68) (19) 13 — — (4) (55) Depreciation, Depletion and 2,993 2,763 386 370 487 585 3,866 3,718 Exploration Expense 19 9 6 1 17 91 42 101 (Income) Loss From Equity- 6 8 — — (57) (23) (51) (15) Segment Income (Loss) 5,136 6,267 210 851 671 957 6,017 8,075 Downstream Canadian Refining U.S. Refining Total For the years ended December 31, 2023 2022 2023 2022 2023 2022 Revenues Gross Sales (1) 6,233 7,792 26,393 30,218 32,626 38,010 Less: Royalties — — — — — — 6,233 7,792 26,393 30,218 32,626 38,010 Expenses Purchased Product (1) 4,919 6,389 23,354 26,020 28,273 32,409 Transportation and Blending — — — — — — Operating 639 704 2,562 2,346 3,201 3,050 Realized (Gain) Loss on Risk — — — 112 — 112 Operating Margin 675 699 477 1,740 1,152 2,439 Unrealized (Gain) Loss on Risk Management — — (17) 18 (17) 18 Depreciation, Depletion and 185 208 486 640 671 848 Exploration Expense — — — — — — (Income) Loss From Equity-Accounted — — — — — — Segment Income (Loss) 490 491 8 1,082 498 1,573 (1) Comparative periods reflect certain revisions. See Note 39. Corporate and Eliminations Consolidated For the years ended December 31, 2023 2022 2023 2022 Revenues Gross Sales (1) (8,234) (7,387) 55,474 71,765 Less: Royalties — — 3,270 4,868 (8,234) (7,387) 52,204 66,897 Expenses Purchased Product (1) (6,710) (5,192) 24,715 33,958 Transportation and Blending (1) (947) (1,175) 10,141 11,126 Operating (1) (539) (1,023) 6,352 5,816 Realized (Gain) Loss on Risk Management (3) 31 9 1,762 Unrealized (Gain) Loss on Risk Management 73 (89) 52 (126) Depreciation, Depletion and Amortization 107 113 4,644 4,679 Exploration Expense — — 42 101 (Income) Loss From Equity-Accounted Affiliates — — (51) (15) Segment Income (Loss) (215) (52) 6,300 9,596 General and Administrative 688 865 688 865 Finance Costs 671 820 671 820 Interest Income (133) (81) (133) (81) Integration, Transaction and Other Costs 85 106 85 106 Foreign Exchange (Gain) Loss, Net (67) 343 (67) 343 Revaluation (Gain) Loss 34 (549) 34 (549) Re-measurement of Contingent Payment 59 162 59 162 (Gain) Loss on Divestiture of Assets (14) (269) (14) (269) Other (Income) Loss, Net (63) (532) (63) (532) 1,260 865 1,260 865 Earnings (Loss) Before Income Tax 5,040 8,731 Income Tax Expense (Recovery) 931 2,281 Net Earnings (Loss) 4,109 6,450 (1) Comparative periods reflect certain revisions. See Note 39. |
Schedule of Revenues by Product | B) Revenues by Product For the years ended December 31, 2023 2022 Upstream Oil Sands Crude Oil (1) 22,550 28,921 NGLs (2) 352 877 Natural Gas and Other 231 392 Conventional Crude Oil 589 429 NGLs (2) 799 926 Natural Gas and Other (1) 1,773 2,786 Offshore Crude Oil 385 581 NGLs 280 354 Natural Gas 853 1,008 Total Upstream 27,812 36,274 Downstream Canadian Refining Synthetic Crude Oil 2,124 2,360 Diesel 1,752 2,164 Asphalt 571 620 Gasoline 522 948 Other Products and Services 1,264 1,700 U.S. Refining Gasoline 12,375 14,116 Distillates 9,612 11,453 Asphalt 864 533 Other Products (1) 3,542 4,116 Total Downstream 32,626 38,010 Corporate and Eliminations (1) (8,234) (7,387) Consolidated 52,204 66,897 (1) Comparative periods reflect certain revisions. See Note 39. (2) Third-party condensate sales are included within NGLs. |
Schedule of Geographical Information | C) Geographical Information Revenues (1) For the years ended December 31, 2023 2022 Canada (2) 25,128 33,314 United States (2) 25,943 32,221 China 1,133 1,362 Consolidated 52,204 66,897 (1) Revenues by country are classified based on where the operations are located. (2) Comparative periods reflect certain revisions. See Note 39. Non-Current Assets (1) As at December 31, 2023 2022 Canada 35,876 35,194 United States 5,230 4,824 China 1,608 2,064 Indonesia 344 365 Consolidated 43,058 42,447 (1) |
Schedule of Assets by Segment | D) Assets by Segment E&E Assets PP&E ROU Assets As at December 31, 2023 2022 2023 2022 2023 2022 Oil Sands 729 674 24,443 24,657 849 638 Conventional — 6 2,209 2,020 1 2 Offshore 9 5 2,798 2,549 102 152 Canadian Refining — — 2,469 2,466 28 252 U.S. Refining — — 5,014 4,482 268 329 Corporate and Eliminations — — 317 325 432 472 Consolidated 738 685 37,250 36,499 1,680 1,845 Goodwill Total Assets As at December 31, 2023 2022 2023 2022 Oil Sands 2,923 2,923 31,673 32,248 Conventional — — 2,429 2,410 Offshore — — 3,511 3,339 Canadian Refining — — 2,960 3,172 U.S. Refining — — 8,660 8,324 Corporate and Eliminations — — 4,682 6,376 Consolidated 2,923 2,923 53,915 55,869 |
Schedule of Capital Expenditures | E) Capital Expenditures (1) For the years ended December 31, 2023 2022 Capital Investment Oil Sands 2,382 1,792 Conventional 452 344 Offshore Asia Pacific 7 8 Atlantic 635 302 Total Upstream 3,476 2,446 Canadian Refining 145 117 U.S. Refining 602 1,059 Total Downstream 747 1,176 Corporate and Eliminations 75 86 4,298 3,708 Acquisitions (Note 5) Oil Sands (2) 37 1,609 Conventional 5 12 U.S. Refining (3) 385 — 427 1,621 Total Capital Expenditures 4,725 5,329 (1) Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the HCML joint venture. (2) In 2022, Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-existing interest in SOSP of $1.6 billion. (3) In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) and reacquired it at fair value as required by IFRS 3. The acquisition capital above does not include the fair value of the pre-existing interest in Toledo of $368 million. |
Summary of Accounting Policie_2
Summary of Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Summary Of Significant Accounting Policies [Abstract] | |
Disclosure of Revisions to Prior Period | The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) and segmented disclosures to the corresponding revised amounts: Year Ended December 31, 2022 Oil Sands Segment Previously Reported Revisions Revised Balance Gross Sales 34,775 (92) 34,683 Purchased Product 4,810 (92) 4,718 29,965 — 29,965 Conventional Segment Gross Sales 4,332 107 4,439 Transportation and Blending 143 107 250 4,189 — 4,189 U.S. Refining Segment Gross Sales 30,310 (92) 30,218 Purchased Product 26,112 (92) 26,020 4,198 — 4,198 Corporate and Eliminations Segment Gross Sales (7,464) 77 (7,387) Purchased Product (5,533) 341 (5,192) Transportation and Blending (664) (511) (1,175) Operating (1,270) 247 (1,023) 3 — 3 Consolidated Purchased Product 33,801 157 33,958 Transportation and Blending 11,530 (404) 11,126 Operating 5,569 247 5,816 50,900 — 50,900 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination [Abstract] | |
Disclosure of detailed information about business combination | The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition. As at February 28, 2023 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed Cash 69 Accounts Receivable and Accrued Revenues 3 Inventories 387 Property, Plant and Equipment 770 Right-of-Use Assets 33 Other Assets 10 Accounts Payable and Accrued Liabilities (139) Lease Liabilities (33) Decommissioning Liabilities (5) Other Liabilities (73) Total Identifiable Net Assets 1,022 As at February 28, 2023 Total Purchase Consideration 514 Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo 508 Fair Value of Identifiable Net Assets (1,022) Goodwill — The following table summarizes the fair value of total consideration: As at August 31, 2022 Cash, Net of Closing Adjustments 394 Bay Du Nord 40 Variable Payment 600 Total Consideration 1,034 As at August 31, 2022 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed Cash 9 Accounts Receivable and Accrued Revenues 164 Inventories 88 Property, Plant and Equipment 3,218 Accounts Payable and Accrued Liabilities (313) Income Tax Payable (39) Decommissioning Liabilities (48) Deferred Income Tax Liabilities (486) Total Identifiable Net Assets 2,593 As at August 31, 2022 Total Purchase Consideration 1,034 Fair Value of Pre-Existing 50 Percent Ownership Interest in SOSP 1,559 Fair Value of Identifiable Net Assets (2,593) Goodwill — |
General and Administrative (Tab
General and Administrative (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
General And Administrative Expenses [Abstract] | |
Summary of General and Administrative Expenses | For the years ended December 31, 2023 2022 Salaries and Benefits 249 204 Administrative and Other 342 297 Stock-Based Compensation Expense (Recovery) (Note 32) 97 373 Other Incentive Benefits Expense (Recovery) — (9) 688 865 |
Finance Costs (Tables)
Finance Costs (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Finance Costs [Abstract] | |
Schedule of Finance Cost | For the years ended December 31, 2023 2022 Interest Expense – Short-Term Borrowings and Long-Term Debt 362 478 Net Premium (Discount) on Redemption of Long-Term Debt (1) (84) (29) Interest Expense – Lease Liabilities (Note 20) 161 163 Unwinding of Discount on Decommissioning Liabilities (Note 27) 220 176 Other 32 37 691 825 Capitalized Interest (20) (5) 671 820 (1) Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments. |
Integration, Transaction and _2
Integration, Transaction and Other Costs (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Integration Costs [Abstract] | |
Disclosure of Integration and Transaction Costs | For the years ended December 31, 2023 2022 Integration Costs (1) 46 95 Transaction Costs (Note 5) 11 11 Other (2) 28 — 85 106 (1) For the year ended December 31, 2023, integration costs includes $46 million related to the Toledo Acquisition (2022 – $5 million related to the Toledo Acquisition and $90 million related to the Husky Arrangement). (2) Includes costs related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. |
Foreign Exchange (Gain) Loss,_2
Foreign Exchange (Gain) Loss, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Foreign Exchange Gains Losses [Abstract] | |
Schedule of Foreign Exchange Gain Loss Net | For the years ended December 31, 2023 2022 Unrealized Foreign Exchange (Gain) Loss on Translation of: U.S. Dollar Debt Issued From Canada (231) 365 Other 21 — Unrealized Foreign Exchange (Gain) Loss (210) 365 Realized Foreign Exchange (Gain) Loss 143 (22) (67) 343 |
Impairment Charges and Revers_2
Impairment Charges and Reversals (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of impairment loss recognised or reversed for cash-generating unit [abstract] | |
Summary of Crude Oil, NGLs and Natural Gas Prices | The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: 2024 2025 2026 2027 2028 Average Annual Increase Thereafter West Texas Intermediate (“WTI”) (US$/bbl) (1) 73.67 74.98 76.14 77.66 79.22 2.00 % Western Canadian Select at Hardisty (2) (C$/bbl) 76.74 79.77 81.12 82.88 85.04 2.00 % Condensate at Edmonton (C$/bbl) 96.79 98.75 100.71 102.72 104.78 2.00 % Alberta Energy Company Natural Gas (C$/Mcf) (3) 2.20 3.37 4.05 4.13 4.21 2.00 % (1) Barrel ("bbl"). (2) Western Canadian Select at Hardisty (“WCS”). (3) One thousand cubic feet (“Mcf”). |
Summary of Crude Oil and Forward Crack Spreads | The forward commodity prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: 2023 2024 2025 2026 2027 Average Annual Increase Thereafter WTI (US$/bbl) 80.33 78.50 76.95 77.61 79.16 2.00 % WCS (C$/bbl) 76.54 77.75 77.55 80.07 81.89 2.00 % Condensate at Edmonton (C$/bbl) 106.22 101.35 98.94 100.19 101.74 2.00 % Alberta Energy Company Natural Gas (C$/Mcf) 4.23 4.40 4.21 4.27 4.34 2.00 % Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were: (US$/bbl) 2023 2024 2025 2026 2027 WTI 80.33 78.50 76.95 77.61 79.16 Differential WTI – WTS (1) (0.56) (0.56) (0.56) (0.56) (0.56) Differential WTI – WCS (23.32) (19.09) (17.42) (15.87) (15.74) Chicago 3-2-1 Crack Spread 29.37 24.10 22.12 21.70 21.67 (1) West Texas Sour (“WTS”). |
Summary of Sensitivities | One Percent Increase in the Discount Rate One Percent Decrease in the Discount Rate Five Percent Increase in the Forward Price Estimates Five Percent Decrease in the Forward Price Estimates Increase (Decrease) to Impairment Amount 69 (65) (268) 268 Increase (Decrease) to Impairment Reversal Amount (72) 14 168 (342) |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Income Tax Expense Continuing Operations [Abstract] | |
Provision for Income Taxes | For the years ended December 31, 2023 2022 Current Tax Canada 1,041 1,252 United States (109) 104 Asia Pacific 224 262 Other International 25 21 Total Current Tax Expense (Recovery) 1,181 1,639 Deferred Tax Expense (Recovery) (250) 642 931 2,281 |
Disclosure Of Reconciliation Of Accounting Profit From Continuing Operations Multiplied By Applicable Tax Rates Explanatory | The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: For the years ended December 31, 2023 2022 Earnings (Loss) Before Income Tax 5,040 8,731 Canadian Statutory Rate (percent) 23.7 23.7 Expected Income Tax Expense (Recovery) 1,194 2,069 Effect on Taxes Resulting From: Statutory and Other Rate Differences (38) 17 Non-Taxable Capital (Gains) Losses (15) 84 Non-Recognition of Capital (Gains) Losses (30) 84 Adjustments Arising From Prior Year Tax Filings (16) 15 Recognition of U.S. Tax Basis (115) — Other (49) 12 Total Tax Expense (Recovery) 931 2,281 Effective Tax Rate (percent) 18.5 26.1 |
Disclosure of deferred taxes | The breakdown of deferred income tax assets and deferred income tax liabilities, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows: For the years ended December 31, 2023 2022 Deferred Income Tax Assets Deferred Income Tax Assets to be Settled Within Twelve Months (315) (31) Deferred Income Tax Assets to be Settled After More Than Twelve Months (1,174) (747) (1,489) (778) Deferred Income Tax Liabilities Deferred Income Tax Liabilities to be Settled Within Twelve Months 138 55 Deferred Income Tax Liabilities to be Settled After More Than Twelve Months 4,843 4,460 4,981 4,515 Net Deferred Income Tax Liability 3,492 3,737 |
Disclosure Of Reconciliation Of Changes In Deferred Tax Liability Asset Explanatory | The movement in deferred income tax assets and liabilities, without taking into consideration the offsetting of balances within the same tax jurisdiction, is: Deferred Income Tax Assets Unused Tax Losses Risk Management Other Total As at December 31, 2021 (655) (11) (788) (1,454) Charged (Credited) to Earnings 490 11 158 659 Charged (Credited) to Other Comprehensive Income 9 — 8 17 As at December 31, 2022 (156) — (622) (778) Charged (Credited) to Earnings (777) — 54 (723) Charged (Credited) to Other Comprehensive Income 19 — (7) 12 As at December 31, 2023 (914) — (575) (1,489) Deferred Income Tax Liabilities PP&E Risk Management Other Total As at December 31, 2021 3,949 — 97 4,046 Charged (Credited) to Earnings 25 11 (53) (17) Charged (Credited) to Sunrise Purchase Price Allocation 486 — — 486 As at December 31, 2022 4,460 11 44 4,515 Charged (Credited) to Earnings 495 (8) (14) 473 Charged (Credited) to Other Comprehensive Income (7) — — (7) As at December 31, 2023 4,948 3 30 4,981 Net Deferred Income Tax Liabilities Total As at December 31, 2021 2,592 Charged (Credited) to Earnings 642 Charged (Credited) to Sunrise Purchase Price Allocation 486 Charged (Credited) to Other Comprehensive Income 17 As at December 31, 2022 3,737 Charged (Credited) to Earnings (250) Charged (Credited) to Other Comprehensive Income 5 As at December 31, 2023 3,492 |
Disclosure Of Temporary Difference Unused Tax Losses And Unused Tax Credits | The approximate amounts of tax pools available, including tax losses, are: As at December 31, 2023 2022 Canada 8,547 8,505 United States 8,058 6,477 Asia Pacific 347 457 16,952 15,439 |
Per Share Amounts (Tables)
Per Share Amounts (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings per share [abstract] | |
Schedule Representing Per Share Amounts | For the years ended December 31, 2023 2022 Net Earnings (Loss) 4,109 6,450 Effect of Cumulative Dividends on Preferred Shares (36) (35) Net Earnings (Loss) – Basic and Diluted 4,073 6,415 Basic – Weighted Average Number of Shares (thousands) 1,895,487 1,951,262 Dilutive Effect of Warrants 22,223 44,845 Dilutive Effect of Net Settlement Rights 7,150 10,045 Dilutive Effect of Cenovus Replacement Stock Options 580 — Diluted – Weighted Average Number of Shares (thousands) 1,925,440 2,006,152 Net Earnings (Loss) Per Common Share – Basic ($) 2.15 3.29 Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($) 2.12 3.20 (1) For the year ended December 31, 2023, net earnings of $nil (2022 – $52 million) and no common shares (2022 – 1.6 million) related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive. (2) For the year ended December 31, 2023, 1.5 million NSRs (2022 – 52 thousand) were excluded from the calculation of diluted weighted average number of shares as the effect was anti-dilutive. |
Disclosure Of Dividends To Shareholders | B) Common Share Dividends 2023 2022 For the years ended December 31, Per Share Amount Per Share Amount Base Dividends 0.525 990 0.350 682 Variable Dividends — — 0.114 219 Total Common Share Dividends Declared and Paid 0.525 990 0.464 901 C) Preferred Share Dividends For the years ended December 31, 2023 2022 Series 1 First Preferred Shares 7 7 Series 2 First Preferred Shares 2 1 Series 3 First Preferred Shares 12 12 Series 5 First Preferred Shares 9 9 Series 7 First Preferred Shares 6 6 Total Preferred Share Dividends Declared 36 35 |
Cash and Cash Equivalents (Tabl
Cash and Cash Equivalents (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Cash and cash equivalents [abstract] | |
Disclosure Of Cash And Cash Equivalent Explanatory | As at December 31, 2023 2022 Cash 2,109 3,195 Short-Term Investments 118 1,329 2,227 4,524 |
Accounts Receivable and Accru_2
Accounts Receivable and Accrued Revenues (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Trade and other current receivables [abstract] | |
Schedule of Accounts Receivable and Accrued Revenues | As at December 31, 2023 2022 Trade and Accruals 2,722 2,962 Prepaids and Deposits 242 402 Joint Operations Receivables 49 51 Other 22 58 3,035 3,473 |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Classes of current inventories [abstract] | |
Disclosure Of Detailed Information About Inventories Explanatory | As at December 31, 2023 2022 Product Crude Oil 2,084 2,424 Diluent 379 366 Natural Gas and NGLs 68 50 Refined Products 1,073 1,169 Total Product 3,604 4,009 Parts and Supplies 426 303 4,030 4,312 |
Exploration and Evaluation As_2
Exploration and Evaluation Assets, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Exploration And Evaluation Assets [Abstract] | |
Summary of Exploration and Valuation Assets, Net | Total As at December 31, 2021 720 Additions 37 Write-downs (1) (64) Change in Decommissioning Liabilities (12) Exchange Rate Movements and Other 4 As at December 31, 2022 685 Acquisition 31 Additions 84 Transfer to PP&E (Note 19) (60) Write-downs (1) (29) Change in Decommissioning Liabilities 28 Exchange Rate Movements and Other (1) As at December 31, 2023 738 (1) For the year ended December 31, 2023 , previously capitalized E&E costs of $14 million, $6 million and $9 million in the Oil Sands, Conventional and Offshore segments, respectively, were written off as exploration expense (2022 – $2 million and $62 million in the Oil Sands and Offshore segments, respectively), as the carrying value was not considered to be recoverable. |
Property, Plant and Equipment_2
Property, Plant and Equipment, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of detailed information about property, plant and equipment [abstract] | |
Summary of Property, Plant and Equipment | Crude Oil and Natural Gas Properties Processing, Transportation and Storage Assets Refining Assets Other Assets (1) Total COST As at December 31, 2021 38,443 228 10,495 1,735 50,901 Acquisitions (Note 5) (2) 3,230 — — — 3,230 Additions 2,409 11 1,143 108 3,671 Change in Decommissioning Liabilities (186) (6) (29) (32) (253) Divestitures (Notes 5 and 10) (2) (557) — — — (557) Exchange Rate Movements and Other 189 21 523 14 747 As at December 31, 2022 43,528 254 12,132 1,825 57,739 Acquisitions (Note 5) (3) 11 — 770 — 781 Additions 3,392 14 719 89 4,214 Transfer from E&E (Note 18) 60 — — — 60 Change in Decommissioning Liabilities 542 — 21 18 581 Divestitures (Note 5) (3) (17) — (633) (17) (667) Exchange Rate Movements and Other (91) 4 (239) (7) (333) As at December 31, 2023 47,425 272 12,770 1,908 62,375 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION As at December 31, 2021 10,912 53 4,572 1,139 16,676 Depreciation, Depletion and Amortization (4) 3,461 37 466 103 4,067 Impairment Charges (Note 11) — — 1,499 — 1,499 Impairment Reversals (Note 11) — — (1,233) — (1,233) Divestitures (Notes 5 and 10) (2) (84) — — — (84) Exchange Rate Movements and Other 13 16 243 43 315 As at December 31, 2022 14,302 106 5,547 1,285 21,240 Depreciation, Depletion and Amortization (4) 3,692 19 554 86 4,351 Divestitures (Note 5) (3) (8) — (299) (12) (319) Exchange Rate Movements and Other (11) 4 (135) (5) (147) As at December 31, 2023 17,975 129 5,667 1,354 25,125 CARRYING VALUE As at December 31, 2022 29,226 148 6,585 540 36,499 As at December 31, 2023 29,450 143 7,103 554 37,250 (1) Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft. (2) In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million. (3) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million. (4) For the year ended December 31, 2023, DD&A includes asset write-downs of $20 million, $12 million and $38 million in the Oil Sands, Canadian Refining and U.S. Refining segments, respectively, (2022 – $26 million and $25 million in the Offshore and Canadian Refining segments, respectively). |
Disclosure Of Property Plant And Equipment Under Construction Explanatory | PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A: As at December 31, 2023 2022 Crude Oil and Natural Gas Properties 2,507 2,142 Refining Assets 243 137 2,750 2,279 |
Right of Use Assets, Net (Table
Right of Use Assets, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of quantitative information about right-of-use assets [abstract] | |
Summary of Right of Use Assets, Net | Real Estate Transportation and Storage Assets (1) Refining Assets Other Assets (2) Total COST As at December 31, 2021 592 1,841 161 62 2,656 Additions — 22 1 2 25 Exchange Rate Movements and Other 7 (23) 12 10 6 As at December 31, 2022 599 1,840 174 74 2,687 Acquisitions (Note 5) (3) 1 24 8 — 33 Additions 1 56 — — 57 Divestitures (Note 5) (3) — — (19) — (19) Exchange Rate Movements and Other (13) 44 (2) (4) 25 As at December 31, 2023 588 1,964 161 70 2,783 ACCUMULATED DEPRECIATION As at December 31, 2021 92 520 33 1 646 Depreciation 36 226 21 14 297 Exchange Rate Movements and Other (1) (101) 4 (3) (101) As at December 31, 2022 127 645 58 12 842 Depreciation 36 223 22 12 293 Divestitures (Note 5) (3) — — (12) — (12) Exchange Rate Movements and Other (7) (5) (3) (5) (20) As at December 31, 2023 156 863 65 19 1,103 CARRYING VALUE As at December 31, 2022 472 1,195 116 62 1,845 As at December 31, 2023 432 1,101 96 51 1,680 (1) Includes railcars, barges, vessels, pipelines, caverns and storage tanks. (2) Includes assets in the commercial fuels business, fleet vehicles and other equipment. (3) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million. |
Joint Arrangements (Tables)
Joint Arrangements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Subclassifications of assets, liabilities and equities [abstract] | |
Disclosure of joint ventures | Summarized below is the financial information for HCML accounted for using the equity method. Results of Operations For the years ended December 31, 2023 2022 Revenue 615 383 Expenses 545 350 Net Earnings (Loss) 70 33 Balance Sheet As at December 31, 2023 2022 Current Assets (1) 334 247 Non-Current Assets 1,751 1,926 Current Liabilities 140 160 Non-Current Liabilities 1,188 1,293 Net Assets 757 720 (1) Includes cash and cash equivalents of $111 million (December 31, 2022 – $64 million). For the years ended December 31, 2023 2022 HMLP Net Earnings (Loss) 231 190 Cenovus's Share of HMLP Net Earnings (Loss) (1) (1) (23) Cenovus's Share of HMLP Other Comprehensive Income (Loss) (1) (2) 8 Distributions Received 56 23 Contributions Paid 62 31 (1) |
Other Assets (Tables)
Other Assets (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Other Noncurrent Assets [Abstract] | |
Summary of Other Assets | As at December 31, 2023 2022 Private Equity Investments (Note 35) 131 55 Precious Metals 76 86 Net Investment in Finance Leases 61 62 Long-Term Receivables and Prepaids 50 120 Intangible Assets (1) — 19 318 342 (1) For the year ended December 31, 2022, $49 million of |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill [Abstract] | |
Schedule of changes in goodwill | 2023 2022 Carrying Value, Beginning of Year 2,923 3,473 Goodwill Disposed (Note 5) — (550) Carrying Value, End of Year 2,923 2,923 The carrying amount of goodwill is allocated to the following CGUs: As at December 31, 2023 2022 Primrose (Foster Creek) 1,171 1,171 Christina Lake 1,101 1,101 Lloydminster Thermal 651 651 2,923 2,923 |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Trade and other current payables [abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | As at December 31, 2023 2022 Accruals 3,931 3,412 Trade 1,075 2,331 Employee Long-Term Incentives 284 162 Interest 69 80 Joint Operations Payable 75 66 Risk Management 19 39 Provisions for Onerous and Unfavourable Contracts 18 25 Other 9 9 5,480 6,124 |
Debt and Capital Structure (Tab
Debt and Capital Structure (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Borrowings [abstract] | |
Schedule of Short-Term and Long-Term Debt | A) Short-Term Borrowings As at December 31, Notes 2023 2022 Uncommitted Demand Facilities i — — WRB Uncommitted Demand Facilities ii 179 115 Total Debt Principal 179 115 B) Long-Term Debt As at December 31, Notes 2023 2022 Committed Credit Facility (1) i — — U.S. Dollar Denominated Unsecured Notes ii 5,028 6,537 Canadian Dollar Unsecured Notes ii 2,000 2,000 Total Debt Principal 7,028 8,537 Debt Premiums (Discounts), Net, and Transaction Costs 80 154 Long-Term Debt 7,108 8,691 (1) |
Mandatory Debt Payments | U.S. Dollar Canadian Dollar Unsecured Notes Total As at December 31, 2023 US$ Principal C$ Principal Equivalent C$ Principal C$ Principal and Equivalent 2024 — — — — 2025 133 176 — 176 2026 — — — — 2027 373 493 750 1,243 2028 — — 1,250 1,250 Thereafter 3,296 4,359 — 4,359 3,802 5,028 2,000 7,028 |
Summary of Net Debt to Adjusted EBITDA | Net Debt to Adjusted EBITDA As at December 31, 2023 2022 Short-Term Borrowings 179 115 Current Portion of Long-Term Debt — — Long-Term Portion of Long-Term Debt 7,108 8,691 Total Debt 7,287 8,806 Less: Cash and Cash Equivalents (2,227) (4,524) Net Debt 5,060 4,282 Net Earnings (Loss) 4,109 6,450 Add (Deduct): Finance Costs 671 820 Interest Income (133) (81) Income Tax Expense (Recovery) 931 2,281 Depreciation, Depletion and Amortization 4,644 4,679 Exploration and Evaluation Asset Write-downs 29 64 (Income) Loss From Equity-Accounted Affiliates (51) (15) Unrealized (Gain) Loss on Risk Management 52 (126) Foreign Exchange (Gain) Loss, Net (67) 343 Revaluation (Gain) Loss 34 (549) Re-measurement of Contingent Payments 59 162 (Gain) Loss on Divestiture of Assets (14) (269) Other (Income) Loss, Net (63) (532) Adjusted EBITDA (1) 10,201 13,227 Net Debt to Adjusted EBITDA (times) 0.5 0.3 (1) Calculated on a trailing twelve-month basis. |
Disclosure Of Net Debt To Adjusted Funds Flow | Net Debt to Adjusted Funds F low As at December 31, 2023 2022 Net Debt 5,060 4,282 Cash From (Used in) Operating Activities 7,388 11,403 (Add) Deduct: Settlement of Decommissioning Liabilities (222) (150) Net Change in Non-Cash Working Capital (1,193) 575 Adjusted Funds Flow (1) 8,803 10,978 Net Debt to Adjusted Funds Flow (times) 0.6 0.4 (1) Calculated on a trailing twelve-month basis. |
Summary of Net Debt to Capitalization | Net Debt to Capitalization As at December 31, 2023 2022 Net Debt 5,060 4,282 Shareholders’ Equity 28,698 27,576 Capitalization 33,758 31,858 Net Debt to Capitalization (percent) 15 13 |
Contingent Payments (Tables)
Contingent Payments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of contingent liabilities in business combination [abstract] | |
Summary of Contingent Payment | 2023 2022 Contingent Payments, Beginning of Year 419 — Initial Recognition — 600 Liabilities Settled or Payable (314) (92) Re-measurement 59 (89) Contingent Payments, End of Year 164 419 Less: Current Portion 164 263 Long-Term Portion — 156 2022 Contingent Payments, Beginning of Year 236 Re-measurement 251 Liabilities Settled (487) Contingent Payments, End of Year — |
Lease Liabilities (Tables)
Lease Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Lease liabilities [abstract] | |
Summary of Lease Liabilities | 2023 2022 Lease Liabilities, Beginning of Year 2,836 2,957 Acquisitions (Note 5) (1) 33 — Additions 57 25 Interest Expense (Note 7) 161 163 Lease Payments (449) (465) Divestitures (Note 5) (1) (11) — Exchange Rate Movements and Other 31 156 Lease Liabilities, End of Year 2,658 2,836 Less: Current Portion 299 308 Long-Term Portion 2,359 2,528 (1) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million. |
Decommissioning Liabilities (Ta
Decommissioning Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Provision for decommissioning, restoration and rehabilitation costs [abstract] | |
Summary of Decommissioning Provision | 2023 2022 Decommissioning Liabilities, Beginning of Year 3,559 3,906 Liabilities Incurred 14 22 Liabilities Acquired (Note 5) (1) (2) 5 48 Liabilities Settled (221) (215) Liabilities Divested (Note 5) (1) (2) (5) (89) Change in Estimated Future Cash Flows 330 693 Change in Discount Rates 265 (980) Unwinding of Discount on Decommissioning Liabilities (Note 7) 220 176 Exchange Rate Movements and Other (12) (2) Decommissioning Liabilities, End of Year 4,155 3,559 (1) In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s decommissioning liabilities w as $2 million. (2) In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million. |
Description Of Major Assumptions Made Concerning Future Events Other Provisions Explanatory | Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities: Sensitivity 2023 2022 As at December 31, Range Increase Decrease Increase Decrease Credit-Adjusted Risk-Free Rate ± one percent (387) 515 (319) 419 Inflation Rate ± one percent 519 (392) 419 (320) |
Other Liabilities (Tables)
Other Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Miscellaneous non-current liabilities [abstract] | |
Summary of Other Liabilities | As at December 31, 2023 2022 Renewable Volume Obligation, Net (1) 397 101 Pension and Other Post-Employment Benefit Plan 276 201 Provision for West White Rose Expansion Project (2) 156 204 Provisions for Onerous and Unfavourable Contracts 72 95 Employee Long-Term Incentives 100 245 Drilling Provisions 25 31 Deferred Revenue — 45 Other 157 120 1,183 1,042 (1) The gross amounts of the RVO and RINs asset were $785 million and $388 million, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively). (2) |
Pensions and Other Post-Emplo_2
Pensions and Other Post-Employment Benefits (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Pensions And Other Post Employment Benefits [Abstract] | |
Summary of Defined Benefit and OPEB Plan Obligation and Funded Status | A) Plan Obligations, Assets and Funded Status DB Pension Plan OPEB Plans 2023 2022 2023 2022 Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year 172 220 174 225 Current Service Costs 10 16 14 8 Past Service Costs - Curtailment and Plan Amendments — — 10 — Interest Costs (1) 9 7 10 7 Benefits Paid (8) (12) (9) (8) Plan Participant Contributions 3 2 — — Re-measurements: (Gains) Losses From Experience Adjustments 4 1 1 (2) (Gains) Losses From Changes in Financial Assumptions 13 (64) 50 (57) Exchange Rate Movements and Other (1) 2 (1) 1 Defined Benefit Obligation, End of Year 202 172 249 174 Plan Assets Fair Value of Plan Assets, Beginning of Year 147 159 — — Employer Contributions 18 16 9 8 Plan Participant Contributions 3 2 — — Benefits Paid (7) (10) (9) (8) Interest Income (1) 8 4 — — Re-measurements: Return on Plan Assets (Excluding Interest Income) 10 (26) — — Exchange Rate Movements and Other (1) 2 — — Fair Value of Plan Assets, End of Year 178 147 — — Defined Benefit Pension and OPEB Asset (Liability) (2) (24) (25) (249) (174) (1) Based on the discount rate of the defined benefit obligation at the beginning of the year. (2) Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities. |
Summary of Pension and OPEB Costs | B) Costs OPEB Plans For the years ended December 31, 2023 2022 2023 2022 Defined Benefit Plan Cost Current Service Costs 10 16 14 8 Past Service Costs – Curtailments and Plan Amendments — — 10 — Net Interest Costs 1 3 10 7 Re-measurements: Return on Plan Assets (Excluding Interest Income) (10) 26 — — (Gains) Losses From Experience Adjustments 4 1 1 (2) (Gains) Losses From Changes in Demographic Assumptions — — — — (Gains) Losses From Changes in Financial Assumptions 13 (64) 50 (57) Defined Benefit Plan Cost (Recovery) 18 (18) 85 (44) Defined Contribution Plan Cost (1) 99 72 — — Total Plan Cost 117 54 85 (44) (1) Includes defined contribution and U.S. 401(k) plans. |
Summary of Fair Value of the Plan Assets | The fair value of the DB Pension Plan assets, as represented by fair value hierarchy levels are as follows: As at December 31, 2023 2022 Level 1 – Cash and Cash Equivalents 5 7 Level 2 – Equity and Fixed Income Funds 161 130 Level 3 – Real Estate Funds and Other 12 10 178 147 |
Summary of principal weighted average actuarial assumptions used to determine benefit obligations and expenses | The principal weighted average actuarial assumptions used to determine benefit obligations are as follows: Defined Benefit Plan OPEB Plans For the years ended December 31, 2023 2022 2023 2022 Discount Rate (percent) 4.58 5.12 4.65 5.13 Future Salary Growth Rate (percent) 4.00 4.05 N/A N/A Average Longevity (years) 88.4 88.4 88.4 88.4 Health Care Cost Trend Rate (percent) N/A N/A 5.24 5.24 |
Sensitivity of defined benefit and OPEB obligation to changes in relevant actuarial assumptions | 2023 2022 As at December 31, Increase Decrease Increase Decrease Discount Rate (54) 66 (43) 51 |
Share Capital and Warrants (Tab
Share Capital and Warrants (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of classes of share capital [abstract] | |
Summary of Share Capital | B) Issued and Outstanding – Common Shares 2023 2022 Number of Common Shares (thousands) Amount Number of Common Shares (thousands) Amount Outstanding, Beginning of Year 1,909,190 16,320 2,001,211 17,016 Issued Upon Exercise of Warrants 2,610 26 9,399 93 Issued Under Stock Option Plans 3,679 58 11,069 170 Purchase of Common Shares under NCIB (43,611) (373) (112,489) (959) Outstanding, End of Year 1,871,868 16,031 1,909,190 16,320 As at December 31, 2023 Dividend Reset Date Dividend Rate (percent) Number of Preferred Shares (thousands) Series 1 First Preferred Shares March 31, 2026 2.58 10,740 Series 2 First Preferred Shares (1) Quarterly 6.77 1,260 Series 3 First Preferred Shares December 31, 2024 4.69 10,000 Series 5 First Preferred Shares March 31, 2025 4.59 8,000 Series 7 First Preferred Shares June 30, 2025 3.94 6,000 (1) The floating-rate dividend was 5.86 percent from December 31, 2022, to March 30, 2023 (December 31, 2021, to March 30, 2022 – 1.86 percent); 6.29 percent from March 31, 2023, to June 29, 2023 (March 31, 2022, to June 29, 2022 – 2.35 percent); 6.29 percent from June 30, 2023, to September 29, 2023 (June 30, 2022, to September 29, 2022 – 3.21 percent); and 6.89 percent from September 30, 2023, to December 30, 2023 (September 30, 2022, to December 30, 2022 – 5.05 percent). 2023 2022 Number of Warrants (thousands) Amount Number of Warrants (thousands) Amount Outstanding, Beginning of Year 55,720 184 65,119 215 Exercised (2,610) (8) (9,399) (31) Purchased and Cancelled (45,485) (151) — — Outstanding, End of Year 7,625 25 55,720 184 Retained Earnings Prior to Ovintiv Split Stock-Based Compensation Total As at December 31, 2021 3,966 318 4,284 Stock-Based Compensation Expense — 10 10 Purchase of Common Shares Under NCIB (1,571) — (1,571) Common Shares Issued on Exercise of Stock Options — (32) (32) As at December 31, 2022 2,395 296 2,691 Stock-Based Compensation Expense — 11 11 Purchase of Common Shares Under NCIB (688) — (688) Common Shares Issued on Exercise of Stock Options — (12) (12) As at December 31, 2023 1,707 295 2,002 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract] | |
Summary of Accumulated Other Comprehensive Income (Loss) | Pension and Other Post-Retirement Benefits Private Equity Instruments Foreign Currency Translation Adjustment Total As at December 31, 2021 28 27 629 684 Other Comprehensive Income (Loss), Before Tax 96 2 713 811 Income Tax (Expense) Recovery (25) — — (25) As at December 31, 2022 99 29 1,342 1,470 Other Comprehensive Income (Loss), Before Tax (58) 63 (286) (281) Reclassification on Divestiture (Note 5) — — 12 12 Income Tax (Expense) Recovery 14 (7) — 7 As at December 31, 2023 55 85 1,068 1,208 |
Stock-Based Compensation Plans
Stock-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of terms and conditions of share-based payment arrangement [abstract] | |
Summary of Assumptions Used to Determine Fair Value of Options Granted | The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate (percent) 3.42 Expected Dividend Yield (percent) 1.78 Expected Volatility (1) (percent) 31.95 Expected Life (years) 5.45 (1) Expected volatility has been based on historical share volatility of the Company. |
Summary of Options Outstanding and Exercisable | Number of Stock Options with Associated Net Settlement Rights Weighted For the year ended December 31, 2023 (thousands) ($/unit) Outstanding, Beginning of Year 14,349 12.38 Granted 1,571 24.34 Exercised (3,839) 13.08 Forfeited (128) 15.78 Expired (58) 19.89 Outstanding, End of Year 11,895 13.66 Outstanding Exercisable As at December 31, 2023 Number of Weighted Average Remaining Contractual Life Weighted Average Exercise Price Number of Weighted Average Exercise Price Range of Exercise Price ($) (thousands) (years) ($/unit) (thousands) ($/unit) 5.00 to 9.99 4,303 3.83 8.77 2,218 8.85 10.00 to 14.99 4,163 2.92 11.93 3,894 11.94 15.00 to 19.99 1,851 5.13 19.88 536 19.88 20.00 to 24.99 1,561 6.17 24.25 10 22.75 25.00 to 29.99 17 6.70 27.71 — — 11,895 4.03 13.66 6,658 11.56 Number of Cenovus Replacement Stock Options Weighted Average Exercise Price For the year ended December 31, 2023 (thousands) ($/unit) Outstanding, Beginning of Year 3,467 9.99 Exercised (2,113) 9.97 Forfeited (23) 6.58 Expired (326) 21.09 Outstanding, End of Year 1,005 6.49 Outstanding Exercisable As at December 31, 2023 Number of Cenovus Replacement Stock Options Weighted Average Remaining Contractual Life Weighted Average Exercise Price Number of Cenovus Replacement Stock Options Weighted Average Exercise Price Range of Exercise Price ($) (thousands) (years) ($/unit) (thousands) ($/unit) 3.00 to 4.99 782 1.22 3.54 782 3.54 5.00 to 9.99 28 0.42 6.19 28 6.19 10.00 to 14.99 — — — — — 15.00 to 19.99 195 0.18 18.35 195 18.35 1,005 0.99 6.49 1,005 6.49 Number of Performance Share Units For the year ended December 31, 2023 (thousands) Outstanding, Beginning of Year 8,678 Granted 2,539 Vested and Paid Out (972) Forfeited (231) Units in Lieu of Base Dividends 229 Outstanding, End of Year 10,243 Number of Restricted Share Units For the year ended December 31, 2023 (thousands) Outstanding, Beginning of Year 6,655 Granted 2,961 Vested and Paid Out (2,300) Forfeited (243) Units in Lieu of Base Dividends 161 Outstanding, End of Year 7,234 Number of Deferred For the year ended December 31, 2023 (thousands) Outstanding, Beginning of Year 1,506 Granted to Directors 126 Granted 59 Units in Lieu of Dividends 37 Redeemed (37) Outstanding, End of Year 1,691 |
Summary of Stock-Based Compensation | E) Total Stock-Based Compensation For the years ended December 31, 2023 2022 Stock Options With Associated Net Settlement Rights 11 15 Cenovus Replacement Stock Options (5) 53 Performance Share Units 47 183 Restricted Share Units 46 100 Deferred Share Units (2) 22 Total Stock-Based Compensation Expense (Recovery) 97 373 |
Employee Salaries and Benefit_2
Employee Salaries and Benefit Expenses (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Salaries And Employee Benefits [Abstract] | |
Summary of Employee Salaries and Benefit Expenses | 33. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, 2023 2022 Salaries, Bonuses and Other Short-Term Employee Benefits 1,344 1,246 Pension and Post-Employment Benefits 125 92 Stock-Based Compensation (Note 32) 97 373 Other Incentive Benefits (Recovery) — (9) Termination Benefits 14 27 1,580 1,729 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of transactions between related parties [abstract] | |
Summary of Key Management Compensation | Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is: For the years ended December 31, 2023 2022 Salaries, Director Fees and Other Short-Term Benefits 40 40 Pension and Post-Employment Benefits 3 4 Stock-Based Compensation 40 140 Termination Benefits — 3 83 187 |
Financial Instruments (Tables)
Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of detailed information about financial instruments [abstract] | |
Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets | 2023 2022 Fair Value, Beginning of Year 55 53 Acquisition 13 — Changes in Fair Value 63 2 Fair Value, End of Year 131 55 |
Summary of Unrealized Risk Management Positions | Summary of Risk Management Positions 2023 2022 Risk Management Risk Management As at December 31, Asset Liability Net Asset Liability Net Crude Oil, Natural Gas, Condensate and Refined Products 11 19 (8) 2 40 (38) Power Swap Contracts 2 — 2 1 7 (6) Renewable Power Contracts 18 — 18 90 — 90 31 19 12 93 47 46 |
Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value | As at December 31, 2023 2022 Level 2 – Prices Sourced From Observable Data or Market Corroboration (6) (44) Level 3 – Prices Sourced From Partially Unobservable Data 18 90 12 46 |
Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities | 2023 2022 Fair Value of Contracts, Beginning of Year 46 (68) Change in Fair Value of Contracts in Place at Beginning of Year — (5) Change in Fair Value of Contracts Entered Into During the Year (45) (1,641) Fair Value of Contracts Realized During the Year 9 1,762 Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts 2 (2) Fair Value of Contracts, End of Year 12 46 Offsetting Financial Assets and Liabilities Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same. |
Summary of Offsetting Risk Management Positions | 2023 2022 Risk Management Risk Management As at December 31, Asset Liability Net Asset Liability Net Recognized Risk Management Positions Gross Amount 71 59 12 153 107 46 Amount Offset (40) (40) — (60) (60) — Net Amount 31 19 12 93 47 46 |
Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax | For the years ended December 31, 2023 2022 Realized (Gain) Loss 9 1,762 Unrealized (Gain) Loss 52 (126) (Gain) Loss on Risk Management 61 1,636 The impact of the below on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows: As at December 31, 2023 Sensitivity Range Increase Decrease Power Commodity Price ± C$20.00/MWh (1) Applied to Power Hedges 92 (92) (1) One thousand kilowatts of electricity per hour (“MWh”). As at December 31, 2022 Sensitivity Range Increase Decrease WCS and Condensate Differential Price ± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production 13 (13) Power Commodity Price ± C$20.00/MWh Applied to Power Hedges 113 (113) U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate 14 (17) In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows: As at December 31, 2023 2022 $0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate 197 246 $0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate (197) (246) |
Summary of Earnings Impact of (Gain) Loss from Risk Management Positions | changes in WCS forward prices, with fluctuations in all other variables held constant, could have impacted earnings before income tax as follows: 2023 2022 As at December 31, Sensitivity Range Increase Decrease Increase Decrease WCS Forward Prices ± $10.00 per barrel (21) 45 (68) 157 |
Risk Management (Tables)
Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Risk Management [Abstract] | |
Net Fair Value of Risk Management Positions | Net Fair Value of Risk Management Positions As at December 31, 2023 Notional Volumes (1) (2) Terms (3) Weighted Average Price (1) (2) Fair Value Asset (Liability) Futures Contracts Related to Blending (4) WTI Fixed – Sell 3.5 MMbbls January 2024 – December 2024 US$75.22/bbl 16 WTI Fixed – Buy 1.5 MMbbls January 2024 – December 2024 US$73.69/bbl (4) Power Swap Contacts 2 Renewable Power Contracts 18 Other Financial Positions (5) (20) Total Fair Value 12 (1) Million barrels ("MMbbls"). (2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month. (3) Includes individual contracts with varying terms, the longest of which is 13 months. (4) WTI futures contracts are used to help manage price exposure to condensate used for blending. |
Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax | For the years ended December 31, 2023 2022 Realized (Gain) Loss 9 1,762 Unrealized (Gain) Loss 52 (126) (Gain) Loss on Risk Management 61 1,636 The impact of the below on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows: As at December 31, 2023 Sensitivity Range Increase Decrease Power Commodity Price ± C$20.00/MWh (1) Applied to Power Hedges 92 (92) (1) One thousand kilowatts of electricity per hour (“MWh”). As at December 31, 2022 Sensitivity Range Increase Decrease WCS and Condensate Differential Price ± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production 13 (13) Power Commodity Price ± C$20.00/MWh Applied to Power Hedges 113 (113) U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate 14 (17) In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows: As at December 31, 2023 2022 $0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate 197 246 $0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate (197) (246) |
Undiscounted Cash Outflows Relating to Financial Liabilities | Undiscounted cash outflows relating to financial liabilities are: As at December 31, 2023 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total Accounts Payable and Accrued Liabilities (1) 5,480 — — — 5,480 Short-Term Borrowings 179 — — — 179 Contingent Payments 168 — — — 168 Lease Liabilities (2) 438 712 569 2,635 4,354 Long-Term Debt (2) 313 792 3,007 7,145 11,257 As at December 31, 2022 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total Accounts Payable and Accrued Liabilities (1) 6,124 — — — 6,124 Short-Term Borrowings 115 — — — 115 Contingent Payments 271 167 — — 438 Lease Liabilities (2) 426 746 596 2,889 4,657 Long-Term Debt (2) 401 983 2,014 11,196 14,594 (1) Includes current risk management liabilities. (2) Principal and interest, including current portion, if applicable. |
Supplementary Cash Flow Infor_2
Supplementary Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Of Supplementary Cash Flow Information [Abstract] | |
Disclosure Of Changes In Non-Cash Working Capital Items | A) Working Capital As at December 31, 2023 2022 Total Current Assets 9,708 12,430 Total Current Liabilities 6,210 8,021 Working Capital 3,498 4,409 As at December 31, 2023, adjusted working capital, which excludes the current portion of the contingent payments, was $3.7 billion (December 31, 2022 – $4.7 billion). Changes in non-cash working capital is as follows: For the years ended December 31, 2023 2022 Accounts Receivable and Accrued Revenues 314 838 Income Tax Receivable (295) (58) Inventories 216 (143) Accounts Payable and Accrued Liabilities (685) (524) Income Tax Payable (1,112) 1,000 Total Change in Non-Cash Working Capital (1,562) 1,113 Net Change in Non-Cash Working Capital – Operating Activities (1,193) 575 Net Change in Non-Cash Working Capital – Investing Activities (369) 538 Total Change in Non-Cash Working Capital (1,562) 1,113 For the years ended December 31, 2023 2022 Interest Paid 402 647 Interest Received 130 78 Income Taxes Paid 2,595 723 |
Summary of Reconciliation of Liabilities to Cash Flows from Financing Activities | Dividends Payable Warrant Purchase Payable Short-Term Borrowings Long-Term Debt Lease Liabilities As at December 31, 2021 — — 79 12,385 2,957 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings — — 34 — — Repayment of Long-Term Debt — — — (4,149) — Principal Repayment of Leases — — — — (302) Base Dividends Paid on Common Shares (682) — — — — Variable Dividends Paid on Common Shares (219) — — — — Dividends Paid on Preferred Shares (26) — — — — Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt — — — (29) — Finance and Transaction Costs — — — (28) — Lease Additions — — — — 25 Base Dividends Declared on Common Shares 682 — — — — Variable Dividends Declared on Common Shares 219 — — — — Dividends Declared on Preferred Shares 35 — — — — Exchange Rate Movements and Other — — 2 512 156 As at December 31, 2022 9 — 115 8,691 2,836 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings — — 58 — — Repayment of Long-Term Debt — — — (1,346) — Principal Repayment of Leases — — — — (288) Base Dividends Paid on Common Shares (990) — — — — Dividends Paid on Preferred Shares (36) — — — — Payment for Purchase of Warrants — (711) — — — Finance and Transaction Costs — (2) — — — Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt — — — (84) — Finance and Transaction Costs — 2 — (19) — Lease Acquisitions — — — — 33 Lease Additions — — — — 57 Lease Divestitures — — — — (11) Base Dividends Declared on Common Shares 990 — — — — Dividends Declared on Preferred Shares 36 — — — — Warrants Purchased and Cancelled — 711 — — — Exchange Rate Movements and Other — — 6 (134) 31 As at December 31, 2023 9 — 179 7,108 2,658 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments And Contingencies [Abstract] | |
Minimum Future Payments, Commitments And Contingent Liabilities | Future payments for the Company’s commitments are below: As at December 31, 2023 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Transportation and Storage (1) (2) 2,018 1,927 1,680 1,663 1,641 15,738 24,667 Product Purchases 617 — — — — — 617 Real Estate 57 57 59 63 58 604 898 Obligation to Fund HCML 94 94 94 89 52 90 513 Other Long-Term Commitments (3) 417 194 184 175 166 965 2,101 Total Commitments 3,203 2,272 2,017 1,990 1,917 17,397 28,796 As at December 31, 2022 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Transportation and Storage (1) (2) 1,747 2,011 1,542 1,416 1,360 13,005 21,081 Product Purchases 1,626 1,509 922 922 922 3,457 9,358 Real Estate 48 50 50 50 54 604 856 Obligation to Fund HCML 92 105 96 96 91 143 623 Other Long-Term Commitments 381 90 75 74 65 395 1,080 Total Commitments 3,894 3,765 2,685 2,558 2,492 17,604 32,998 (1) Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 – $9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator. (2) As at December 31, 2023, includes $2.1 billion related to long-term transportation and storage commitments with HMLP (December 31, 2022 – $2.2 billion). (3) |
Prior Period Revisions (Tables)
Prior Period Revisions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Disclosure of Revisions to Prior Period | The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) and segmented disclosures to the corresponding revised amounts: Year Ended December 31, 2022 Oil Sands Segment Previously Reported Revisions Revised Balance Gross Sales 34,775 (92) 34,683 Purchased Product 4,810 (92) 4,718 29,965 — 29,965 Conventional Segment Gross Sales 4,332 107 4,439 Transportation and Blending 143 107 250 4,189 — 4,189 U.S. Refining Segment Gross Sales 30,310 (92) 30,218 Purchased Product 26,112 (92) 26,020 4,198 — 4,198 Corporate and Eliminations Segment Gross Sales (7,464) 77 (7,387) Purchased Product (5,533) 341 (5,192) Transportation and Blending (664) (511) (1,175) Operating (1,270) 247 (1,023) 3 — 3 Consolidated Purchased Product 33,801 157 33,958 Transportation and Blending 11,530 (404) 11,126 Operating 5,569 247 5,816 50,900 — 50,900 |
Description of Business and S_3
Description of Business and Segmented Disclosures - Additional Information (Detail) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 CAD ($) u_cve_customer plant | Dec. 31, 2022 CAD ($) u_cve_customer | |
Disclosure of operating segments [line items] | ||
Number of major customers | u_cve_customer | 2 | 2 |
Gross Sales | $ 55,474 | $ 71,765 |
Downstream | ||
Disclosure of operating segments [line items] | ||
Gross Sales | $ 32,626 | 38,010 |
Downstream | Canadian Refining | ||
Disclosure of operating segments [line items] | ||
Number of ethanol plants | plant | 2 | |
Gross Sales | $ 6,233 | 7,792 |
Customer One | ||
Disclosure of operating segments [line items] | ||
Gross Sales | 18,000 | 16,100 |
Customer Two | ||
Disclosure of operating segments [line items] | ||
Gross Sales | $ 7,100 | $ 9,100 |
Bottom of range | ||
Disclosure of operating segments [line items] | ||
Percentage of entity's revenues from gross sales | 10% |
Description of Business and S_4
Description of Business and Segmented Disclosures - Schedule of Segment and Operational Information (Detail) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Revenues | |||
Gross Sales | $ 55,474 | $ 71,765 | |
Less: Royalties | 3,270 | 4,868 | |
Revenues | 52,204 | 66,897 | |
Expenses | |||
Purchased Product | [1] | 24,715 | 33,958 |
Transportation and Blending | [1] | 10,141 | 11,126 |
Operating | [1] | 6,352 | 5,816 |
(Gain) Loss on Risk Management | 61 | 1,636 | |
Depreciation, Depletion and Amortization | 4,644 | 4,679 | |
Exploration Expense | 42 | 101 | |
(Income) Loss From Equity-Accounted Affiliates | (51) | (15) | |
Segment Income (Loss) | 6,300 | 9,596 | |
General and Administrative | 688 | 865 | |
Finance Costs | 671 | 820 | |
Interest Income | (133) | (81) | |
Integration, Transaction and Other Costs | 85 | 106 | |
Foreign Exchange (Gain) Loss, Net | (67) | 343 | |
Revaluation (Gain) Loss | 34 | (549) | |
Re-measurement of Contingent Payment | 59 | 162 | |
(Gain) Loss on Divestiture of Assets | (14) | (269) | |
Other (Income) Loss, Net | (63) | (532) | |
Total Non-operating (Income) Expense | 1,260 | 865 | |
Earnings (Loss) Before Income Tax | 5,040 | 8,731 | |
Income Tax Expense (Recovery) | 931 | 2,281 | |
Net Earnings (Loss) | 4,109 | 6,450 | |
Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 9 | 1,762 | |
Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 52 | (126) | |
Upstream | |||
Revenues | |||
Gross Sales | 31,082 | 41,142 | |
Less: Royalties | 3,270 | 4,868 | |
Revenues | 27,812 | 36,274 | |
Expenses | |||
Purchased Product | 3,152 | 6,741 | |
Transportation and Blending | 11,088 | 12,301 | |
Operating | 3,690 | 3,789 | |
Operating Margin | 9,870 | 11,824 | |
Depreciation, Depletion and Amortization | 3,866 | 3,718 | |
Exploration Expense | 42 | 101 | |
(Income) Loss From Equity-Accounted Affiliates | (51) | (15) | |
Segment Income (Loss) | 6,017 | 8,075 | |
Upstream | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 12 | 1,619 | |
Upstream | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | (4) | (55) | |
Downstream | |||
Revenues | |||
Gross Sales | 32,626 | 38,010 | |
Less: Royalties | 0 | 0 | |
Revenues | 32,626 | 38,010 | |
Expenses | |||
Purchased Product | 28,273 | 32,409 | |
Transportation and Blending | 0 | 0 | |
Operating | 3,201 | 3,050 | |
Operating Margin | 1,152 | 2,439 | |
Depreciation, Depletion and Amortization | 671 | 848 | |
Exploration Expense | 0 | 0 | |
(Income) Loss From Equity-Accounted Affiliates | 0 | 0 | |
Segment Income (Loss) | 498 | 1,573 | |
Downstream | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 0 | 112 | |
Downstream | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | (17) | 18 | |
Oil Sands | |||
Revenues | |||
Gross Sales | 34,683 | ||
Expenses | |||
Purchased Product | 4,718 | ||
Oil Sands | Upstream | |||
Revenues | |||
Gross Sales | 26,192 | 34,683 | |
Less: Royalties | 3,059 | 4,493 | |
Revenues | 23,133 | 30,190 | |
Expenses | |||
Purchased Product | 1,457 | 4,718 | |
Transportation and Blending | 10,774 | 12,036 | |
Operating | 2,716 | 2,930 | |
Operating Margin | 8,169 | 8,979 | |
Depreciation, Depletion and Amortization | 2,993 | 2,763 | |
Exploration Expense | 19 | 9 | |
(Income) Loss From Equity-Accounted Affiliates | 6 | 8 | |
Segment Income (Loss) | 5,136 | 6,267 | |
Oil Sands | Upstream | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 17 | 1,527 | |
Oil Sands | Upstream | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 15 | (68) | |
Conventional | |||
Revenues | |||
Gross Sales | 4,439 | ||
Expenses | |||
Transportation and Blending | 250 | ||
Conventional | Upstream | |||
Revenues | |||
Gross Sales | 3,273 | 4,439 | |
Less: Royalties | 112 | 298 | |
Revenues | 3,161 | 4,141 | |
Expenses | |||
Purchased Product | 1,695 | 2,023 | |
Transportation and Blending | 298 | 250 | |
Operating | 590 | 541 | |
Operating Margin | 583 | 1,235 | |
Depreciation, Depletion and Amortization | 386 | 370 | |
Exploration Expense | 6 | 1 | |
(Income) Loss From Equity-Accounted Affiliates | 0 | 0 | |
Segment Income (Loss) | 210 | 851 | |
Conventional | Upstream | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | (5) | 92 | |
Conventional | Upstream | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | (19) | 13 | |
Offshore | Upstream | |||
Revenues | |||
Gross Sales | 1,617 | 2,020 | |
Less: Royalties | 99 | 77 | |
Revenues | 1,518 | 1,943 | |
Expenses | |||
Purchased Product | 0 | 0 | |
Transportation and Blending | 16 | 15 | |
Operating | 384 | 318 | |
Operating Margin | 1,118 | 1,610 | |
Depreciation, Depletion and Amortization | 487 | 585 | |
Exploration Expense | 17 | 91 | |
(Income) Loss From Equity-Accounted Affiliates | (57) | (23) | |
Segment Income (Loss) | 671 | 957 | |
Offshore | Upstream | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 0 | 0 | |
Offshore | Upstream | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 0 | 0 | |
Canadian Refining | Downstream | |||
Revenues | |||
Gross Sales | 6,233 | 7,792 | |
Less: Royalties | 0 | 0 | |
Revenues | 6,233 | 7,792 | |
Expenses | |||
Purchased Product | 4,919 | 6,389 | |
Transportation and Blending | 0 | 0 | |
Operating | 639 | 704 | |
Operating Margin | 675 | 699 | |
Depreciation, Depletion and Amortization | 185 | 208 | |
Exploration Expense | 0 | 0 | |
(Income) Loss From Equity-Accounted Affiliates | 0 | 0 | |
Segment Income (Loss) | 490 | 491 | |
Canadian Refining | Downstream | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 0 | 0 | |
Canadian Refining | Downstream | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 0 | 0 | |
U.S. Refining | |||
Revenues | |||
Gross Sales | 30,218 | ||
Expenses | |||
Purchased Product | 26,020 | ||
U.S. Refining | Downstream | |||
Revenues | |||
Gross Sales | 26,393 | 30,218 | |
Less: Royalties | 0 | 0 | |
Revenues | 26,393 | 30,218 | |
Expenses | |||
Purchased Product | 23,354 | 26,020 | |
Transportation and Blending | 0 | 0 | |
Operating | 2,562 | 2,346 | |
Operating Margin | 477 | 1,740 | |
Depreciation, Depletion and Amortization | 486 | 640 | |
Exploration Expense | 0 | 0 | |
(Income) Loss From Equity-Accounted Affiliates | 0 | 0 | |
Segment Income (Loss) | 8 | 1,082 | |
U.S. Refining | Downstream | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | 0 | 112 | |
U.S. Refining | Downstream | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | (17) | 18 | |
Corporate and Eliminations | |||
Revenues | |||
Gross Sales | (8,234) | (7,387) | |
Less: Royalties | 0 | 0 | |
Revenues | (8,234) | (7,387) | |
Expenses | |||
Purchased Product | (6,710) | (5,192) | |
Transportation and Blending | (947) | (1,175) | |
Operating | (539) | (1,023) | |
Depreciation, Depletion and Amortization | 107 | 113 | |
Exploration Expense | 0 | 0 | |
(Income) Loss From Equity-Accounted Affiliates | 0 | 0 | |
Segment Income (Loss) | (215) | (52) | |
General and Administrative | 688 | 865 | |
Finance Costs | 671 | 820 | |
Interest Income | (133) | (81) | |
Integration, Transaction and Other Costs | 85 | 106 | |
Foreign Exchange (Gain) Loss, Net | (67) | 343 | |
Revaluation (Gain) Loss | 34 | (549) | |
Re-measurement of Contingent Payment | 59 | 162 | |
(Gain) Loss on Divestiture of Assets | (14) | (269) | |
Other (Income) Loss, Net | (63) | (532) | |
Total Non-operating (Income) Expense | 1,260 | 865 | |
Corporate and Eliminations | Realized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | (3) | 31 | |
Corporate and Eliminations | Unrealized (Gain) Loss | |||
Expenses | |||
(Gain) Loss on Risk Management | $ 73 | $ (89) | |
[1] Comparative periods reflect certain revisions. See Note 39. |
Description of Business and S_5
Description of Business and Segmented Disclosures - Schedule of Revenues by Product (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Upstream | ||
Revenue | $ 52,204 | $ 66,897 |
U.S. Refining | ||
Consolidated | 52,204 | 66,897 |
Corporate and Eliminations | ||
Upstream | ||
Revenue | (8,234) | (7,387) |
U.S. Refining | ||
Corporate and Eliminations | (8,234) | (7,387) |
Consolidated | (8,234) | (7,387) |
Upstream | ||
Upstream | ||
Revenue | 27,812 | 36,274 |
U.S. Refining | ||
Consolidated | 27,812 | 36,274 |
Upstream | Oil Sands | ||
Upstream | ||
Crude Oil | 22,550 | 28,921 |
NGLs | 352 | 877 |
Natural Gas and Other | 231 | 392 |
Canadian Refining | ||
Synthetic Crude Oil | 22,550 | 28,921 |
Upstream | Conventional | ||
Upstream | ||
Crude Oil | 589 | 429 |
NGLs | 799 | 926 |
Natural Gas and Other | 1,773 | 2,786 |
Canadian Refining | ||
Synthetic Crude Oil | 589 | 429 |
Upstream | Offshore | ||
Upstream | ||
Crude Oil | 385 | 581 |
NGLs | 280 | 354 |
Natural Gas | 853 | 1,008 |
Canadian Refining | ||
Synthetic Crude Oil | 385 | 581 |
Downstream | ||
Upstream | ||
Revenue | 32,626 | 38,010 |
U.S. Refining | ||
Consolidated | 32,626 | 38,010 |
Downstream | Canadian Refining | ||
Canadian Refining | ||
Diesel | 1,752 | 2,164 |
Asphalt | 571 | 620 |
Gasoline | 522 | 948 |
Other Products and Services | 1,264 | 1,700 |
U.S. Refining | ||
Gasoline | 522 | 948 |
Distillates | 1,752 | 2,164 |
Asphalt | 571 | 620 |
Other products | 1,264 | 1,700 |
Downstream | Canadian Refining | Synthetic Oil | ||
Upstream | ||
Crude Oil | 2,124 | 2,360 |
Canadian Refining | ||
Synthetic Crude Oil | 2,124 | 2,360 |
Downstream | U.S. Refining | ||
Canadian Refining | ||
Diesel | 9,612 | 11,453 |
Asphalt | 864 | 533 |
Gasoline | 12,375 | 14,116 |
Other Products and Services | 3,542 | 4,116 |
U.S. Refining | ||
Gasoline | 12,375 | 14,116 |
Distillates | 9,612 | 11,453 |
Asphalt | 864 | 533 |
Other products | $ 3,542 | $ 4,116 |
Description of Business and S_6
Description of Business and Segmented Disclosures - Schedule of Geographical Information (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of geographical areas [line items] | ||
Revenue | $ 52,204 | $ 66,897 |
Non-current assets | 43,058 | 42,447 |
Canada | ||
Disclosure of geographical areas [line items] | ||
Revenue | 25,128 | 33,314 |
Non-current assets | 35,876 | 35,194 |
United States | ||
Disclosure of geographical areas [line items] | ||
Revenue | 25,943 | 32,221 |
Non-current assets | 5,230 | 4,824 |
China | ||
Disclosure of geographical areas [line items] | ||
Revenue | 1,133 | 1,362 |
Non-current assets | 1,608 | 2,064 |
Indonesia | ||
Disclosure of geographical areas [line items] | ||
Non-current assets | $ 344 | $ 365 |
Description of Business and S_7
Description of Business and Segmented Disclosures - Schedule of Assets by Segment (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure Of Reportable Segments [Line Items] | |||
E&E Assets | $ 738 | $ 685 | |
PP&E | 37,250 | 36,499 | |
ROU Assets | 1,680 | 1,845 | |
Goodwill | 2,923 | 2,923 | $ 3,473 |
Total Assets | 53,915 | 55,869 | |
Oil Sands | |||
Disclosure Of Reportable Segments [Line Items] | |||
E&E Assets | 729 | 674 | |
PP&E | 24,443 | 24,657 | |
ROU Assets | 849 | 638 | |
Goodwill | 2,923 | 2,923 | |
Total Assets | 31,673 | 32,248 | |
Conventional | |||
Disclosure Of Reportable Segments [Line Items] | |||
E&E Assets | 0 | 6 | |
PP&E | 2,209 | 2,020 | |
ROU Assets | 1 | 2 | |
Goodwill | 0 | 0 | |
Total Assets | 2,429 | 2,410 | |
Offshore | |||
Disclosure Of Reportable Segments [Line Items] | |||
E&E Assets | 9 | 5 | |
PP&E | 2,798 | 2,549 | |
ROU Assets | 102 | 152 | |
Goodwill | 0 | 0 | |
Total Assets | 3,511 | 3,339 | |
Canadian Refining | |||
Disclosure Of Reportable Segments [Line Items] | |||
E&E Assets | 0 | 0 | |
PP&E | 2,469 | 2,466 | |
ROU Assets | 28 | 252 | |
Goodwill | 0 | 0 | |
Total Assets | 2,960 | 3,172 | |
U.S. Refining | |||
Disclosure Of Reportable Segments [Line Items] | |||
E&E Assets | 0 | 0 | |
PP&E | 5,014 | 4,482 | |
ROU Assets | 268 | 329 | |
Goodwill | 0 | 0 | |
Total Assets | 8,660 | 8,324 | |
Corporate and Eliminations | |||
Disclosure Of Reportable Segments [Line Items] | |||
E&E Assets | 0 | 0 | |
PP&E | 317 | 325 | |
ROU Assets | 432 | 472 | |
Goodwill | 0 | 0 | |
Total Assets | $ 4,682 | $ 6,376 |
Description of Business and S_8
Description of Business and Segmented Disclosures - Schedule of Capital Expenditures (Detail) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Feb. 28, 2023 | Aug. 31, 2022 | |
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | $ 4,298 | $ 3,708 | ||
Acquisitions (Note 5) | 427 | 1,621 | ||
Total Capital Expenditures | 4,725 | 5,329 | ||
Sunrise Oil Sands Partnership | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo | $ 1,559 | |||
Fair value of accounts receivable and accrued revenues recognised as of acquisition date | $ 1,559 | |||
BP-Husky Refining LLC | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo | $ 508 | |||
Fair value of accounts receivable and accrued revenues recognised as of acquisition date | 508 | |||
Upstream | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 3,476 | 2,446 | ||
Downstream | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 747 | 1,176 | ||
Oil Sands | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Acquisitions (Note 5) | 37 | 1,609 | ||
Oil Sands | Upstream | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 2,382 | 1,792 | ||
Conventional | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Acquisitions (Note 5) | 5 | 12 | ||
Conventional | Upstream | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 452 | 344 | ||
Offshore | Upstream | Asia Pacific | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 7 | 8 | ||
Offshore | Upstream | Atlantic | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 635 | 302 | ||
Canadian Refining | Downstream | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 145 | 117 | ||
U.S. Refining | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Acquisitions (Note 5) | 385 | 0 | ||
U.S. Refining | BP-Husky Refining LLC | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo | 368 | |||
Fair value of accounts receivable and accrued revenues recognised as of acquisition date | $ 368 | |||
U.S. Refining | Downstream | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | 602 | 1,059 | ||
Corporate and Eliminations | ||||
Disclosure Of Reportable Segments [Line Items] | ||||
Capital Investment | $ 75 | $ 86 |
Summary of Accounting Policie_3
Summary of Accounting Policies - Additional information (Detail) | 12 Months Ended |
Dec. 31, 2023 | |
Information technology assets | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 3 years |
Land improvements and buildings | Bottom of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 15 years |
Land improvements and buildings | Top of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 40 years |
Office improvements and buildings | Bottom of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 3 years |
Office improvements and buildings | Top of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 15 years |
Refining equipment | Bottom of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 10 years |
Refining equipment | Top of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 60 years |
Other | Bottom of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 3 years |
Other | Top of range | |
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |
Useful life measured as period of time, property, plant and equipment | 60 years |
Summary of Accounting Policie_4
Summary of Accounting Policies - Revisions to Prior Periods (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Gross Sales | $ 55,474 | $ 71,765 | |
Purchased Product | [1] | 24,715 | 33,958 |
Operating | [1] | 6,352 | 5,816 |
Transportation and Blending | [1] | 10,141 | 11,126 |
Depreciation, Depletion and Amortization | 4,644 | 4,679 | |
Oil Sands | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Gross Sales | 34,683 | ||
Purchased Product | 4,718 | ||
Gross sales less purchased product | 29,965 | ||
Corporate and Eliminations | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Gross Sales | (8,234) | (7,387) | |
Purchased Product | (6,710) | (5,192) | |
Operating | (539) | (1,023) | |
Transportation and Blending | (947) | (1,175) | |
Depreciation, Depletion and Amortization | $ 107 | 113 | |
Previously Reported | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Purchased Product | 33,801 | ||
Operating | 5,569 | ||
Transportation and Blending | 11,530 | ||
Previously Reported | Oil Sands | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Gross Sales | 34,775 | ||
Purchased Product | 4,810 | ||
Gross sales less purchased product | 29,965 | ||
Previously Reported | Corporate and Eliminations | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Gross Sales | (7,464) | ||
Purchased Product | (5,533) | ||
Operating | (1,270) | ||
Transportation and Blending | (664) | ||
Revisions | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Purchased Product | 157 | ||
Operating | 247 | ||
Transportation and Blending | (404) | ||
Revisions | Oil Sands | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Gross Sales | (92) | ||
Purchased Product | (92) | ||
Gross sales less purchased product | 0 | ||
Revisions | Corporate and Eliminations | |||
Disclosure Of Summary Of Significant Accounting Policies [Line Items] | |||
Gross Sales | 77 | ||
Purchased Product | 341 | ||
Operating | 247 | ||
Transportation and Blending | $ (511) | ||
[1] Comparative periods reflect certain revisions. See Note 39. |
Critical Accounting Judgments_2
Critical Accounting Judgments and Key Sources of Estimation Uncertainty - Additional Information (Detail) | 8 Months Ended | 12 Months Ended |
Aug. 30, 2022 | Dec. 31, 2023 | |
WRB Refining LP | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint operation | 50% | |
BP-Husky Refining LLC | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint operation | 50% | |
Sunrise Oil Sands Partnership | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint operation | 50% |
Acquisitions - Narrative (Detai
Acquisitions - Narrative (Details) $ in Millions, $ in Millions | 2 Months Ended | 7 Months Ended | 10 Months Ended | 12 Months Ended | |||||
Feb. 28, 2023 CAD ($) | Aug. 31, 2022 CAD ($) | Feb. 28, 2022 CAD ($) | Feb. 27, 2023 | Sep. 30, 2023 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Feb. 28, 2023 USD ($) | |
Disclosure of detailed information about business combination [line items] | |||||||||
Acquisition-related costs for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination | $ 11 | $ 11 | |||||||
BP-Husky Refining LLC | |||||||||
Disclosure of detailed information about business combination [line items] | |||||||||
Agreement to purchase remaining ownership | 50% | 50% | 50% | ||||||
Total Purchase Consideration | $ 514 | $ 378 | |||||||
Accounts Payable and Accrued Liabilities | 3 | ||||||||
Fair value of accounts receivable and accrued revenues recognised as of acquisition date | 508 | ||||||||
Carrying value of investment in joint ventures recognised as of acquisition date | 554 | ||||||||
Non-cash revaluation loss, before tax | 34 | ||||||||
Non-cash revaluation loss, after tax | $ 23 | ||||||||
Non-cash revaluation loss, cumulative foreign exchange | $ 12 | ||||||||
Acquisition-related costs for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination | 11 | $ 9 | |||||||
Revenue of acquiree since acquisition date | $ 4,100 | ||||||||
Profit (loss) of acquiree since acquisition date | $ (85) | ||||||||
Revenue of combined entity as if combination occurred at beginning of period | 52,200 | ||||||||
Profit (loss) of combined entity as if combination occurred at beginning of period | $ 4,000 | ||||||||
BP-Husky Refining LLC | Property, plant and equipment | |||||||||
Disclosure of detailed information about business combination [line items] | |||||||||
Measurement period adjustments recognised for particular assets, liabilities, non-controlling interests or items of consideration | 96 | ||||||||
BP-Husky Refining LLC | Inventory | |||||||||
Disclosure of detailed information about business combination [line items] | |||||||||
Measurement period adjustments recognised for particular assets, liabilities, non-controlling interests or items of consideration | (66) | ||||||||
BP-Husky Refining LLC | Other Liabilities | |||||||||
Disclosure of detailed information about business combination [line items] | |||||||||
Measurement period adjustments recognised for particular assets, liabilities, non-controlling interests or items of consideration | (3) | ||||||||
BP-Husky Refining LLC | Accounts Payable And Accrued Liabilities | |||||||||
Disclosure of detailed information about business combination [line items] | |||||||||
Measurement period adjustments recognised for particular assets, liabilities, non-controlling interests or items of consideration | $ (1) | ||||||||
Sunrise Oil Sands Partnership | |||||||||
Disclosure of detailed information about business combination [line items] | |||||||||
Agreement to purchase remaining ownership | 50% | ||||||||
Total Purchase Consideration | $ 1,034 | ||||||||
Fair value of accounts receivable and accrued revenues recognised as of acquisition date | 1,559 | ||||||||
Carrying value of investment in joint ventures recognised as of acquisition date | 960 | ||||||||
Acquisition-related costs for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination | 2 | ||||||||
Contingent consideration maximum payment | $ 600 | ||||||||
Non-cash revaluation gain, before tax | 599 | ||||||||
Non-cash revaluation gain, after tax | $ 457 |
Acquisitions - BP-Husky, Summar
Acquisitions - BP-Husky, Summary of Consideration (Details) - BP-Husky Refining LLC $ in Millions | Feb. 28, 2023 CAD ($) |
Disclosure of detailed information about business combination [line items] | |
Cash | $ 69 |
Accounts Payable and Accrued Liabilities | 3 |
Inventories | 387 |
Property, Plant and Equipment | 770 |
Right-of-Use Assets | 33 |
Other Assets | 10 |
Accounts Payable and Accrued Liabilities | (139) |
Lease Liabilities | (33) |
Decommissioning Liabilities | (5) |
Other Liabilities | (73) |
Total Identifiable Net Assets | $ 1,022 |
Acquisitions - BP-Husky, Summ_2
Acquisitions - BP-Husky, Summary of Goodwill (Details) $ in Millions, $ in Millions | Dec. 31, 2023 CAD ($) | Feb. 28, 2023 CAD ($) | Feb. 28, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) |
Disclosure of detailed information about business combination [line items] | |||||
Goodwill | $ 2,923 | $ 2,923 | $ 3,473 | ||
BP-Husky Refining LLC | |||||
Disclosure of detailed information about business combination [line items] | |||||
Total Purchase Consideration | $ 514 | $ 378 | |||
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo | 508 | ||||
Fair Value of Identifiable Net Assets | (1,022) | ||||
Goodwill | $ 0 |
Acquisitions - Sunrise Oil Sand
Acquisitions - Sunrise Oil Sands Partnership, Summary of Consideration (Details) - Sunrise Oil Sands Partnership $ in Millions | Aug. 31, 2022 CAD ($) |
Disclosure of detailed information about business combination [line items] | |
Cash, Net of Closing Adjustments | $ 394 |
Bay Du Nord | 40 |
Variable Payment | 600 |
Consideration transferred | $ 1,034 |
Acquisitions - Sunrise Oil Sa_2
Acquisitions - Sunrise Oil Sands Partnership, Assets Acquired and Liabilities Acquired (Details) - Sunrise Oil Sands Partnership $ in Millions | Aug. 31, 2022 CAD ($) |
Disclosure of detailed information about business combination [line items] | |
Cash | $ 9 |
Accounts Receivable and Accrued Revenues | 164 |
Inventories | 88 |
Property, Plant and Equipment | 3,218 |
Accounts Payable and Accrued Liabilities | (313) |
Income Tax Payable | (39) |
Decommissioning Liabilities | (48) |
Deferred Income Tax Liabilities | (486) |
Total Identifiable Net Assets | $ 2,593 |
Acquisitions - Sunrise Oil Sa_3
Acquisitions - Sunrise Oil Sands Partnership, Summary of Goodwill (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Aug. 31, 2022 | Dec. 31, 2021 |
Disclosure of detailed information about business combination [line items] | ||||
Goodwill | $ 2,923 | $ 2,923 | $ 3,473 | |
Sunrise Oil Sands Partnership | ||||
Disclosure of detailed information about business combination [line items] | ||||
Total Purchase Consideration | $ 1,034 | |||
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo | 1,559 | |||
Total Identifiable Net Assets | (2,593) | |||
Goodwill | $ 0 |
General and Administrative - Su
General and Administrative - Summary of General and Administrative Expenses (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
General And Administrative Expenses [Abstract] | ||
Salaries and Benefits | $ 249 | $ 204 |
Administrative and Other | 342 | 297 |
Stock-Based Compensation Expense (Recovery) (Note 32) | 97 | 373 |
Other Incentive Benefits Expense (Recovery) | 0 | (9) |
General and Administrative Expenses | $ 688 | $ 865 |
Finance Costs - Schedule of Fin
Finance Costs - Schedule of Finance Costs (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Finance Costs [Abstract] | ||
Interest Expense – Short-Term Borrowings and Long-Term Debt | $ 362 | $ 478 |
Net discount on redemption of long-term debt | (84) | (29) |
Interest Expense – Lease Liabilities (Note 20) | 161 | 163 |
Unwinding of Discount on Decommissioning Liabilities (Note 27) | 220 | 176 |
Other | 32 | 37 |
Total finance costs excluding capitalized interest | 691 | 825 |
Capitalized Interest | (20) | (5) |
Finance Costs | $ 671 | $ 820 |
Integration, Transaction and _3
Integration, Transaction and Other Costs (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of detailed information about business combination [line items] | ||
Integration costs | $ 46 | $ 95 |
Transaction Costs (Note 5) | 11 | 11 |
Other (2) | 28 | 0 |
Integration, transaction and other costs | 85 | 106 |
Husky Energy, Inc. | ||
Disclosure of detailed information about business combination [line items] | ||
Integration, transaction and other costs | 90 | |
Sunrise Oil Sands Partnership And Toledo CGU | ||
Disclosure of detailed information about business combination [line items] | ||
Integration, transaction and other costs | $ 46 | $ 5 |
Foreign Exchange (Gain) Loss,_3
Foreign Exchange (Gain) Loss, Net - Schedule of Foreign Exchange Gain Loss Net (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items] | ||
Unrealized Foreign Exchange (Gain) Loss | $ (210) | $ 365 |
Realized Foreign Exchange (Gain) Loss | 143 | (22) |
Total | (67) | 343 |
U.S. Dollar Debt Issued From Canada | ||
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items] | ||
Unrealized Foreign Exchange (Gain) Loss | (231) | 365 |
Other | ||
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items] | ||
Unrealized Foreign Exchange (Gain) Loss | $ 21 | $ 0 |
Divestitures (Details)
Divestitures (Details) $ in Millions | 12 Months Ended | ||||||
Sep. 13, 2022 CAD ($) gas_station | Jun. 08, 2022 CAD ($) | May 31, 2022 CAD ($) | Feb. 28, 2022 CAD ($) | Jan. 31, 2022 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | |
Disclosure of analysis of single amount of discontinued operations [line items] | |||||||
Proceeds from disposal of oil and gas assets | $ 0 | ||||||
Before-tax gain (loss) on disposal | $ 14 | $ 269 | |||||
Retail | |||||||
Disclosure of analysis of single amount of discontinued operations [line items] | |||||||
Before-tax gain (loss) on disposal | $ 74 | ||||||
After-tax gain (loss) on disposal | $ 56 | ||||||
Number of stores sold | gas_station | 337 | ||||||
Consideration for sale of assets held for sale | $ 404 | ||||||
Tucker | |||||||
Disclosure of analysis of single amount of discontinued operations [line items] | |||||||
Proceeds from disposal of oil and gas assets | $ 730 | ||||||
Before-tax gain (loss) on disposal | 165 | ||||||
After-tax gain (loss) on disposal | $ 126 | ||||||
Wembley | |||||||
Disclosure of analysis of single amount of discontinued operations [line items] | |||||||
Proceeds from disposal of oil and gas assets | $ 221 | ||||||
Before-tax gain (loss) on disposal | 76 | ||||||
After-tax gain (loss) on disposal | $ 58 | ||||||
White Rose Field | |||||||
Disclosure of analysis of single amount of discontinued operations [line items] | |||||||
Before-tax gain (loss) on disposal | $ 62 | ||||||
After-tax gain (loss) on disposal | $ 47 | ||||||
Percentage of working interest acquired | 12.50% | ||||||
Payment to transfer working interest | $ 50 | ||||||
Headwater Exploration Inc. | |||||||
Disclosure of analysis of single amount of discontinued operations [line items] | |||||||
Proceeds from disposal of oil and gas assets | $ 110 | ||||||
Before-tax gain (loss) on disposal | 0 | ||||||
After-tax gain (loss) on disposal | $ 0 |
Impairment Charges and Revers_3
Impairment Charges and Reversals - Additional Information (Detail) $ in Millions | 2 Months Ended | 12 Months Ended | ||
Feb. 28, 2023 | Feb. 27, 2023 | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | |
BP-Husky Refining LLC | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Agreement to purchase remaining ownership | 50% | 50% | 50% | |
Discounted future cash flows | Minimum | Discount rate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.14 | |||
Upstream | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 0 | $ 0 | ||
Upstream | Discounted future cash flows | Discount rate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 0 | |||
Significant unobservable input, assets | 0.01 | |||
Upstream | Discounted future cash flows | Forward Price Estimate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 0 | |||
Significant unobservable input, assets | 0.05 | |||
Upstream | Discounted future cash flows | Minimum | Discount rate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.14 | |||
Upstream | Discounted future cash flows | Maximum | Discount rate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.15 | |||
Downstream | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 0 | |||
Downstream | Discounted future cash flows | Minimum | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.15 | |||
Downstream | Discounted future cash flows | Maximum | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.18 | |||
Downstream | Growth rate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.02 | |||
U.S. Refining | Downstream | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Recoverable amount of asset or cash-generating unit | $ 5,400 | |||
Sunrise | Discounted future cash flows | Discount rate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.01 | |||
Sunrise | Discounted future cash flows | Forward Price Estimate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Significant unobservable input, assets | 0.05 | |||
Sunrise | Upstream | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | 0 | |||
Sunrise | Upstream | Discount rate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 0 | $ 69 | ||
Significant unobservable input, assets | 0.01 | |||
Sunrise | Upstream | Forward Price Estimate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 0 | |||
Sunrise | Upstream | Discounted future cash flows | Forward Price Estimate | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 226 | |||
Significant unobservable input, assets | 0.05 | |||
Borger, Wood River, and Lima CGUs | Downstream | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
Impairment Reversals (Note 11) | $ 1,200 | |||
Superior and Toledo CGU | Downstream | ||||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||||
CGU Impairments | $ 1,500 |
Impairment Charges and Revers_4
Impairment Charges and Reversals - Forward Price Assumptions (Details) | Dec. 31, 2023 $ / bbl $ / Mcf $ / bbl | Dec. 31, 2022 $ / bbl $ / bbl $ / Mcf |
West Texas Intermediate | 1 Year | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 73.67 | 80.33 |
West Texas Intermediate | 2 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 74.98 | 78.50 |
West Texas Intermediate | 3 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 76.14 | 76.95 |
West Texas Intermediate | 4 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 77.66 | 77.61 |
West Texas Intermediate | 5 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 79.22 | 79.16 |
West Texas Intermediate | Thereafter | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Forward price, average annual increase | 2% | 2% |
Western Canada Select | 1 Year | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 76.74 | 76.54 |
Western Canada Select | 2 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 79.77 | 77.75 |
Western Canada Select | 3 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 81.12 | 77.55 |
Western Canada Select | 4 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 82.88 | 80.07 |
Western Canada Select | 5 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 85.04 | 81.89 |
Western Canada Select | Thereafter | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Forward price, average annual increase | 2% | 2% |
Edmonton C5+ | 1 Year | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 96.79 | 106.22 |
Edmonton C5+ | 2 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 98.75 | 101.35 |
Edmonton C5+ | 3 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 100.71 | 98.94 |
Edmonton C5+ | 4 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 102.72 | 100.19 |
Edmonton C5+ | 5 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | 104.78 | 101.74 |
Edmonton C5+ | Thereafter | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Forward price, average annual increase | 2% | 2% |
Alberta Energy Company Natural Gas | 1 Year | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | $ / Mcf | 2.20 | 4.23 |
Alberta Energy Company Natural Gas | 2 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | $ / Mcf | 3.37 | 4.40 |
Alberta Energy Company Natural Gas | 3 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | $ / Mcf | 4.05 | 4.21 |
Alberta Energy Company Natural Gas | 4 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | $ / Mcf | 4.13 | 4.27 |
Alberta Energy Company Natural Gas | 5 Years | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Long-term price assumptions used in current measurement of fair value less costs of disposal | $ / Mcf | 4.21 | 4.34 |
Alberta Energy Company Natural Gas | Thereafter | ||
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | ||
Forward price, average annual increase | 2% | 2% |
Impairment Charges and Revers_5
Impairment Charges and Reversals - Sensitivity (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 CAD ($) | |
Disclosure of impairment loss recognised or reversed for cash-generating unit [abstract] | |
Increase through change in discount rate, impairments | $ 69 |
Decrease through change in discount rate, impairments | (65) |
Five percent increase through change in forward price estimates, Impairments | (268) |
Five percent decrease through change in forward price estimates, Impairments | 268 |
One percent increase through change in discount rate, impairment reversal | (72) |
One percent decrease through change in discount rate, impairment reversal | 14 |
Five percent increase through change in forward price estimates, impairment reversal | 168 |
Five percent decrease through change in forward price estimates, impairment reversal | $ (342) |
Impairment Charges and Revers_6
Impairment Charges and Reversals - Crude Oil and Forward Crack Spreads (Details) | Dec. 31, 2022 $ / bbl |
West Texas Intermediate | 1 Year | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 80.33 |
West Texas Intermediate | 2 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 78.50 |
West Texas Intermediate | 3 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 76.95 |
West Texas Intermediate | 4 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 77.61 |
West Texas Intermediate | 5 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 79.16 |
WTI-WTS | 1 Year | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (0.56) |
WTI-WTS | 2 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (0.56) |
WTI-WTS | 3 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (0.56) |
WTI-WTS | 4 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (0.56) |
WTI-WTS | 5 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (0.56) |
WTI-WCS | 1 Year | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (23.32) |
WTI-WCS | 2 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (19.09) |
WTI-WCS | 3 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (17.42) |
WTI-WCS | 4 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (15.87) |
WTI-WCS | 5 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | (15.74) |
Chicago 3-2-1 Crack Spreads (WTI) | 1 Year | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 29.37 |
Chicago 3-2-1 Crack Spreads (WTI) | 2 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 24.10 |
Chicago 3-2-1 Crack Spreads (WTI) | 3 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 22.12 |
Chicago 3-2-1 Crack Spreads (WTI) | 4 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 21.70 |
Chicago 3-2-1 Crack Spreads (WTI) | 5 Years | |
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items] | |
Long-term Price Assumptions Used to Determine Future Cash Flows | 21.67 |
Other Income (Loss), Net (Detai
Other Income (Loss), Net (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of attribution of expenses by nature to their function [line items] | |||
Other income | $ 63 | $ 532 | |
Decommissioning Liabilities | $ 4,155 | 3,559 | $ 3,906 |
Site Rehabilitation Program | |||
Disclosure of attribution of expenses by nature to their function [line items] | |||
Decommissioning Liabilities | 65 | ||
2018 Atlantic Region Incident | |||
Disclosure of attribution of expenses by nature to their function [line items] | |||
Insurance proceeds | $ 328 |
Income Taxes - Provision for In
Income Taxes - Provision for Income Taxes (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Major Components Of Tax Expense Income [Line Items] | ||
Current Tax Expense (Recovery) | $ 1,181 | $ 1,639 |
Deferred Tax Expense (Recovery) | (250) | 642 |
Total Tax Expense (Recovery) | 931 | 2,281 |
Canada | ||
Major Components Of Tax Expense Income [Line Items] | ||
Current Tax Expense (Recovery) | 1,041 | 1,252 |
United States | ||
Major Components Of Tax Expense Income [Line Items] | ||
Current Tax Expense (Recovery) | (109) | 104 |
Asia Pacific | ||
Major Components Of Tax Expense Income [Line Items] | ||
Current Tax Expense (Recovery) | 224 | 262 |
Other International | ||
Major Components Of Tax Expense Income [Line Items] | ||
Current Tax Expense (Recovery) | $ 25 | $ 21 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of income taxes [line items] | ||
Deferred Tax Expense (Recovery) | $ (250) | $ 642 |
Deferred Income Taxes | 696 | 546 |
Deferred tax expense (income) recognised in profit or loss | 0 | 0 |
Amounts of tax pools available, including tax losses | 16,952 | 15,439 |
BP-Husky Refining LLC | ||
Disclosure of income taxes [line items] | ||
Deferred Tax Expense (Recovery) | 115 | |
Canadian Federal Non Capital Losses | ||
Disclosure of income taxes [line items] | ||
Amounts of tax pools available, including tax losses | 126 | 115 |
US Federal Net Operating Losses | ||
Disclosure of income taxes [line items] | ||
Amounts of tax pools available, including tax losses | 3,700 | 468 |
Canadian Net Capital Losses | ||
Disclosure of income taxes [line items] | ||
Amounts of tax pools available, including tax losses | 59 | 28 |
Net capital losses associated with unrealized foreign exchange losses | $ 141 | $ 504 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Income Taxes Calculated at Statutory Rate (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure Of Income Tax Expense Continuing Operations [Abstract] | ||
Earnings (Loss) Before Income Tax | $ 5,040 | $ 8,731 |
Canadian Statutory Rate (percent) | 23.70% | 23.70% |
Expected Income Tax Expense (Recovery) | $ 1,194 | $ 2,069 |
Effect on Taxes Resulting From: | ||
Statutory and Other Rate Differences | (38) | 17 |
Non-Taxable Capital (Gains) Losses | (15) | 84 |
Non-Recognition of Capital (Gains) Losses | (30) | 84 |
Adjustments Arising From Prior Year Tax Filings | (16) | 15 |
Recognition of U.S. Tax Basis | (115) | 0 |
Other | (49) | 12 |
Total Tax Expense (Recovery) | $ 931 | $ 2,281 |
Effective Tax Rate (percent) | 18.50% | 26.10% |
Income Taxes - Deferred Income
Income Taxes - Deferred Income Tax Liabilities and Deferred Income Tax Assets (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure of income taxes [line items] | |||
Deferred Income Tax Assets | $ (1,489) | $ (778) | $ (1,454) |
Deferred Income Tax Liabilities | 4,981 | 4,515 | 4,046 |
Net Deferred Income Tax Liability | 3,492 | 3,737 | $ 2,592 |
1 Year | |||
Disclosure of income taxes [line items] | |||
Deferred Income Tax Assets | (315) | (31) | |
Deferred Income Tax Liabilities | 138 | 55 | |
Later than one year | |||
Disclosure of income taxes [line items] | |||
Deferred Income Tax Assets | (1,174) | (747) | |
Deferred Income Tax Liabilities | $ 4,843 | $ 4,460 |
Income Taxes - Schedule of Move
Income Taxes - Schedule of Movement in Deferred Income Tax Liabilities and Assets (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred income tax assets, beginning balance | $ (778) | $ (1,454) |
Deferred income tax liabilities, beginning balance | 4,515 | 4,046 |
Net deferred income tax liabilities, beginning balance | 3,737 | 2,592 |
Deferred tax expense (income) recognised in profit or loss | 0 | 0 |
Deferred income tax assets, ending balance | (1,489) | (778) |
Deferred income tax liabilities, ending balance | 4,981 | 4,515 |
Net deferred income tax liabilities, ending balance | 3,492 | 3,737 |
Unused Tax Losses | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred income tax assets, beginning balance | (156) | (655) |
Deferred income tax assets, ending balance | (914) | (156) |
Deferred Income Tax Assets | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | (723) | 659 |
Charged (Credited) to Other Comprehensive Income | 12 | 17 |
Deferred Income Tax Assets | Unused Tax Losses | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | (777) | 490 |
Charged (Credited) to Other Comprehensive Income | 19 | 9 |
Deferred Income Tax Liabilities | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | 473 | (17) |
Deferred Income Tax Liabilities | Husky Energy, Inc. | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | 486 | |
Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | (7) | |
Net Deferred Income Tax Liabilities | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | (250) | 642 |
Charged (credited) to acquisitions | 486 | |
Charged (Credited) to Other Comprehensive Income | 5 | 17 |
Property, plant and equipment | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred income tax liabilities, beginning balance | 4,460 | 3,949 |
Deferred income tax liabilities, ending balance | 4,948 | 4,460 |
Property, plant and equipment | Deferred Income Tax Liabilities | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | 495 | 25 |
Property, plant and equipment | Deferred Income Tax Liabilities | Husky Energy, Inc. | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | 486 | |
Property, plant and equipment | Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | (7) | |
Risk Management | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred income tax assets, beginning balance | 0 | (11) |
Deferred income tax liabilities, beginning balance | 11 | 0 |
Deferred income tax assets, ending balance | 0 | 0 |
Deferred income tax liabilities, ending balance | 3 | 11 |
Risk Management | Deferred Income Tax Assets | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | 0 | 11 |
Charged (Credited) to Other Comprehensive Income | 0 | 0 |
Risk Management | Deferred Income Tax Liabilities | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | (8) | 11 |
Risk Management | Deferred Income Tax Liabilities | Husky Energy, Inc. | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | 0 | |
Risk Management | Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | 0 | |
Other | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred income tax assets, beginning balance | (622) | (788) |
Deferred income tax liabilities, beginning balance | 44 | 97 |
Deferred income tax assets, ending balance | (575) | (622) |
Deferred income tax liabilities, ending balance | 30 | 44 |
Other | Deferred Income Tax Assets | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | 54 | 158 |
Charged (Credited) to Other Comprehensive Income | (7) | 8 |
Other | Deferred Income Tax Liabilities | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Deferred tax expense (income) recognised in profit or loss | (14) | (53) |
Other | Deferred Income Tax Liabilities | Husky Energy, Inc. | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | $ 0 | |
Other | Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership | ||
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items] | ||
Charged (credited) to acquisitions | $ 0 |
Income Taxes - Schedule of Amou
Income Taxes - Schedule of Amounts of Tax Pools Available, Including Tax Losses (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Amounts of tax pools available, including tax losses | $ 16,952 | $ 15,439 |
Canada | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Amounts of tax pools available, including tax losses | 8,547 | 8,505 |
United States | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Amounts of tax pools available, including tax losses | 8,058 | 6,477 |
Asia Pacific | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Amounts of tax pools available, including tax losses | $ 347 | $ 457 |
Per Share Amounts - Schedule Re
Per Share Amounts - Schedule Representing Per Share Amounts (Detail) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Earnings per share [abstract] | ||
Net Earnings (Loss) | $ 4,109 | $ 6,450 |
Effect of Cumulative Dividends on Preferred Shares | (36) | (35) |
Net Earnings (Loss) – Basic and Diluted | $ 4,073 | $ 6,415 |
Basic – Weighted Average Number of Shares (in shares) | 1,895,487 | 1,951,262 |
Dilutive Effect of Warrants (in shares) | 22,223 | 44,845 |
Dilutive Effect of Net Settlement Rights (in shares) | 7,150 | 10,045 |
Diluted Effect of Cenovus Replacement Stock Options (in shares) | 580 | 0 |
Diluted - Weighted Average Number of Shares (in shares) | 1,925,440 | 2,006,152 |
Net Earnings (Loss) Per Share — Basic (CAD per share) | $ 2.15 | $ 3.29 |
Net Earnings (Loss) Per Share — Diluted (CAD per share) | $ 2.12 | $ 3.20 |
Per Share Amounts - Additional
Per Share Amounts - Additional Information (Detail) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||||
Feb. 14, 2024 | Jan. 02, 2024 | Jan. 03, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of non-adjusting events after reporting period [line items] | |||||
Total dividends paid on preferred shares | $ 36 | $ 35 | |||
Net settlement rights | |||||
Disclosure of non-adjusting events after reporting period [line items] | |||||
Instruments excluded from calculation, shares (in shares) | 1,500 | 52 | |||
Common Shares | |||||
Disclosure of non-adjusting events after reporting period [line items] | |||||
Instruments excluded from calculation, value | $ 0 | $ 52 | |||
Instruments excluded from calculation, shares (in shares) | 0 | 1,600 | |||
Preference shares | |||||
Disclosure of non-adjusting events after reporting period [line items] | |||||
Total dividends paid on preferred shares | $ 9 | $ 9 | $ 36 | $ 26 | |
Preference shares | Potential ordinary share transactions | |||||
Disclosure of non-adjusting events after reporting period [line items] | |||||
Dividends declared (in CAD per share) | $ 0.140 | ||||
Dividends declared | $ 9 |
Per Share Amounts - Common Shar
Per Share Amounts - Common Share Dividends (Details) - Common Shares - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Earnings per share [line items] | ||
Dividends paid (in CAD per share) | $ 0.525 | $ 0.350 |
Dividends paid on common shares | $ 990 | $ 682 |
Variable dividends declared (in CAD per share) | $ 0 | $ 0.114 |
Variable Dividends Paid on Common Shares | $ 0 | $ 219 |
Total common share dividends paid (in CAD per share) | $ 0.525 | $ 0.464 |
Total dividends paid on common shares | $ 990 | $ 901 |
Per Share Amounts - Preferred S
Per Share Amounts - Preferred Share Dividends (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Earnings per share [line items] | ||
Total Preferred Share Dividends Declared | $ 36 | $ 35 |
Series 1 First Preferred Shares | ||
Earnings per share [line items] | ||
Total Preferred Share Dividends Declared | 7 | 7 |
Series 2 First Preferred Shares | ||
Earnings per share [line items] | ||
Total Preferred Share Dividends Declared | 2 | 1 |
Series 3 First Preferred Shares | ||
Earnings per share [line items] | ||
Total Preferred Share Dividends Declared | 12 | 12 |
Series 5 First Preferred Shares | ||
Earnings per share [line items] | ||
Total Preferred Share Dividends Declared | 9 | 9 |
Series 7 First Preferred Shares | ||
Earnings per share [line items] | ||
Total Preferred Share Dividends Declared | $ 6 | $ 6 |
Cash and Cash Equivalents - Sch
Cash and Cash Equivalents - Schedule Representing Cash and Cash Equivalents (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Cash and cash equivalents [abstract] | |||
Cash | $ 2,109 | $ 3,195 | |
Short-Term Investments | 118 | 1,329 | |
Total Cash and Cash Equivalents | $ 2,227 | $ 4,524 | $ 2,873 |
Accounts Receivables and Accrue
Accounts Receivables and Accrued Revenues - Schedule of accounts receivables and accrued revenues (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Trade and other current receivables [abstract] | ||
Trade and Accruals | $ 2,722 | $ 2,962 |
Prepaids and Deposits | 242 | 402 |
Joint Operations Receivables | 49 | 51 |
Other | 22 | 58 |
Accounts Receivable and Accrued Revenues | $ 3,035 | $ 3,473 |
Inventories - Schedule of Inven
Inventories - Schedule of Inventories (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of inventories [line items] | ||
Total Product | $ 3,604 | $ 4,009 |
Parts and supplies | 426 | 303 |
Current inventories | 4,030 | 4,312 |
Crude Oil | ||
Disclosure of inventories [line items] | ||
Total Product | 2,084 | 2,424 |
Diluent | ||
Disclosure of inventories [line items] | ||
Total Product | 379 | 366 |
Natural Gas and NGLs | ||
Disclosure of inventories [line items] | ||
Total Product | 68 | 50 |
Refined Products | ||
Disclosure of inventories [line items] | ||
Total Product | $ 1,073 | $ 1,169 |
Inventories - Additional Inform
Inventories - Additional Information (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of inventories [line items] | ||
Cost of inventories recognized as expense during period | $ 39,100 | $ 49,100 |
Refined Products | ||
Disclosure of inventories [line items] | ||
Inventory write-downs | 86 | |
Crude Oil | ||
Disclosure of inventories [line items] | ||
Inventory write-downs | $ 3 |
Assets Held for Sale (Details)
Assets Held for Sale (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Sep. 13, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of operating segments [line items] | ||||
Proceeds from disposal of oil and gas assets | $ 0 | |||
Property, Plant and Equipment, Net | 37,250 | $ 36,499 | ||
Right-of-Use Assets, Net | 1,680 | 1,845 | ||
Goodwill | 2,923 | 2,923 | $ 3,473 | |
Lease liabilities | (2,658) | (2,836) | (2,957) | |
Decommissioning Liabilities | $ (4,155) | $ (3,559) | $ (3,906) | |
Retail | ||||
Disclosure of operating segments [line items] | ||||
Consideration for sale of assets held for sale | $ 404 |
Exploration and Evaluation As_3
Exploration and Evaluation Assets, Net - Summary of Exploration and Valuation Assets, Net (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Beginning Balance | $ 685 | |
Write-downs | (42) | $ (101) |
Ending Balance | 738 | 685 |
Conventional | ||
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Beginning Balance | 6 | |
Ending Balance | 0 | 6 |
Oil Sands | ||
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Beginning Balance | 674 | |
Ending Balance | 729 | 674 |
Exploration and evaluation costs previously capitalized, written off | 14 | |
Offshore | ||
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Beginning Balance | 5 | |
Ending Balance | 9 | 5 |
Exploration and evaluation costs previously capitalized, written off | 9 | |
E&E Asset | ||
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Beginning Balance | 685 | 720 |
Additions | 84 | 37 |
Transfer to PP&E (Note 19) | (60) | |
Write-downs | (29) | (64) |
Change in Decommissioning Liabilities | 28 | (12) |
Exchange Rate Movements and Other | (1) | 4 |
Acquisition | 31 | |
Ending Balance | 738 | 685 |
E&E Asset | Conventional | ||
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Exploration and evaluation costs previously capitalized, written off | $ 6 | |
E&E Asset | Oil Sands | ||
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Exploration and evaluation costs previously capitalized, written off | 2 | |
E&E Asset | Offshore | ||
Disclosure Of Exploration And Evaluation Assets [Line Items] | ||
Exploration and evaluation costs previously capitalized, written off | $ 62 |
Property, Plant and Equipment_3
Property, Plant and Equipment, Net - Summary of Property, Plant and Equipment (Detail) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Feb. 28, 2023 | Aug. 31, 2022 | |
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | $ 36,499 | |||
Ending Balance | 37,250 | $ 36,499 | ||
Property, Plant and Equipment, Net | 37,250 | 36,499 | ||
Offshore | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 2,549 | |||
Ending Balance | 2,798 | 2,549 | ||
Property, Plant and Equipment, Net | 2,798 | 2,549 | ||
Write-downs (reversals of write-downs) of property, plant and equipment | 20 | 26 | ||
Canadian Refining | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 2,466 | |||
Ending Balance | 2,469 | 2,466 | ||
Property, Plant and Equipment, Net | 2,469 | 2,466 | ||
Write-downs (reversals of write-downs) of property, plant and equipment | 12 | 25 | ||
U.S. Refining | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 4,482 | |||
Ending Balance | 5,014 | 4,482 | ||
Property, Plant and Equipment, Net | 5,014 | 4,482 | ||
Write-downs (reversals of write-downs) of property, plant and equipment | 38 | |||
Sunrise Oil Sands Partnership | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Property, Plant and Equipment, Net | $ 454 | |||
BP-Husky Refining LLC | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Property, Plant and Equipment, Net | $ 334 | |||
COST | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 57,739 | 50,901 | ||
Acquisition | 781 | 3,230 | ||
Additions | 4,214 | 3,671 | ||
Transfer from E&E (Note 18) | 60 | |||
Change in Decommissioning Liabilities | 581 | (253) | ||
Divestitures | (667) | (557) | ||
Exchange Rate Movements and Other | (333) | 747 | ||
Ending Balance | 62,375 | 57,739 | ||
Property, Plant and Equipment, Net | 62,375 | 57,739 | ||
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | (21,240) | (16,676) | ||
Divestitures | 319 | 84 | ||
Exchange Rate Movements and Other | (147) | 315 | ||
Depreciation, Depletion and Amortization (4) | 4,351 | 4,067 | ||
Impairment Charges (Note 11) | 1,499 | |||
Impairment Reversals (Note 11) | (1,233) | |||
Ending Balance | (25,125) | (21,240) | ||
Property, Plant and Equipment, Net | (25,125) | (21,240) | ||
Crude Oil and Natural Gas Properties | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 29,226 | |||
Ending Balance | 29,450 | 29,226 | ||
Property, Plant and Equipment, Net | 29,450 | 29,226 | ||
Crude Oil and Natural Gas Properties | COST | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 43,528 | 38,443 | ||
Acquisition | 11 | 3,230 | ||
Additions | 3,392 | 2,409 | ||
Transfer from E&E (Note 18) | 60 | |||
Change in Decommissioning Liabilities | 542 | (186) | ||
Divestitures | (17) | (557) | ||
Exchange Rate Movements and Other | (91) | 189 | ||
Ending Balance | 47,425 | 43,528 | ||
Property, Plant and Equipment, Net | 47,425 | 43,528 | ||
Crude Oil and Natural Gas Properties | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | (14,302) | (10,912) | ||
Divestitures | 8 | 84 | ||
Exchange Rate Movements and Other | (11) | 13 | ||
Depreciation, Depletion and Amortization (4) | 3,692 | 3,461 | ||
Impairment Charges (Note 11) | 0 | |||
Impairment Reversals (Note 11) | 0 | |||
Ending Balance | (17,975) | (14,302) | ||
Property, Plant and Equipment, Net | (17,975) | (14,302) | ||
Processing, Transportation and Storage Assets | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 148 | |||
Ending Balance | 143 | 148 | ||
Property, Plant and Equipment, Net | 143 | 148 | ||
Processing, Transportation and Storage Assets | COST | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 254 | 228 | ||
Acquisition | 0 | 0 | ||
Additions | 14 | 11 | ||
Transfer from E&E (Note 18) | 0 | |||
Change in Decommissioning Liabilities | 0 | (6) | ||
Divestitures | 0 | 0 | ||
Exchange Rate Movements and Other | 4 | 21 | ||
Ending Balance | 272 | 254 | ||
Property, Plant and Equipment, Net | 272 | 254 | ||
Processing, Transportation and Storage Assets | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | (106) | (53) | ||
Divestitures | 0 | 0 | ||
Exchange Rate Movements and Other | 4 | 16 | ||
Depreciation, Depletion and Amortization (4) | 19 | 37 | ||
Impairment Charges (Note 11) | 0 | |||
Impairment Reversals (Note 11) | 0 | |||
Ending Balance | (129) | (106) | ||
Property, Plant and Equipment, Net | (129) | (106) | ||
Refining Assets | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 6,585 | |||
Ending Balance | 7,103 | 6,585 | ||
Property, Plant and Equipment, Net | 7,103 | 6,585 | ||
Refining Assets | COST | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 12,132 | 10,495 | ||
Acquisition | 770 | 0 | ||
Additions | 719 | 1,143 | ||
Transfer from E&E (Note 18) | 0 | |||
Change in Decommissioning Liabilities | 21 | (29) | ||
Divestitures | (633) | 0 | ||
Exchange Rate Movements and Other | (239) | 523 | ||
Ending Balance | 12,770 | 12,132 | ||
Property, Plant and Equipment, Net | 12,770 | 12,132 | ||
Refining Assets | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | (5,547) | (4,572) | ||
Divestitures | 299 | 0 | ||
Exchange Rate Movements and Other | (135) | 243 | ||
Depreciation, Depletion and Amortization (4) | 554 | 466 | ||
Impairment Charges (Note 11) | 1,499 | |||
Impairment Reversals (Note 11) | (1,233) | |||
Ending Balance | (5,667) | (5,547) | ||
Property, Plant and Equipment, Net | (5,667) | (5,547) | ||
Retail and other | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 540 | |||
Ending Balance | 554 | 540 | ||
Property, Plant and Equipment, Net | 554 | 540 | ||
Retail and other | COST | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | 1,825 | 1,735 | ||
Acquisition | 0 | 0 | ||
Additions | 89 | 108 | ||
Transfer from E&E (Note 18) | 0 | |||
Change in Decommissioning Liabilities | 18 | (32) | ||
Divestitures | (17) | 0 | ||
Exchange Rate Movements and Other | (7) | 14 | ||
Ending Balance | 1,908 | 1,825 | ||
Property, Plant and Equipment, Net | 1,908 | 1,825 | ||
Retail and other | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | ||||
Disclosure of detailed information about property, plant and equipment [line items] | ||||
Beginning Balance | (1,285) | (1,139) | ||
Divestitures | 12 | 0 | ||
Exchange Rate Movements and Other | (5) | 43 | ||
Depreciation, Depletion and Amortization (4) | 86 | 103 | ||
Impairment Charges (Note 11) | 0 | |||
Impairment Reversals (Note 11) | 0 | |||
Ending Balance | (1,354) | (1,285) | ||
Property, Plant and Equipment, Net | $ (1,354) | $ (1,285) |
Property, Plant and Equipment_4
Property, Plant and Equipment, Net - Assets Under Construction (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of detailed information about property, plant and equipment [line items] | ||
Property plant and equipment temporarily idle | $ 2,750 | $ 2,279 |
Crude Oil and Natural Gas Properties | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Property plant and equipment temporarily idle | 2,507 | 2,142 |
Refining equipment | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Property plant and equipment temporarily idle | $ 243 | $ 137 |
Right of Use Assets, Net - Summ
Right of Use Assets, Net - Summary of Right of Use Assets, Net (Detail) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Feb. 28, 2023 | |
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | $ 1,845 | ||
Balance at end of period | 1,680 | $ 1,845 | |
Right-of-Use Assets, Net | 1,680 | 1,845 | |
BP-Husky Refining LLC | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Right-of-Use Assets, Net | $ 7 | ||
COST | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 2,687 | 2,656 | |
Additions | 57 | 25 | |
Exchange Rate Movements and Other | 25 | 6 | |
Acquisitions (Note 5) (3) | 33 | ||
Divestitures | 19 | ||
Balance at end of period | 2,783 | 2,687 | |
Right-of-Use Assets, Net | 2,783 | 2,687 | |
ACCUMULATED DEPRECIATION | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 842 | 646 | |
Exchange Rate Movements and Other | (20) | (101) | |
Divestitures | 12 | ||
Depreciation | 293 | 297 | |
Balance at end of period | 1,103 | 842 | |
Real Estate | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 472 | ||
Balance at end of period | 432 | 472 | |
Right-of-Use Assets, Net | 432 | 472 | |
Real Estate | COST | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 599 | 592 | |
Additions | 1 | 0 | |
Exchange Rate Movements and Other | (13) | 7 | |
Acquisitions (Note 5) (3) | 1 | ||
Divestitures | 0 | ||
Balance at end of period | 588 | 599 | |
Right-of-Use Assets, Net | 588 | 599 | |
Real Estate | ACCUMULATED DEPRECIATION | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 127 | 92 | |
Exchange Rate Movements and Other | (7) | (1) | |
Divestitures | 0 | ||
Depreciation | 36 | 36 | |
Balance at end of period | 156 | 127 | |
Transportation And Storage Assets | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 1,195 | ||
Balance at end of period | 1,101 | 1,195 | |
Right-of-Use Assets, Net | 1,101 | 1,195 | |
Transportation And Storage Assets | COST | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 1,840 | 1,841 | |
Additions | 56 | 22 | |
Exchange Rate Movements and Other | 44 | (23) | |
Acquisitions (Note 5) (3) | 24 | ||
Divestitures | 0 | ||
Balance at end of period | 1,964 | 1,840 | |
Right-of-Use Assets, Net | 1,964 | 1,840 | |
Transportation And Storage Assets | ACCUMULATED DEPRECIATION | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 645 | 520 | |
Exchange Rate Movements and Other | (5) | (101) | |
Divestitures | 0 | ||
Depreciation | 223 | 226 | |
Balance at end of period | 863 | 645 | |
Refining Assets | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 116 | ||
Balance at end of period | 96 | 116 | |
Right-of-Use Assets, Net | 96 | 116 | |
Refining Assets | COST | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 174 | 161 | |
Additions | 0 | 1 | |
Exchange Rate Movements and Other | (2) | 12 | |
Acquisitions (Note 5) (3) | 8 | ||
Divestitures | 19 | ||
Balance at end of period | 161 | 174 | |
Right-of-Use Assets, Net | 161 | 174 | |
Refining Assets | ACCUMULATED DEPRECIATION | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 58 | 33 | |
Exchange Rate Movements and Other | (3) | 4 | |
Divestitures | 12 | ||
Depreciation | 22 | 21 | |
Balance at end of period | 65 | 58 | |
Other Assets | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 62 | ||
Balance at end of period | 51 | 62 | |
Right-of-Use Assets, Net | 51 | 62 | |
Other Assets | COST | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 74 | 62 | |
Additions | 0 | 2 | |
Exchange Rate Movements and Other | (4) | 10 | |
Acquisitions (Note 5) (3) | 0 | ||
Divestitures | 0 | ||
Balance at end of period | 70 | 74 | |
Right-of-Use Assets, Net | 70 | 74 | |
Other Assets | ACCUMULATED DEPRECIATION | |||
Disclosure of quantitative information about right-of-use assets [line items] | |||
Balance at beginning of period | 12 | 1 | |
Exchange Rate Movements and Other | (5) | (3) | |
Divestitures | 0 | ||
Depreciation | 12 | 14 | |
Balance at end of period | $ 19 | $ 12 |
Joint Arrangements - Joint Oper
Joint Arrangements - Joint Operations (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of joint operations [line items] | ||
Net Earnings (Loss) | $ 4,109 | $ 6,450 |
Husky-CNOOC Madura Ltd. | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint venture | 40% | |
Share of income from equity-accounted affiliate | $ 57 | 23 |
Investments in joint ventures accounted for using equity method | 344 | 365 |
Distributions received | 93 | 42 |
Joint venture, contributions | 35 | 54 |
Net Earnings (Loss) | $ 70 | 33 |
Husky Midstream Limited Partnership | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint venture | 35% | |
Investments in joint ventures accounted for using equity method | $ 0 | 0 |
Distributions received | 56 | 23 |
Joint venture, contributions | 62 | 31 |
Net Earnings (Loss) | 231 | 190 |
Unrecognised share of pre-tax net losses of joint ventures | (1) | (23) |
Unrecognised share of losses of joint ventures, OCI | (2) | 8 |
Unrecognised share of losses of joint ventures | $ 31 | $ 28 |
WRB Refining LP | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint operation | 50% | |
WRB Refining LP | Phillips 66 | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint operation | 50% | |
BP-Husky Refining LLC | ||
Disclosure of joint operations [line items] | ||
Proportion of ownership interest in joint operation | 50% |
Joint Arrangements - Husky - CN
Joint Arrangements - Husky - CNOOC Madura Ltd (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Results of Operations | ||||
Revenue | $ 52,204 | $ 66,897 | ||
Expenses | [1] | 6,352 | 5,816 | |
Net Earnings (Loss) | 4,109 | 6,450 | ||
Balance Sheets | ||||
Total Current Assets | 9,708 | 12,430 | ||
Current Liabilities | 6,210 | 8,021 | ||
Cash and Cash Equivalents | 2,227 | 4,524 | $ 2,873 | |
Husky-CNOOC Madura Ltd. | ||||
Results of Operations | ||||
Revenue | 615 | 383 | ||
Expenses | 545 | 350 | ||
Net Earnings (Loss) | 70 | 33 | ||
Balance Sheets | ||||
Total Current Assets | 334 | 247 | ||
Non-Current Assets | 1,751 | 1,926 | ||
Current Liabilities | 140 | 160 | ||
Non-Current Liabilities | 1,188 | 1,293 | ||
Net Assets | 757 | 720 | ||
Cash and Cash Equivalents | $ 111 | $ 64 | ||
[1] Comparative periods reflect certain revisions. See Note 39. |
Other Assets - Schedule of Othe
Other Assets - Schedule of Other Assets (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | |
Disclosure of classes of share capital [Line Items] | ||
Private Equity Investments (Note 35) | $ 55 | $ 131 |
Precious Metals | 86 | 76 |
Net Investment in Finance Leases | 62 | 61 |
Long-Term Receivables and Prepaids | 120 | 50 |
Intangible assets | 19 | 0 |
Other assets | 342 | $ 318 |
Oil Sands | ||
Disclosure of classes of share capital [Line Items] | ||
Disposals, intangible assets other than goodwill | $ 49 |
Goodwill - Activity (Details)
Goodwill - Activity (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Goodwill [Abstract] | ||
Goodwill at beginning of period | $ 2,923 | $ 3,473 |
Goodwill Disposed (Note 5) | 0 | (550) |
Goodwill at end of period | $ 2,923 | $ 2,923 |
Goodwill - Allocation (Details)
Goodwill - Allocation (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure of reconciliation of changes in goodwill [line items] | |||
Goodwill | $ 2,923 | $ 2,923 | $ 3,473 |
Primrose (Foster Creek) | |||
Disclosure of reconciliation of changes in goodwill [line items] | |||
Goodwill | 1,171 | 1,171 | |
Christina Lake | |||
Disclosure of reconciliation of changes in goodwill [line items] | |||
Goodwill | 1,101 | 1,101 | |
Lloydminster Thermal | |||
Disclosure of reconciliation of changes in goodwill [line items] | |||
Goodwill | $ 651 | $ 651 |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Liabilities - Schedule of Accounts Payable and Accrued Liabilities (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Trade and other current payables [abstract] | ||
Accruals | $ 3,931 | $ 3,412 |
Trade | 1,075 | 2,331 |
Employee Long-Term Incentives | 284 | 162 |
Interest | 69 | 80 |
Joint Operations Payable | 75 | 66 |
Risk Management | 19 | 39 |
Provisions for Onerous and Unfavourable Contracts | 18 | 25 |
Other | 9 | 9 |
Accounts payable and accrued liabilities | $ 5,480 | $ 6,124 |
Debt and Capital Structure - Sc
Debt and Capital Structure - Schedule of Short-Term Borrowings (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of detailed information about borrowings [line items] | ||
Short-Term Borrowings | $ 179 | $ 115 |
Uncommitted Demand Facilities | ||
Disclosure of detailed information about borrowings [line items] | ||
Short-Term Borrowings | 0 | 0 |
WRB Refining LP | ||
Disclosure of detailed information about borrowings [line items] | ||
Short-Term Borrowings | $ 179 | $ 115 |
Debt and Capital Structure - Ad
Debt and Capital Structure - Additional Information (Detail) $ in Millions, $ in Millions | 8 Months Ended | 12 Months Ended | |||
Aug. 30, 2022 | Dec. 31, 2023 CAD ($) $ / bbl | Dec. 31, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 USD ($) | |
Disclosure of detailed information about borrowings [line items] | |||||
Weighted average interest rate | 4.70% | 4.70% | |||
Outstanding letters of credit | $ 364 | $ 490 | |||
Current borrowings | $ 179 | 115 | |||
Maximum debt to capitalization ratio | 65% | 65% | |||
Target Net Debt to Adjusted EBITDA Ratio | 1 | ||||
Target net debt | $ 4,000 | ||||
Average crude oil price | $ / bbl | 45 | ||||
Uncommitted Demand Facilities | Top of range | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Amount of undrawn facilities for general purposes | $ 1,100 | ||||
WRB Refining LP | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Current borrowings | $ 179 | 115 | |||
Proportion of ownership interest in joint operation | 50% | ||||
Undrawn borrowing facilities | $ 270 | ||||
WRB Refining LP | Cenovus Energy Inc | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Undrawn borrowing facilities | $ 179 | 135 | 115 | $ 85 | |
Sunrise Oil Sands Partnership | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Proportion of ownership interest in joint operation | 50% | ||||
Maximum | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Committed credit facilities, maximum borrowing capacity | 1,700 | 1,900 | |||
Maximum | Top of range | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Amount of undrawn facilities for general purposes | 1,400 | ||||
Maximum | WRB Refining LP | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Committed credit facilities, maximum borrowing capacity | $ 450 | ||||
Maximum | WRB Refining LP | Cenovus Energy Inc | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Committed credit facilities, maximum borrowing capacity | $ 225 | ||||
Committed Credit Facility | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Undrawn borrowing facilities | 0 | 0 | |||
Uncommitted Demand Facilities | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Current borrowings | 0 | $ 0 | |||
Committed Credit Facilities, Maturing August 18, 2025 | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Committed credit facilities, maximum borrowing capacity | 1,800 | ||||
Committed Credit Facilities, Maturing August 18, 2026 | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Committed credit facilities, maximum borrowing capacity | $ 3,700 |
Debt and Capital Structure - _2
Debt and Capital Structure - Schedule of Long-Term Debt (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of detailed information about borrowings [line items] | ||
Debt Premiums (Discounts), Net, and Transaction Costs | $ 80 | $ 154 |
Total Debt | 7,108 | 8,691 |
Long-Term Debt | ||
Disclosure of detailed information about borrowings [line items] | ||
Total Debt Principal, (CAD equivalent) | 7,028 | 8,537 |
Long-Term Debt | Revolving Term Debt | ||
Disclosure of detailed information about borrowings [line items] | ||
Committed credit facility | 0 | 0 |
Long-Term Debt | U.S. Dollar Denominated Unsecured Notes | ||
Disclosure of detailed information about borrowings [line items] | ||
Total Debt Principal, (CAD equivalent) | 5,028 | 6,537 |
Long-Term Debt | Canadian Dollar Unsecured Notes | ||
Disclosure of detailed information about borrowings [line items] | ||
Total Debt Principal, (CAD equivalent) | $ 2,000 | $ 2,000 |
Debt and Capital Structure - Un
Debt and Capital Structure - Unsecured Notes (Details) - Long-Term Debt $ in Millions, $ in Millions | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2022 CAD ($) |
U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Total debt principal | $ 1,000 | $ 2,600 | |
5.38% due July 15, 2025 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 5.38% | 5.38% | 5.38% |
4.25% due April 15, 2027 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 4.25% | 4.25% | 4.25% |
4.40% due April 15, 2029 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 4.40% | 4.40% | 4.40% |
5.25% due June 15, 2037 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 5.25% | 5.25% | 5.25% |
6.80% due September 15, 2037 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 6.80% | 6.80% | 6.80% |
6.75% due November 15, 2039 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 6.75% | 6.75% | 6.75% |
4.45% due September 15, 2042 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 4.45% | 4.45% | 4.45% |
5.20% due September 15, 2043 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 5.20% | 5.20% | 5.20% |
5.40% due June 15, 2047 | U.S. Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Long-term debt, interest rate | 5.40% | 5.40% | 5.40% |
3.55% due March 12, 2025 | Canadian Dollar Denominated Unsecured Notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Total debt principal | $ 750 |
Debt and Capital Structure - _3
Debt and Capital Structure - Schedule Remaining Principal Amounts of U.S. Dollar Denominated Unsecured Notes (Detail) - Long-Term Debt $ in Millions, $ in Millions | Dec. 31, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2022 CAD ($) |
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | $ 7,028 | $ 8,537 | ||
U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | $ 3,802 | 5,028 | $ 4,800 | 6,537 |
Canadian Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | $ 2,000 | $ 2,000 | ||
5.38% due July 15, 2025 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 5.38% | 5.38% | 5.38% | 5.38% |
Total debt principal | $ 133 | $ 176 | $ 133 | $ 181 |
4.25% due April 15, 2027 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 4.25% | 4.25% | 4.25% | 4.25% |
Total debt principal | $ 373 | $ 493 | $ 373 | $ 505 |
4.40% due April 15, 2029 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 4.40% | 4.40% | 4.40% | 4.40% |
Total debt principal | $ 183 | $ 241 | $ 240 | $ 324 |
2.65% due January 15, 2032 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 2.65% | 2.65% | 2.65% | 2.65% |
Total debt principal | $ 500 | $ 661 | $ 500 | $ 677 |
5.25% due June 15, 2037 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 5.25% | 5.25% | 5.25% | 5.25% |
Total debt principal | $ 333 | $ 441 | $ 583 | $ 790 |
6.80% due September 15, 2037 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 6.80% | 6.80% | 6.80% | 6.80% |
Total debt principal | $ 191 | $ 253 | $ 387 | $ 524 |
6.75% due November 15, 2039 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 6.75% | 6.75% | 6.75% | 6.75% |
Total debt principal | $ 652 | $ 862 | $ 935 | $ 1,267 |
4.45% due September 15, 2042 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 4.45% | 4.45% | 4.45% | 4.45% |
Total debt principal | $ 91 | $ 121 | $ 97 | $ 131 |
5.20% due September 15, 2043 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 5.20% | 5.20% | 5.20% | 5.20% |
Total debt principal | $ 27 | $ 36 | $ 29 | $ 39 |
5.40% due June 15, 2047 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 5.40% | 5.40% | 5.40% | 5.40% |
Total debt principal | $ 569 | $ 752 | $ 800 | $ 1,083 |
3.75% due February 15, 2052 | U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 3.75% | 3.75% | 3.75% | 3.75% |
Total debt principal | $ 750 | $ 992 | $ 750 | $ 1,016 |
3.60% due March 10, 2027 | Canadian Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 3.60% | 3.60% | 3.60% | 3.60% |
Total debt principal | $ 750 | $ 750 | ||
3.50% due February 7, 2028 | Canadian Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Long-term debt, interest rate | 3.50% | 3.50% | 3.50% | 3.50% |
Total debt principal | $ 1,250 | $ 1,250 |
Debt and Capital Structure - Ma
Debt and Capital Structure - Mandatory Debt Payments (Details) - Long-Term Debt $ in Millions, $ in Millions | Dec. 31, 2023 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 USD ($) |
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | $ 7,028 | $ 8,537 | ||
Total Debt Principal, (CAD equivalent) | 7,028 | 8,537 | ||
2024 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 0 | |||
2025 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 176 | |||
2026 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 0 | |||
2027 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 1,243 | |||
2028 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 1,250 | |||
Thereafter | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 4,359 | |||
U.S. Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | 5,028 | $ 3,802 | 6,537 | $ 4,800 |
Total Debt Principal, (CAD equivalent) | 5,028 | 6,537 | ||
U.S. Dollar Denominated Unsecured Notes | 2024 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | 0 | |||
Total Debt Principal, (CAD equivalent) | 0 | |||
U.S. Dollar Denominated Unsecured Notes | 2025 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | 133 | |||
Total Debt Principal, (CAD equivalent) | 176 | |||
U.S. Dollar Denominated Unsecured Notes | 2026 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | 0 | |||
Total Debt Principal, (CAD equivalent) | 0 | |||
U.S. Dollar Denominated Unsecured Notes | 2027 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | 373 | |||
Total Debt Principal, (CAD equivalent) | 493 | |||
U.S. Dollar Denominated Unsecured Notes | 2028 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | 0 | |||
Total Debt Principal, (CAD equivalent) | 0 | |||
U.S. Dollar Denominated Unsecured Notes | Thereafter | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | $ 3,296 | |||
Total Debt Principal, (CAD equivalent) | 4,359 | |||
Canadian Dollar Denominated Unsecured Notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total debt principal | 2,000 | $ 2,000 | ||
Total Debt Principal, (CAD equivalent) | 2,000 | |||
Canadian Dollar Denominated Unsecured Notes | 2024 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 0 | |||
Canadian Dollar Denominated Unsecured Notes | 2025 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 0 | |||
Canadian Dollar Denominated Unsecured Notes | 2026 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 0 | |||
Canadian Dollar Denominated Unsecured Notes | 2027 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 750 | |||
Canadian Dollar Denominated Unsecured Notes | 2028 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | 1,250 | |||
Canadian Dollar Denominated Unsecured Notes | Thereafter | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Total Debt Principal, (CAD equivalent) | $ 0 |
Debt and Capital Structure - Su
Debt and Capital Structure - Summary of Net Debt to Adjusted EBITDA (Detail) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of objectives, policies and processes for managing capital [line items] | |||
Short-Term Borrowings | $ 179 | $ 115 | |
Current Portion of Long-Term Debt | 0 | 0 | |
Long-Term Portion of Long-Term Debt | 7,108 | 8,691 | |
Total Debt | 7,108 | 8,691 | |
Less: Cash and Cash Equivalents | (2,227) | (4,524) | $ (2,873) |
Net Debt | 5,060 | 4,282 | |
Net Earnings (Loss) | 4,109 | 6,450 | |
Add (Deduct): | |||
Interest Income | (133) | (81) | |
Foreign Exchange (Gain) Loss, Net | (67) | 343 | |
Revaluation (Gain) Loss | (34) | 549 | |
Re-measurement of Contingent Payment | (59) | (162) | |
Other (Income) Loss, Net | $ (63) | $ (532) | |
Net Debt to Adjusted EBITDA | 50% | 30% | |
Rolling Twelve Month Basis | |||
Disclosure of objectives, policies and processes for managing capital [line items] | |||
Short-Term Borrowings | $ 179 | $ 115 | |
Long-Term Portion of Long-Term Debt | 7,108 | 8,691 | |
Total Debt | 7,287 | 8,806 | |
Less: Cash and Cash Equivalents | (2,227) | (4,524) | |
Net Debt | 5,060 | 4,282 | |
Net Earnings (Loss) | 4,109 | 6,450 | |
Add (Deduct): | |||
Finance Costs | 671 | 820 | |
Interest Income | (133) | (81) | |
Income Tax Expense (Recovery) | 931 | 2,281 | |
Depreciation, Depletion and Amortization | 4,644 | 4,679 | |
Exploration and Evaluation Asset Write-downs | 29 | 64 | |
(Income) Loss From Equity-Accounted Affiliates | (51) | (15) | |
Unrealized (Gain) Loss on Risk Management | 52 | (126) | |
Foreign Exchange (Gain) Loss, Net | (67) | 343 | |
Revaluation (Gain) Loss | 34 | (549) | |
Re-measurement of Contingent Payment | 59 | 162 | |
(Gain) Loss on Divestiture of Assets | (14) | (269) | |
Other (Income) Loss, Net | (63) | (532) | |
Adjusted EBITDA | $ 10,201 | $ 13,227 |
Debt and Capital Structure - _4
Debt and Capital Structure - Summary of Net Debt to Adjusted Funds Flow (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Borrowings [abstract] | ||
Net Debt | $ 5,060 | $ 4,282 |
Cash From (Used in) Operating Activities | 7,388 | 11,403 |
Settlement of Decommissioning Liabilities | (222) | (150) |
Net Change in Non-Cash Working Capital | (1,193) | 575 |
Adjusted Funds Flow | $ 8,803 | $ 10,978 |
Net Debt to Adjusted Funds Flow (times) | 60% | 40% |
Debt and Capital Structure - _5
Debt and Capital Structure - Summary of Net Debt to Capitalization (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Borrowings [abstract] | |||
Net Debt | $ 5,060 | $ 4,282 | |
Shareholders’ Equity | 28,698 | 27,576 | $ 23,596 |
Capitalization | $ 33,758 | $ 31,858 | |
Net Debt to Capitalization (percent) | 15% | 13% |
Contingent Payments - Additiona
Contingent Payments - Additional Information (Detail) | 1 Months Ended | 12 Months Ended | |||
May 17, 2022 | Jul. 31, 2022 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Aug. 31, 2022 CAD ($) $ / bbl | |
FCCL Partnership | |||||
Disclosure of contingent liabilities in business combination [line items] | |||||
Proportion of ownership interest in joint operation | 50% | ||||
Sunrise Oil Sands Partnership | |||||
Disclosure of contingent liabilities in business combination [line items] | |||||
Contingent consideration maximum payment | $ 600,000,000 | ||||
Contingent consideration, quarterly payment | 2,800,000 | ||||
Maximum payment over remaining term | $ 194,000,000 | ||||
Contingent payable | $ 314,000,000 | $ 92,000,000 | |||
Sunrise Oil Sands Partnership | Bottom of range | |||||
Disclosure of contingent liabilities in business combination [line items] | |||||
Contingent consideration, price per barrel (in dollars per share) | $ / bbl | 52 | ||||
Sunrise Oil Sands Partnership | Top of range | |||||
Disclosure of contingent liabilities in business combination [line items] | |||||
Contingent consideration, price per barrel (in dollars per share) | 53 | ||||
Sunrise Oil Sands Partnership | Major business combination | |||||
Disclosure of contingent liabilities in business combination [line items] | |||||
Contingent payable | $ 299,000,000 | ||||
Conoco Phillips Company and certain of its subsidiaries | |||||
Disclosure of contingent liabilities in business combination [line items] | |||||
Contingent payable | $ 177,000,000 |
Contingent Payments - Summary o
Contingent Payments - Summary of Contingent Payment (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of contingent liabilities in business combination [line items] | ||
Less: Current Portion | $ 164 | $ 263 |
Long-Term Portion | 0 | 156 |
Sunrise Oil Sands Partnership | ||
Disclosure of contingent liabilities in business combination [line items] | ||
Contingent Payments, Beginning of Year | 419 | 0 |
Initial Recognition | 0 | 600 |
Liabilities Settled or Payable | (314) | (92) |
Re-measurement | 59 | (89) |
Contingent Payments, End of Year | 164 | 419 |
Less: Current Portion | 164 | 263 |
Long-Term Portion | 0 | 156 |
FCCL Partnership | ||
Disclosure of contingent liabilities in business combination [line items] | ||
Contingent Payments, Beginning of Year | $ 0 | 236 |
Liabilities Settled or Payable | (487) | |
Re-measurement | 251 | |
Contingent Payments, End of Year | $ 0 |
Lease Liabilities - Summary of
Lease Liabilities - Summary of Lease Liabilities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Feb. 28, 2023 | |
Disclosure of detailed information about business combination [line items] | |||
Beginning balance, lease liabilities | $ 2,836 | $ 2,957 | |
Acquisitions | 33 | 0 | |
Additions | 57 | 25 | |
Interest Expense (Note 7) | 161 | 163 | |
Lease Payments | (449) | (465) | |
Divestitures | (11) | 0 | |
Exchange Rate Movements and Other | (31) | (156) | |
Ending balance, lease liabilities | 2,658 | 2,836 | |
Less: Current Portion | 299 | 308 | |
Long-Term Portion | 2,359 | 2,528 | |
Lease liabilities | $ 2,658 | $ 2,836 | |
BP-Husky Refining LLC | |||
Disclosure of detailed information about business combination [line items] | |||
Lease liabilities | $ 11 |
Decommissioning Liabilities - A
Decommissioning Liabilities - Additional Information (Detail) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Aug. 31, 2022 | |
Disclosure of other provisions [line items] | |||
Estimated future cash flows required to settle the obligation | $ 15,000 | $ 14,200 | |
Expected settlement of decommissioning liabilities | $ 259 | ||
Credit-adjusted risk-free rate | 5.50% | 6.10% | |
Inflation rate | 2% | 2% | |
Restricted Cash | $ 211 | $ 209 | |
BP-Husky Refining LLC | |||
Disclosure of other provisions [line items] | |||
Carrying value of pre-existing decommissioning liabilities | $ 2 | ||
Sunrise Oil Sands Partnership | |||
Disclosure of other provisions [line items] | |||
Carrying value of pre-existing decommissioning liabilities | $ 11 |
Decommissioning Liabilities - S
Decommissioning Liabilities - Summary of Decommissioning Provision (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Provision for decommissioning, restoration and rehabilitation costs [abstract] | ||
Beginning balance | $ 3,559 | $ 3,906 |
Liabilities Incurred | 14 | 22 |
Liabilities acuired | 5 | 48 |
Liabilities Settled | (221) | (215) |
Liabilities divested | (5) | (89) |
Change in Estimated Future Cash Flows | 330 | 693 |
Change in Discount Rates | 265 | (980) |
Unwinding of Discount on Decommissioning Liabilities (Note 7) | 220 | 176 |
Exchange Rate Movements and Other | (12) | (2) |
Ending balance | $ 4,155 | $ 3,559 |
Decommissioning Liabilities -_2
Decommissioning Liabilities - Summary of Changes to the Credit-Adjusted Risk-Free Rate or the Inflation Rate Impact on the Decommissioning Liabilities (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of other provisions [line items] | ||
Credit-adjusted risk-free rate, sensitivity range | 1% | 1% |
Inflation rate, sensitivity range | 1% | 1% |
One percent increase | ||
Disclosure of other provisions [line items] | ||
Credit-adjusted risk-free rate | $ (387) | $ (319) |
Inflation rate | 519 | 419 |
One percent decrease | ||
Disclosure of other provisions [line items] | ||
Credit-adjusted risk-free rate | 515 | 419 |
Inflation rate | $ (392) | $ (320) |
Other Liabilities - Summary of
Other Liabilities - Summary of Other Liabilities (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of non-current liabilities [Line Items] | ||
Renewable volume obligation, net | $ 397 | $ 101 |
Pension and Other Post-Employment Benefit Plan | 276 | 201 |
Provision for West White Rose Expansion Project (2) | 156 | 204 |
Provisions for Onerous and Unfavourable Contracts | 72 | 95 |
Employee Long-Term Incentives | 100 | 245 |
Drilling Provisions | 25 | 31 |
Deferred Revenue | 0 | 45 |
Other | 157 | 120 |
Other Liabilities | 1,183 | 1,042 |
RVO included in other liabilities, gross | 785 | 1,100 |
RINs included in other liabilities, gross | 388 | $ 1,000 |
West white rose expansion project, expected draw down to provision | $ 73 |
Pensions and Other Post-Emplo_3
Pensions and Other Post-Employment Benefits - Additional Information (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2023 CAD ($) | |
DB Pension Plan | |
Disclosure of defined benefit plans [line items] | |
Weighted average duration | 15 years |
Percentage of employees contribution under pension plan | 4% |
Employer contribution | $ 11 |
OPEB Plans | |
Disclosure of defined benefit plans [line items] | |
Weighted average duration | 14 years |
Estimate of contributions expected to be paid to plan for next annual reporting period | $ 13 |
Pensions and Other Post-Emplo_4
Pensions and Other Post-Employment Benefits - Summary of Defined Benefit and OPEB Plan Obligation and Funded Status (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
DB Pension Plan | ||
Disclosure of net defined benefit liability (asset) [line items] | ||
Current Service Costs | $ 10 | $ 16 |
Past Service Costs - Curtailment and Plan Amendments | 0 | 0 |
Interest costs | (1) | (3) |
Re-measurements: | ||
(Gains) Losses From Experience Adjustments | 4 | 1 |
(Gains) Losses From Changes in Demographic Assumptions | 0 | 0 |
(Gains) Losses From Changes in Financial Assumptions | 13 | (64) |
Return on Plan Assets (Excluding Interest Income) | 10 | (26) |
Defined Benefit Pension and OPEB Asset (Liability) (2) | (24) | (25) |
DB Pension Plan | Defined Benefit Obligation | ||
Disclosure of net defined benefit liability (asset) [line items] | ||
Defined Benefit Obligation, Beginning of Year | 172 | 220 |
Current Service Costs | 10 | 16 |
Interest costs | (9) | (7) |
Benefits Paid | (8) | (12) |
Plan Participant Contributions | 3 | 2 |
Re-measurements: | ||
(Gains) Losses From Experience Adjustments | 4 | 1 |
(Gains) Losses From Changes in Financial Assumptions | 13 | (64) |
Exchange Rate Movements and Other | (1) | 2 |
Defined Benefit Obligation, End of Year | 202 | 172 |
DB Pension Plan | Plan Assets | ||
Disclosure of net defined benefit liability (asset) [line items] | ||
Fair Value of Plan Assets, Beginning of Year | 147 | 159 |
Interest costs | 8 | 4 |
Benefits Paid | (7) | (10) |
Plan Participant Contributions | 3 | 2 |
Employer Contributions | 18 | 16 |
Re-measurements: | ||
Return on Plan Assets (Excluding Interest Income) | 10 | (26) |
Exchange Rate Movements and Other | (1) | 2 |
Fair Value of Plan Assets, End of Year | 178 | 147 |
OPEB Plans | ||
Disclosure of net defined benefit liability (asset) [line items] | ||
Current Service Costs | 14 | 8 |
Past Service Costs - Curtailment and Plan Amendments | 10 | 0 |
Interest costs | (10) | (7) |
Re-measurements: | ||
(Gains) Losses From Experience Adjustments | 1 | (2) |
(Gains) Losses From Changes in Demographic Assumptions | 0 | 0 |
(Gains) Losses From Changes in Financial Assumptions | 50 | (57) |
Return on Plan Assets (Excluding Interest Income) | 0 | 0 |
Defined Benefit Pension and OPEB Asset (Liability) (2) | (249) | (174) |
OPEB Plans | Defined Benefit Obligation | ||
Disclosure of net defined benefit liability (asset) [line items] | ||
Defined Benefit Obligation, Beginning of Year | 174 | 225 |
Current Service Costs | 14 | 8 |
Interest costs | (10) | (7) |
Benefits Paid | (9) | (8) |
Plan Participant Contributions | 0 | 0 |
Re-measurements: | ||
(Gains) Losses From Experience Adjustments | 1 | (2) |
(Gains) Losses From Changes in Financial Assumptions | 50 | (57) |
Exchange Rate Movements and Other | (1) | 1 |
Defined Benefit Obligation, End of Year | 249 | 174 |
OPEB Plans | Plan Assets | ||
Disclosure of net defined benefit liability (asset) [line items] | ||
Fair Value of Plan Assets, Beginning of Year | 0 | 0 |
Interest costs | 0 | 0 |
Benefits Paid | (9) | (8) |
Plan Participant Contributions | 0 | 0 |
Employer Contributions | 9 | 8 |
Re-measurements: | ||
Return on Plan Assets (Excluding Interest Income) | 0 | 0 |
Exchange Rate Movements and Other | 0 | 0 |
Fair Value of Plan Assets, End of Year | $ 0 | $ 0 |
Pensions and Other Post-Emplo_5
Pensions and Other Post-Employment Benefits - Summary of Pension and OPEB Costs (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
DB Pension Plan | ||
Disclosure of defined benefit plans [line items] | ||
Current Service Costs | $ 10 | $ 16 |
Past Service Costs – Curtailments and Plan Amendments | 0 | 0 |
Net Interest Costs | 1 | 3 |
Re-measurements: | ||
Return on Plan Assets (Excluding Interest Income) | (10) | 26 |
(Gains) Losses From Experience Adjustments | 4 | 1 |
(Gains) Losses From Changes in Demographic Assumptions | 0 | 0 |
(Gains) Losses From Changes in Financial Assumptions | 13 | (64) |
Defined Benefit Plan Cost (Recovery) | 18 | (18) |
Defined contribution plan cost | 99 | 72 |
Total Plan Cost | 117 | 54 |
OPEB Plans | ||
Disclosure of defined benefit plans [line items] | ||
Current Service Costs | 14 | 8 |
Past Service Costs – Curtailments and Plan Amendments | 10 | 0 |
Net Interest Costs | 10 | 7 |
Re-measurements: | ||
Return on Plan Assets (Excluding Interest Income) | 0 | 0 |
(Gains) Losses From Experience Adjustments | 1 | (2) |
(Gains) Losses From Changes in Demographic Assumptions | 0 | 0 |
(Gains) Losses From Changes in Financial Assumptions | 50 | (57) |
Defined Benefit Plan Cost (Recovery) | 85 | (44) |
Defined contribution plan cost | 0 | 0 |
Total Plan Cost | $ 85 | $ (44) |
Pensions and Other Post-Emplo_6
Pensions and Other Post-Employment Benefits - Summary of Fair Value of the Plan Assets (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Pensions And Other Post Employment Benefits [Abstract] | ||
Level 1 – Cash and Cash Equivalents | $ 5 | $ 7 |
Level 2 – Equity and Fixed Income Funds | 161 | 130 |
Level 3 – Real Estate Funds and Other | 12 | 10 |
Total plan assets, at fair value | $ 178 | $ 147 |
Pensions and Other Post-Emplo_7
Pensions and Other Post-Employment Benefits - Summary of Principal Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Expenses (Detail) - yr | Dec. 31, 2023 | Dec. 31, 2022 |
DB Pension Plan | ||
Disclosure Of Actuarial Assumptions [Line Items] | ||
Discount Rate (percent) | 4.58% | 5.12% |
Future Salary Growth Rate (percent) | 4% | 4.05% |
Average Longevity (years) | 88.4 | 88.4 |
OPEB Plans | ||
Disclosure Of Actuarial Assumptions [Line Items] | ||
Discount Rate (percent) | 4.65% | 5.13% |
Average Longevity (years) | 88.4 | 88.4 |
Health Care Cost Trend Rate (percent) | 5.24% | 5.24% |
Pensions and Other Post-Emplo_8
Pensions and Other Post-Employment Benefits - Sensitivity of Defined Benefit and OPEB Obligation to Changes in Relevant Actuarial Assumptions (Detail) - CAD ($) | Dec. 31, 2023 | Dec. 31, 2022 |
Future Salary Growth Rate | ||
Disclosure of sensitivity analysis for actuarial assumptions [line items] | ||
Increase | $ 0 | |
Percentage of reasonably possible decrease in actuarial assumption | 1% | |
Percentage of reasonably possible increase in actuarial assumption | 1% | |
Health Care Cost Trend Rate | ||
Disclosure of sensitivity analysis for actuarial assumptions [line items] | ||
Increase | $ 0 | |
Percentage of reasonably possible decrease in actuarial assumption | 1% | |
Percentage of reasonably possible increase in actuarial assumption | 1% | |
One Year Change in Assumed Life Expectancy | ||
Disclosure of sensitivity analysis for actuarial assumptions [line items] | ||
Increase | $ 0 | |
Reasonably Possible Decrease In Actuarial Assumption, Life Expectancy | 1 year | |
Reasonably Possible Increase In Actuarial Assumption, Life Expectancy | 1 year | |
Discount Rate | ||
Disclosure of sensitivity analysis for actuarial assumptions [line items] | ||
Increase | $ (54,000,000) | $ (43,000,000) |
Decrease | $ 66,000,000 | $ 51,000,000 |
Percentage of reasonably possible decrease in actuarial assumption | 1% | |
Percentage of reasonably possible increase in actuarial assumption | 1% |
Share Capital and Warrants - Na
Share Capital and Warrants - Narrative (Details) - CAD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||
Jun. 14, 2023 | Feb. 12, 2024 | Dec. 31, 2023 | Sep. 30, 2023 | Jun. 30, 2023 | Mar. 31, 2023 | Dec. 31, 2022 | Sep. 30, 2022 | Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Nov. 07, 2023 | Dec. 31, 2021 | |
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Maximum percentage of preferred stock upon issuance or outstanding of common stock | 20% | |||||||||||||
NCIB, shares redeemed, amount | $ 1,061 | $ 2,530 | ||||||||||||
NCIB, reduction to contributed surplus | $ 688 | $ 1,571 | ||||||||||||
Preference shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Number of shares issued | 0 | 0 | ||||||||||||
Shares outstanding (in shares) | 36,000,000 | 36,000,000 | 36,000,000 | 36,000,000 | ||||||||||
Issued capital | $ 519 | $ 519 | $ 519 | $ 519 | ||||||||||
Dividend Rate (percent) | 6.89% | 6.29% | 6.29% | 5.86% | 5.05% | 3.21% | 2.35% | 1.86% | ||||||
Preference shares | Series 1 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares outstanding (in shares) | 10,740,000 | 10,740,000 | ||||||||||||
Dividend Rate (percent) | 2.58% | |||||||||||||
Preference shares | Series 1 First Preferred Shares | Government of Canada Bond | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 173% | 173% | ||||||||||||
Preference shares | Series 2 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares outstanding (in shares) | 1,260,000 | 1,260,000 | ||||||||||||
Dividend Rate (percent) | 6.77% | |||||||||||||
Preference shares | Series 2 First Preferred Shares | 90-Day Government of Canada Treasury Bills | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 173% | 173% | ||||||||||||
Preference shares | Series 3 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares outstanding (in shares) | 10,000,000 | 10,000,000 | ||||||||||||
Dividend Rate (percent) | 4.69% | |||||||||||||
Preference shares | Series 3 First Preferred Shares | Government of Canada Bond | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 313% | 313% | ||||||||||||
Preference shares | Series 5 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares outstanding (in shares) | 8,000,000 | 8,000,000 | ||||||||||||
Dividend Rate (percent) | 4.59% | |||||||||||||
Preference shares | Series 5 First Preferred Shares | Government of Canada Bond | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 357% | 357% | ||||||||||||
Preference shares | Series 7 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares outstanding (in shares) | 6,000,000 | 6,000,000 | ||||||||||||
Dividend Rate (percent) | 3.94% | |||||||||||||
Preference shares | Series 7 First Preferred Shares | Government of Canada Bond | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 352% | 352% | ||||||||||||
Preference shares | First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Redeemable preferred shares, conversion term | 5 years | |||||||||||||
Redeemable preferred shares, price per share | $ 25 | |||||||||||||
Preference shares | Series 1 And 2 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Redeemable preferred shares, conversion term | 5 years | |||||||||||||
Preference shares | Series 3 and 4 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Redeemable preferred shares, conversion term | 5 years | |||||||||||||
Preference shares | Series 5 and 6 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Redeemable preferred shares, conversion term | 5 years | |||||||||||||
Preference shares | Series 7 and 8 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Redeemable preferred shares, conversion term | 5 years | |||||||||||||
Preference shares | Series 1, 3, 5, 7 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Redeemable preferred shares, conversion term | 5 years | |||||||||||||
Preference shares | Series 4 First Preferred Shares | 90-Day Government of Canada Treasury Bills | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 313% | 313% | ||||||||||||
Preference shares | Series 6 First Preferred Shares | 90-Day Government of Canada Treasury Bills | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 357% | 357% | ||||||||||||
Preference shares | Series 8 First Preferred Shares | 90-Day Government of Canada Treasury Bills | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Dividend rate, basis spread | 352% | 352% | ||||||||||||
Preference shares | Series 2,4,6,8 First Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Redeemable preferred shares, price per share | $ 25.50 | |||||||||||||
Second Preferred Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares outstanding (in shares) | 0 | 0 | 0 | 0 | ||||||||||
Common Shares | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Purchase of Common Shares under NCIB | 43,611,000 | 112,489,000 | ||||||||||||
Shares outstanding (in shares) | 1,871,868,000 | 1,909,190,000 | 1,871,868,000 | 1,909,190,000 | 2,001,211,000 | |||||||||
Issued capital | $ 16,031 | $ 16,320 | $ 16,031 | $ 16,320 | $ 17,016 | |||||||||
Common Shares | Original NCIB | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
NCIB, shares repurchased, price per share (in CAD per share) | $ 24.32 | $ 22.49 | ||||||||||||
NCIB, shares redeemed, amount | $ 1,100 | $ 2,500 | ||||||||||||
NCIB, reduction to contributed surplus | $ 688 | $ 1,600 | ||||||||||||
Common Shares | Renewed NCIB | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
NCIB, shares authorized for repurchase (in shares) | 133,200,000 | |||||||||||||
Common Shares | Renewed NCIB | Potential ordinary share transactions | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
NCIB, shares authorized for repurchase (in shares) | 118,300,000 | |||||||||||||
Purchase of Common Shares under NCIB | 4,300,000 | |||||||||||||
NCIB, shares redeemed, amount | $ 92 | |||||||||||||
Common Share Warrants | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares outstanding (in shares) | 7,625,000 | 55,720,000 | 7,625,000 | 55,720,000 | 65,119,000 | |||||||||
Issued capital | $ 25 | $ 184 | $ 25 | $ 184 | $ 215 | |||||||||
Exercise price of warrants issued (in CAD per share) | $ 6.54 | $ 6.54 | ||||||||||||
Purchases and cancelled (in shares) | 45,500,000 | 45,485,000 | 0 | |||||||||||
Purchase Price, Warrants, Per Share | $ 22.18 | |||||||||||||
Purchased and Cancelled | $ 711 | $ 151 | $ 0 | |||||||||||
Decrease Through Repurchase And Cancellation of Warrants, Equity | 560 | |||||||||||||
Decrease Through Repurchase And Cancellation of Warrants, Transaction Costs, Equity | $ 2 | |||||||||||||
Stock Option Plan | ||||||||||||||
Disclosure of classes of share capital [Line Items] | ||||||||||||||
Shares available for future issuance (in shares) | 45,500,000 | 43,100,000 | 45,500,000 | 43,100,000 |
Share Capital and Warrants - Is
Share Capital and Warrants - Issued and Outstanding - Common Shares (Detail) - Common Shares - CAD ($) shares in Thousands, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Number of Common Shares | ||
Outstanding, beginning of year (in shares) | 1,909,190 | 2,001,211 |
Issued Upon Exercise of Warrants | 2,610 | 9,399 |
Issued Under Stock Option Plans | 3,679 | 11,069 |
Purchase of Common Shares under NCIB | (43,611) | (112,489) |
Outstanding, end of year (in shares) | 1,871,868 | 1,909,190 |
Amount | ||
Outstanding, Beginning of Year | $ 16,320 | $ 17,016 |
Issued Upon Exercise of Warrants | 26 | 93 |
Issued Under Stock Option Plans | 58 | 170 |
Purchase of Common Shares under NCIB | (373) | (959) |
Outstanding, End of Year | $ 16,031 | $ 16,320 |
Share Capital and Warrants - _2
Share Capital and Warrants - Issued and Outstanding - Preferred Shares (Details) - Preference shares - shares shares in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Dec. 31, 2023 | Sep. 30, 2023 | Jun. 30, 2023 | Mar. 31, 2023 | Dec. 31, 2022 | Sep. 30, 2022 | Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2023 | |
Disclosure of classes of share capital [Line Items] | |||||||||
Dividend Rate (percent) | 6.89% | 6.29% | 6.29% | 5.86% | 5.05% | 3.21% | 2.35% | 1.86% | |
Shares outstanding (in shares) | 36,000 | 36,000 | 36,000 | ||||||
Series 1 First Preferred Shares | |||||||||
Disclosure of classes of share capital [Line Items] | |||||||||
Dividend Rate (percent) | 2.58% | ||||||||
Shares outstanding (in shares) | 10,740 | 10,740 | |||||||
Series 2 First Preferred Shares | |||||||||
Disclosure of classes of share capital [Line Items] | |||||||||
Dividend Rate (percent) | 6.77% | ||||||||
Shares outstanding (in shares) | 1,260 | 1,260 | |||||||
Series 3 First Preferred Shares | |||||||||
Disclosure of classes of share capital [Line Items] | |||||||||
Dividend Rate (percent) | 4.69% | ||||||||
Shares outstanding (in shares) | 10,000 | 10,000 | |||||||
Series 5 First Preferred Shares | |||||||||
Disclosure of classes of share capital [Line Items] | |||||||||
Dividend Rate (percent) | 4.59% | ||||||||
Shares outstanding (in shares) | 8,000 | 8,000 | |||||||
Series 7 First Preferred Shares | |||||||||
Disclosure of classes of share capital [Line Items] | |||||||||
Dividend Rate (percent) | 3.94% | ||||||||
Shares outstanding (in shares) | 6,000 | 6,000 |
Share Capital and Warrants - _3
Share Capital and Warrants - Issued and Outstanding - Warrants (Details) - Common Share Warrants - CAD ($) shares in Thousands, $ in Millions | 12 Months Ended | ||
Jun. 14, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | |
Number of Warrants | |||
Outstanding, beginning of year (in shares) | 55,720 | 65,119 | |
Exercised (in shares) | (2,610) | (9,399) | |
Purchases and cancelled (in shares) | (45,500) | (45,485) | 0 |
Outstanding, end of year (in shares) | 7,625 | 55,720 | |
Amount | |||
Outstanding, Beginning of Year | $ 184 | $ 215 | |
Issued Upon Exercise of Warrants | (8) | (31) | |
Purchased and Cancelled | $ (711) | (151) | 0 |
Outstanding, End of Year | $ 25 | $ 184 |
Share Capital and Warrants - Sc
Share Capital and Warrants - Schedule of Paid in Surplus Includes Stock Based Compensation Expense (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of reserves within equity [line items] | ||
Beginning balance | $ 2,691 | $ 4,284 |
Stock-Based Compensation Expense | 97 | 373 |
Purchase of Common Shares Under NCIB | (688) | (1,571) |
Common Shares Issued on Exercise of Stock Options | (12) | (32) |
Ending balance | 2,002 | 2,691 |
NSRs and NCIB | ||
Disclosure of reserves within equity [line items] | ||
Stock-Based Compensation Expense | 11 | 10 |
Retained Earnings Prior to Ovintiv Split | ||
Disclosure of reserves within equity [line items] | ||
Beginning balance | 2,395 | 3,966 |
Purchase of Common Shares Under NCIB | (688) | (1,571) |
Common Shares Issued on Exercise of Stock Options | 0 | 0 |
Ending balance | 1,707 | 2,395 |
Retained Earnings Prior to Ovintiv Split | NSRs and NCIB | ||
Disclosure of reserves within equity [line items] | ||
Stock-Based Compensation Expense | 0 | 0 |
Stock-Based Compensation | ||
Disclosure of reserves within equity [line items] | ||
Beginning balance | 296 | 318 |
Purchase of Common Shares Under NCIB | 0 | 0 |
Common Shares Issued on Exercise of Stock Options | (12) | (32) |
Ending balance | 295 | 296 |
Stock-Based Compensation | NSRs and NCIB | ||
Disclosure of reserves within equity [line items] | ||
Stock-Based Compensation Expense | $ 11 | $ 10 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Loss) - Schedule of Accumulated Other Comprehensive Income (Loss) (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of accumulated other comprehensive income loss [line items] | ||
Beginning balance | $ 1,470 | $ 684 |
Other Comprehensive Income (Loss), Before Tax | (281) | 811 |
Reclassification on Divestiture (Note 5) | 12 | |
Income Tax (Expense) Recovery | 7 | (25) |
Ending balance | 1,208 | 1,470 |
Pension and Other Post-Retirement Benefits | ||
Disclosure of accumulated other comprehensive income loss [line items] | ||
Beginning balance | 99 | 28 |
Other Comprehensive Income (Loss), Before Tax | (58) | 96 |
Reclassification on Divestiture (Note 5) | 0 | |
Income Tax (Expense) Recovery | 14 | (25) |
Ending balance | 55 | 99 |
Private Equity Instruments | ||
Disclosure of accumulated other comprehensive income loss [line items] | ||
Beginning balance | 29 | 27 |
Other Comprehensive Income (Loss), Before Tax | 63 | 2 |
Reclassification on Divestiture (Note 5) | 0 | |
Income Tax (Expense) Recovery | (7) | 0 |
Ending balance | 85 | 29 |
Foreign Currency Translation Adjustment | ||
Disclosure of accumulated other comprehensive income loss [line items] | ||
Beginning balance | 1,342 | 629 |
Other Comprehensive Income (Loss), Before Tax | (286) | 713 |
Reclassification on Divestiture (Note 5) | 12 | |
Income Tax (Expense) Recovery | 0 | 0 |
Ending balance | $ 1,068 | $ 1,342 |
Stock-Based Compensation Plan_2
Stock-Based Compensation Plans - Additional Information (Detail) $ / shares in Units, shares in Thousands | 12 Months Ended | |
Dec. 31, 2023 CAD ($) plan $ / shares shares | Dec. 31, 2022 CAD ($) | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Options expiration term | 7 years | |
Liabilities from share based payment | $ 284,000,000 | $ 162,000,000 |
Number of deferred share unit plans | plan | 2 | |
Minimum | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Vesting multiplier, percent | 0% | |
Maximum | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Vesting multiplier, percent | 200% | |
Net settlement rights | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Weighted average unit fair value of granted | $ 7.41 | |
Cenovus Replacement Stock Options | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Liabilities from share based payment | $ 12,000,000 | 42,000,000 |
Cenovus Replacement Stock Options | Settled for cash | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Number of other equity instruments exercised or vested in share-based payment arrangement, settled for cash | shares | (2,113) | |
Weighted average exercise price, exercised (in dollars per share) | $ / shares | $ 9.98 | |
Cenovus Replacement Stock Options | Settled for common shares | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Number of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in shares) | shares | 3 | |
Weighted average exercise price of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in dollars per share) | $ / shares | $ 3.54 | |
Common shares issued in exercise of other equity instruments (in shares) | shares | 2 | |
PSUs | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Liabilities from share based payment | $ 238,000,000 | 216,000,000 |
Award vesting term | 3 years | |
Intrinsic value of vested | $ 0 | |
RSUs | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Liabilities from share based payment | $ 97,000,000 | 109,000,000 |
Award vesting term | 3 years | |
Intrinsic value of vested | $ 0 | |
DSUs | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Liabilities from share based payment | $ 37,000,000 | $ 40,000,000 |
DSUs Option One | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Percentage of annual bonus award to convert into DSUs | 0% | |
DSUs Option Two | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Percentage of annual bonus award to convert into DSUs | 25% | |
DSUs Option Three | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Percentage of annual bonus award to convert into DSUs | 50% | |
DSUs Option Four | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Percentage of annual bonus award to convert into DSUs | 75% | |
Deferred Share Units Option Five | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Percentage of annual bonus award to convert into DSUs | 100% | |
Later than one year | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Percentage of options exercisable | 30% | |
3 Years | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Percentage of options exercisable | 30% |
Stock-Based Compensation Plan_3
Stock-Based Compensation Plans - Summary of Assumptions Used to Determine Fair Value of Options Granted (Detail) - Net settlement rights | 12 Months Ended |
Dec. 31, 2023 yr | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Risk-Free Interest Rate (percent) | 3.42% |
Expected Dividend Yield (percent) | 1.78% |
Expected Volatility | 31.95% |
Expected Life (years) | 5.45 |
Stock-Based Compensation Plan_4
Stock-Based Compensation Plans - Summary of Stock Option Activity and Related Information (Detail) shares in Thousands | 12 Months Ended |
Dec. 31, 2023 shares $ / shares | |
Net settlement rights | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Number of options outstanding, beginning of period (in shares) | 14,349 |
Options granted (in shares) | (1,571) |
Options exercised (in shares) | (3,839) |
Options forfeited (in shares) | (128) |
Options expired (in shares) | (58) |
Number of options outstanding, ending period (in shares) | 11,895 |
Weighted average exercised price, outstanding, beginning of year (in dollars per share) | $ / shares | $ 12.38 |
Weighted average exercise price, granted (in dollars per share) | $ / shares | 24.34 |
Weighted average exercise price, exercised (in dollars per share) | $ / shares | 13.08 |
Weighted average exercise price, forfeited (in dollars per share) | $ / shares | 15.78 |
Weighted average exercise price, expired (in dollars per share) | $ / shares | 19.89 |
Weighted average exercised price, outstanding, end of year (in dollars per share) | $ / shares | $ 13.66 |
Cenovus Replacement Stock Options | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Number of options outstanding, beginning of period (in shares) | 3,467 |
Options forfeited (in shares) | (23) |
Options expired (in shares) | (326) |
Number of options outstanding, ending period (in shares) | 1,005 |
Weighted average exercised price, outstanding, beginning of year (in dollars per share) | $ / shares | $ 9.99 |
Weighted average exercise price, forfeited (in dollars per share) | $ / shares | 6.58 |
Weighted average exercise price, expired (in dollars per share) | $ / shares | 21.09 |
Weighted average exercised price, outstanding, end of year (in dollars per share) | $ / shares | 6.49 |
Cenovus Replacement Stock Options | Settled for cash | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Weighted average exercise price, exercised (in dollars per share) | $ / shares | $ 9.97 |
PSUs | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Number of share units, outstanding, beginning of year (in shares) | 8,678 |
Granted (in shares) | 2,539 |
Exercised (in shares) | (972) |
Cancelled (in shares) | (231) |
United in lieu of dividends (in shares) | 229 |
Number of share units, outstanding, end of year (in shares) | 10,243 |
RSUs | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Number of share units, outstanding, beginning of year (in shares) | 6,655 |
Granted (in shares) | 2,961 |
Exercised (in shares) | (2,300) |
Cancelled (in shares) | (243) |
United in lieu of dividends (in shares) | 161 |
Number of share units, outstanding, end of year (in shares) | 7,234 |
DSUs | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Number of share units, outstanding, beginning of year (in shares) | 1,506 |
Granted (in shares) | 59 |
United in lieu of dividends (in shares) | 37 |
Redeemed (in shares) | (37) |
Number of share units, outstanding, end of year (in shares) | 1,691 |
DSUs | Director | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | |
Granted (in shares) | 126 |
Stock-Based Compensation Plan_5
Stock-Based Compensation Plans - Summary of Options Outstanding and Exercisable by Range of Exercise Price (Detail) shares in Thousands | 12 Months Ended | |
Dec. 31, 2023 shares $ / shares | Dec. 31, 2022 shares $ / shares | |
Net settlement rights | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 11,895 | 14,349 |
Weighted average remaining contractual life of outstanding share options (in years) | 4 years 10 days | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 13.66 | $ 12.38 |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 6,658 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 11.56 | |
Net settlement rights | 5.00 to 9.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 4,303 | |
Weighted average remaining contractual life of outstanding share options (in years) | 3 years 9 months 29 days | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 8.77 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 2,218 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 8.85 | |
Net settlement rights | 5.00 to 9.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 5 | |
Net settlement rights | 5.00 to 9.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 9.99 | |
Net settlement rights | 10.00 to 14.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 4,163 | |
Weighted average remaining contractual life of outstanding share options (in years) | 2 years 11 months 1 day | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 11.93 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 3,894 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 11.94 | |
Net settlement rights | 10.00 to 14.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 10 | |
Net settlement rights | 10.00 to 14.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 14.99 | |
Net settlement rights | 15.00 to 19.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 1,851 | |
Weighted average remaining contractual life of outstanding share options (in years) | 5 years 1 month 17 days | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 19.88 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 536 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 19.88 | |
Net settlement rights | 15.00 to 19.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 15 | |
Net settlement rights | 15.00 to 19.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 19.99 | |
Net settlement rights | 20.00 to 24.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 1,561 | |
Weighted average remaining contractual life of outstanding share options (in years) | 6 years 2 months 1 day | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 24.25 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 10 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 22.75 | |
Net settlement rights | 20.00 to 24.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 20 | |
Net settlement rights | 20.00 to 24.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 24.99 | |
Net settlement rights | 25.00 to 29.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 17 | |
Weighted average remaining contractual life of outstanding share options (in years) | 6 years 8 months 12 days | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 27.71 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 0 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 0 | |
Net settlement rights | 25.00 to 29.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 25 | |
Net settlement rights | 25.00 to 29.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 29.99 | |
Cenovus Replacement Stock Options | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 1,005 | 3,467 |
Weighted average remaining contractual life of outstanding share options (in years) | 11 months 26 days | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 6.49 | $ 9.99 |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 1,005 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 6.49 | |
Cenovus Replacement Stock Options | 3.00 to 4.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 782 | |
Weighted average remaining contractual life of outstanding share options (in years) | 1 year 2 months 19 days | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 3.54 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 782 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 3.54 | |
Cenovus Replacement Stock Options | 3.00 to 4.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 3 | |
Cenovus Replacement Stock Options | 3.00 to 4.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 4.99 | |
Cenovus Replacement Stock Options | 5.00 to 9.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 28 | |
Weighted average remaining contractual life of outstanding share options (in years) | 5 months 1 day | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 6.19 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 28 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 6.19 | |
Cenovus Replacement Stock Options | 5.00 to 9.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 5 | |
Cenovus Replacement Stock Options | 5.00 to 9.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 9.99 | |
Cenovus Replacement Stock Options | 10.00 to 14.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 0 | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 0 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 0 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 0 | |
Cenovus Replacement Stock Options | 10.00 to 14.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 10 | |
Cenovus Replacement Stock Options | 10.00 to 14.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 14.99 | |
Cenovus Replacement Stock Options | 15.00 to 19.99 | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Outstanding number (in shares) | shares | 195 | |
Weighted average remaining contractual life of outstanding share options (in years) | 2 months 4 days | |
Weighted average exercise price of share options outstanding in share-based payment arrangement (in dollars per share) | $ 18.35 | |
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares | 195 | |
Weighted average exercise price of share options exercisable in share-based payment arrangement (in dollars per share) | $ 18.35 | |
Cenovus Replacement Stock Options | 15.00 to 19.99 | Bottom of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | 15 | |
Cenovus Replacement Stock Options | 15.00 to 19.99 | Top of range | ||
Disclosure of range of exercise prices of outstanding share options [Line Items] | ||
Exercise price of warrants (in dollars per share) | $ 19.99 |
Stock-Based Compensation Plan_6
Stock-Based Compensation Plans - Summary of Stock-Based Compensation (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Total Stock-Based Compensation Expense (Recovery) | $ 97 | $ 373 |
Stock Options With Associated Net Settlement Rights | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Total Stock-Based Compensation Expense (Recovery) | 11 | 15 |
Cenovus Replacement Stock Options | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Total Stock-Based Compensation Expense (Recovery) | (5) | 53 |
Performance Share Units | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Total Stock-Based Compensation Expense (Recovery) | 47 | 183 |
Restricted Share Units | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Total Stock-Based Compensation Expense (Recovery) | 46 | 100 |
Deferred Share Units | ||
Disclosure of terms and conditions of share-based payment arrangement [Line Items] | ||
Total Stock-Based Compensation Expense (Recovery) | $ (2) | $ 22 |
Employee Salaries and Benefit_3
Employee Salaries and Benefit Expenses - Summary of Employee Salaries and Benefit Expenses (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure Of Salaries And Employee Benefits [Abstract] | ||
Salaries, Bonuses and Other Short-Term Employee Benefits | $ 1,344 | $ 1,246 |
Pension and Post-Employment Benefits | 125 | 92 |
Stock-Based Compensation (Note 32) | 97 | 373 |
Other Incentive Benefits Expense (Recovery) | 0 | (9) |
Termination Benefits | 14 | 27 |
Employee Salaries and Benefit Expenses | $ 1,580 | $ 1,729 |
Related Party Transactions - Su
Related Party Transactions - Summary of Key Management Compensation (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of transactions between related parties [abstract] | ||
Salaries, Director Fees and Other Short-Term Benefits | $ 40 | $ 40 |
Pension and Post-Employment Benefits | 3 | 4 |
Stock-Based Compensation | 40 | 140 |
Termination Benefits | 0 | 3 |
Total compensation paid or payable | $ 83 | $ 187 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Details) - Husky Midstream Limited Partnership - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of transactions between related parties [line items] | ||
Proportion of ownership interest in joint venture | 35% | |
Joint ventures where entity is venturer | ||
Disclosure of transactions between related parties [line items] | ||
Revenue from rendering of services, related party transactions | $ 160 | $ 188 |
Purchases of goods, related party transactions | $ 295 | $ 263 |
Financial Instruments - Additio
Financial Instruments - Additional information (Detail) $ / $ in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2023 CAD ($) $ / bbl | Dec. 31, 2023 CAD ($) $ / bbl | Dec. 31, 2023 CAD ($) $ / bbl | Dec. 31, 2023 CAD ($) $ / bbl $ / $ | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) | |
Disclosure of detailed information about financial instruments [line items] | ||||||
Total Debt | $ 7,108 | $ 7,108 | $ 7,108 | $ 7,108 | $ 8,691 | |
Cash collateral for risk management contracts price change | $ 47 | $ 47 | $ 47 | $ 47 | 211 | |
Discounted credit adjusted risk free rate | 5.60% | 5.60% | 5.60% | 5.60% | ||
Sunrise Oil Sands Partnership | ||||||
Disclosure of detailed information about financial instruments [line items] | ||||||
Estimated fair value of contingent payment | $ 164 | $ 164 | $ 164 | $ 164 | 419 | $ 0 |
WCS Forward Prices | ||||||
Disclosure of detailed information about financial instruments [line items] | ||||||
Average forward price for Western Canadian Select crude oil for the remaining term (in CAD per barrel) | $ / bbl | 71.86 | 71.86 | 71.86 | 71.86 | ||
Sensitivity price range | $ / bbl | 10 | |||||
Increase | $ (21) | (68) | ||||
Decrease | $ 45 | 157 | ||||
WTI Option Implied Volatility | ||||||
Disclosure of detailed information about financial instruments [line items] | ||||||
Average implied volatility contingent payment percentage | 39.40% | 39.40% | 39.40% | 39.40% | ||
Sensitivity range | 10% | |||||
U.S. to Canadian Dollar Foreign Exchange Average Rate Volatility Contingent Payment | ||||||
Disclosure of detailed information about financial instruments [line items] | ||||||
Average implied volatility contingent payment percentage | 5.80% | 5.80% | 5.80% | 5.80% | ||
Canadian to U.S. Dollar Foreign Exchange Rate Option Implied Volatility | ||||||
Disclosure of detailed information about financial instruments [line items] | ||||||
Sensitivity range | 5% | 0% | ||||
Level 2 | ||||||
Disclosure of detailed information about financial instruments [line items] | ||||||
Debt, fair value | $ 6,600 | $ 6,600 | $ 6,600 | $ 6,600 | $ 7,800 |
Financial Instruments - Reconci
Financial Instruments - Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets (Detail) - Level 3 of fair value hierarchy - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of fair value measurement of assets [Line Items] | ||
Fair Value, Beginning of Year | $ 55 | $ 53 |
Acquisition | 13 | 0 |
Changes in Fair Value | 63 | 2 |
Fair Value, End of Year | $ 131 | $ 55 |
Financial Instruments - Summary
Financial Instruments - Summary of Unrealized Risk Management Positions (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Net | $ 12 | $ 46 | $ (68) |
Power Swap Contacts | |||
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Net | 2 | ||
Renewable Power Contracts | |||
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Net | 18 | ||
Level 2 | |||
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Net | (6) | (44) | |
Level 2 | Commodity price risk | |||
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Asset | 31 | 93 | |
Liability | 19 | 47 | |
Net | 12 | 46 | |
Level 2 | Commodity price risk | Crude Oil, Natural Gas, Condensate and Refined Products | |||
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Asset | 11 | 2 | |
Liability | 19 | 40 | |
Net | (8) | (38) | |
Level 2 | Commodity price risk | Power Swap Contacts | |||
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Asset | 2 | 1 | |
Liability | 0 | 7 | |
Net | 2 | (6) | |
Level 2 | Commodity price risk | Renewable Power Contracts | |||
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items] | |||
Asset | 18 | 90 | |
Liability | 0 | 0 | |
Net | $ 18 | $ 90 |
Financial Instruments - Summa_2
Financial Instruments - Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure Of Levels Of Fair Value Hierarchy [Line Items] | |||
Fair value of derivative financial instruments net | $ 12 | $ 46 | $ (68) |
Level 2 | |||
Disclosure Of Levels Of Fair Value Hierarchy [Line Items] | |||
Fair value of derivative financial instruments net | (6) | (44) | |
Level 3 | |||
Disclosure Of Levels Of Fair Value Hierarchy [Line Items] | |||
Fair value of derivative financial instruments net | $ 18 | $ 90 |
Financial Instruments - Recon_2
Financial Instruments - Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of detailed information about financial instruments [abstract] | ||
Fair Value of Contracts, Beginning of Year | $ 46 | $ (68) |
Change in Fair Value of Contracts in Place at Beginning of Year | 0 | (5) |
Change in Fair Value of Contracts Entered Into During the Year | (45) | (1,641) |
Fair Value of Contracts Realized During the Year | 9 | 1,762 |
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts | 2 | (2) |
Fair Value of Contracts, End of Year | $ 12 | $ 46 |
Financial Instruments - Summa_3
Financial Instruments - Summary of Offsetting Risk Management Positions (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of detailed information about financial instruments [abstract] | ||
Risk management asset, gross | $ 71 | $ 153 |
Risk management asset, amount offset | (40) | (60) |
Net risk management asset | 31 | 93 |
Risk management liabilities, gross | 59 | 107 |
Risk management liabilities, amount offset | (40) | (60) |
Net risk management liabilities | 19 | 47 |
Risk management net, gross | 12 | 46 |
Risk management net, amount offset | 0 | 0 |
Risk management net | $ 12 | $ 46 |
Financial Instruments - Summa_4
Financial Instruments - Summary of Earnings Impact of (Gain) Loss from Risk Management Positions (Detail) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of detailed information about financial instruments [line items] | ||
(Gain) Loss on Risk Management | $ 61 | $ 1,636 |
Realized (Gain) Loss | ||
Disclosure of detailed information about financial instruments [line items] | ||
(Gain) Loss on Risk Management | 9 | 1,762 |
Unrealized (Gain) Loss | ||
Disclosure of detailed information about financial instruments [line items] | ||
(Gain) Loss on Risk Management | $ 52 | $ (126) |
Financial Instruments - Summa_5
Financial Instruments - Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax (Detail) - WCS Forward Prices $ in Millions | 12 Months Ended | |
Dec. 31, 2023 CAD ($) $ / bbl | Dec. 31, 2022 CAD ($) | |
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items] | ||
Sensitivity price range | $ / bbl | 10 | |
Increase | $ (21) | $ (68) |
Decrease | $ 45 | $ 157 |
Risk Management - Additional In
Risk Management - Additional Information (Detail) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2023 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 CAD ($) | |
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Fair value of derivative financial instruments net | $ 12,000,000 | $ 46,000,000 | $ (68,000,000) | ||
Percentage of accounts receivable outstanding, less than 60 days | 98% | 98% | |||
Target Net Debt to Adjusted EBITDA Ratio | 1 | ||||
Cash and cash equivalents | $ 2,227,000,000 | 4,524,000,000 | $ 2,873,000,000 | ||
Long-Term Debt | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Notional value | 7,028,000,000 | 8,537,000,000 | |||
U.S. Dollar Denominated Unsecured Notes | Long-Term Debt | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Notional value | 5,028,000,000 | $ 3,802 | 6,537,000,000 | $ 4,800 | |
WRB Refining LP | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Uncommitted demand facilities | 119,000,000 | 90 | |||
Uncommitted Demand Facilities | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Uncommitted demand facilities | $ 1,400,000,000 | ||||
Fair value derivative financial instruments | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Average contract financial term | 13 months | ||||
Top of range | Uncommitted Demand Facilities | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Amount of undrawn facilities for general purposes | $ 1,100,000,000 | ||||
Liquidity risk | Committed Credit Facility | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Uncommitted demand facilities | $ 5,500,000,000 | ||||
Foreign Exchange Rate Contracts | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Notional value | $ 0 | $ 168 | |||
Interest rate swap contract | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Notional value | $ 0 | ||||
Trade Receivables | Credit risk | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Average expected credit loss rate | 0.40% | 0.40% | 0.40% | 0.40% | |
Trade Receivables | Credit risk | Investment grade counterparties | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Number of days outstanding for accruals, joint operations, trade receivables and net investment in finance leases | 60 days | 60 days | |||
Trade Receivables | Credit risk | Investment grade counterparties | Bottom of range | |||||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | |||||
Percent of accounts receivable held with investment grade counterparties | 83% | 83% | 85% | 85% |
Risk Management - Net Fair Valu
Risk Management - Net Fair Value of Risk Management Positions (Detail) $ in Millions | Dec. 31, 2023 CAD ($) $ / barrel | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) |
Disclosure of Derivative Financial Instruments [Line Items] | |||
Fair value of derivative financial instruments net | $ 12 | $ 46 | $ (68) |
Power Swap Contacts | |||
Disclosure of Derivative Financial Instruments [Line Items] | |||
Fair value of derivative financial instruments net | 2 | ||
Renewable Power Contracts | |||
Disclosure of Derivative Financial Instruments [Line Items] | |||
Fair value of derivative financial instruments net | $ 18 | ||
WTI Fixed – Sell | Crude Oil and Condensate Contracts | |||
Disclosure of Derivative Financial Instruments [Line Items] | |||
Notional volume | $ / barrel | 3,500,000 | ||
Weighted average price | $ / barrel | 75.22 | ||
Fair value of derivative financial instruments net | $ 16 | ||
WTI Fixed – Buy | Crude Oil and Condensate Contracts | |||
Disclosure of Derivative Financial Instruments [Line Items] | |||
Notional volume | $ / barrel | 1,500,000 | ||
Weighted average price | $ / barrel | 73.69 | ||
Fair value of derivative financial instruments net | $ (4) | ||
Other Financial Positions | |||
Disclosure of Derivative Financial Instruments [Line Items] | |||
Fair value of derivative financial instruments net | $ (20) |
Risk Management - Impact of Flu
Risk Management - Impact of Fluctuating Commodity Prices and Interest Rates on Company's Open Risk Management Positions (Detail) $ in Millions | Dec. 31, 2023 CAD ($) $ / barrel $ / $ MMcf MWh | Dec. 31, 2022 CAD ($) $ / barrel $ / $ MMcf MWh |
WCS Hardisty Differential Price | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | $ / barrel | 5 | |
Natural Gas Commodity Price | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | MMcf | 1 | 1 |
Commodity price risk | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Increase | $ 0 | $ 0 |
Commodity price risk | Crude Oil Contracts | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | $ / barrel | 10 | 10 |
Commodity price risk | WCS and Condensate Differential Price | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | $ / barrel | 2.50 | 2.50 |
Increase | $ 13 | |
Decrease | $ (13) | |
Commodity price risk | WCS Hardisty Differential Price | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | $ / barrel | 5 | |
Commodity price risk | Refined Products | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | $ / barrel | 10 | 10 |
Commodity price risk | Natural Gas Basis Price | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | MMcf | 0.50 | 0.50 |
Commodity price risk | Power Commodity Price | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | MWh | 20 | 20 |
Increase | $ 92 | $ 113 |
Decrease | (92) | (113) |
Currency risk | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Increase | $ 0 | $ 0 |
Currency risk | U.S. to Canadian Dollar Exchange Rate | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | $ / $ | 0.05 | 0.05 |
Increase | $ 14 | |
Decrease | $ (17) |
Risk Management - Impact of F_2
Risk Management - Impact of Fluctuating Commodity Prices and Interest Rates on Company's Open Risk Management Positions (Detail) - Currency risk $ in Millions | 12 Months Ended | |
Dec. 31, 2023 CAD ($) $ / $ | Dec. 31, 2022 CAD ($) | |
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Increase | $ 197 | $ 246 |
Decrease | $ (197) | $ (246) |
Canadian to U.S. Dollar Exchange Rate | ||
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items] | ||
Sensitivity Range | $ / $ | 0.05 |
Risk Management - Undiscounted
Risk Management - Undiscounted Cash Outflows Relating to Financial Liabilities (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Accounts Payables And Accrued Liabilities | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | $ 5,480 | $ 6,124 |
Accounts Payables And Accrued Liabilities | 1 Year | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 5,480 | 6,124 |
Accounts Payables And Accrued Liabilities | Years 2 and 3 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 0 |
Accounts Payables And Accrued Liabilities | Years 4 and 5 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 0 |
Accounts Payables And Accrued Liabilities | Thereafter | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 0 |
Short-Term Borrowings | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 179 | 115 |
Short-Term Borrowings | 1 Year | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 179 | 115 |
Short-Term Borrowings | Years 2 and 3 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 0 |
Short-Term Borrowings | Years 4 and 5 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 0 |
Short-Term Borrowings | Thereafter | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 0 |
Lease Liabilities | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 4,354 | 4,657 |
Lease Liabilities | 1 Year | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 438 | 426 |
Lease Liabilities | Years 2 and 3 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 712 | 746 |
Lease Liabilities | Years 4 and 5 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 569 | 596 |
Lease Liabilities | Thereafter | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 2,635 | 2,889 |
Long-Term Debt | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 11,257 | 14,594 |
Long-Term Debt | 1 Year | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 313 | 401 |
Long-Term Debt | Years 2 and 3 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 792 | 983 |
Long-Term Debt | Years 4 and 5 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 3,007 | 2,014 |
Long-Term Debt | Thereafter | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 7,145 | 11,196 |
Contingent Payments | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 168 | 438 |
Contingent Payments | 1 Year | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 168 | 271 |
Contingent Payments | Years 2 and 3 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 167 |
Contingent Payments | Years 4 and 5 | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | 0 | 0 |
Contingent Payments | Thereafter | ||
Disclosure of Maturity Analysis for Financial Liabilities [Line Items] | ||
Financial instruments | $ 0 | $ 0 |
Supplementary Cash Flow Infor_3
Supplementary Cash Flow Information - Summary of Supplementary Cash Flow Information (Detail) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure Of Supplementary Cash Flow Information [Abstract] | ||
Total Current Assets | $ 9,708 | $ 12,430 |
Total Current Liabilities | 6,210 | 8,021 |
Working Capital | 3,498 | 4,409 |
Adjusted working capital | 3,700 | 4,700 |
Contingent Payments | $ 164 | $ 263 |
Supplementary Cash Flow Infor_4
Supplementary Cash Flow Information - Non-Cash Working Capital (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure Of Supplementary Cash Flow Information [Line Items] | ||
Accounts Receivable and Accrued Revenues | $ 314 | $ 838 |
Income Tax Receivable | (295) | (58) |
Inventories | 216 | (143) |
Accounts Payable and Accrued Liabilities | (685) | (524) |
Income Tax Payable | (1,112) | 1,000 |
Total Change in Non-Cash Working Capital | (1,562) | 1,113 |
Net Change in Non-Cash Working Capital – Operating Activities | (1,193) | 575 |
Net Change in Non-Cash Working Capital – Investing Activities | (369) | 538 |
Interest Paid | 402 | 647 |
Interest Received | 130 | 78 |
Income Taxes Paid | $ 2,595 | $ 723 |
Supplementary Cash Flow Infor_5
Supplementary Cash Flow Information - Summary of Reconciliation of Liabilities to Cash Flows from Financing Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Beginning balance, short-term borrowings | $ 115 | |
Beginning balance, lease liabilities | 2,836 | $ 2,957 |
Changes From Financing Cash Flows: | ||
Repayment of Long-Term Debt | (1,346) | (4,149) |
Principal Repayment of Leases | (288) | (302) |
Payment for Purchase of Warrants | (711) | 0 |
Non-Cash Changes: | ||
Lease Additions | 57 | 25 |
Ending balance, short term borrowings | 179 | 115 |
Ending balance, lease liabilities | 2,658 | 2,836 |
Dividends Payable | ||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Beginning balance, dividend payable | 9 | 0 |
Non-Cash Changes: | ||
Ending balance, dividend payable | 9 | 9 |
Dividends Payable | Common Shares | ||
Changes From Financing Cash Flows: | ||
Dividends paid | (990) | (682) |
Variable Dividends Paid on Common Shares | (219) | |
Non-Cash Changes: | ||
Dividends declared | 990 | 682 |
Variable Dividends Declared on Common Shares | 219 | |
Dividends Payable | Preference shares | ||
Changes From Financing Cash Flows: | ||
Dividends paid | (36) | (26) |
Non-Cash Changes: | ||
Dividends declared | 36 | 35 |
Warrant Purchase Payable | ||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Beginning balance, warrant payable | 0 | 0 |
Changes From Financing Cash Flows: | ||
Payment for Purchase of Warrants | (711) | |
Finance and Transaction Costs | (2) | |
Non-Cash Changes: | ||
Finance and Transaction Costs | 2 | |
Warrants Purchased and Cancelled | 711 | |
Ending balance, warrant payable | 0 | 0 |
Short-Term Borrowings | ||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Beginning balance, short-term borrowings | 115 | 79 |
Changes From Financing Cash Flows: | ||
Net Issuance (Repayment) of Short-Term Borrowings | 58 | 34 |
Non-Cash Changes: | ||
Exchange Rate Movements and Other | 6 | 2 |
Ending balance, short term borrowings | 179 | 115 |
Long-Term Debt | ||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Beginning balance, long term debt | 8,691 | 12,385 |
Changes From Financing Cash Flows: | ||
Repayment of Long-Term Debt | (1,346) | (4,149) |
Non-Cash Changes: | ||
Net Premium (Discount) on Redemption of Long-Term Debt | (84) | (29) |
Finance and Transaction Costs | (19) | (28) |
Exchange Rate Movements and Other | (134) | 512 |
Ending balance, long term debt | 7,108 | 8,691 |
Lease Liabilities | ||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Beginning balance, lease liabilities | 2,836 | 2,957 |
Changes From Financing Cash Flows: | ||
Principal Repayment of Leases | (288) | (302) |
Non-Cash Changes: | ||
Lease Acquisitions | 33 | |
Lease Additions | 57 | 25 |
Lease Divestitures | (11) | |
Exchange Rate Movements and Other | 31 | 156 |
Ending balance, lease liabilities | $ 2,658 | $ 2,836 |
Commitments and Contingencies -
Commitments and Contingencies - Future Payments for Commitments (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Feb. 28, 2023 | Feb. 15, 2023 | Dec. 31, 2022 | |
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation and storage | $ 24,667 | $ 21,081 | ||
Product Purchases | 617 | 9,358 | ||
Real estate | 898 | 856 | ||
Obligation to fund equity-accounted affiliate | 513 | 623 | ||
Other long term committments | 2,101 | 1,080 | ||
Total Commitments | $ 28,796 | 32,998 | ||
Transportation commitments subject to regulatory approval or approved but not yet in service term | 20 years | |||
Contractual commitments | $ 28,796 | 32,998 | ||
Outstanding letters of credit | 364 | 490 | ||
Transportation commitment | $ 587 | |||
BP-Husky Refining LLC | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Total Payments | $ 538 | |||
HMLP | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Total Commitments | 2,100 | 2,200 | ||
Contractual commitments | 2,100 | 2,200 | ||
Commitments approved and not yet in service | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation commitments | 13,000 | 9,100 | ||
1 Year | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation and storage | 2,018 | 1,747 | ||
Product Purchases | 617 | 1,626 | ||
Real estate | 57 | 48 | ||
Obligation to fund equity-accounted affiliate | 94 | 92 | ||
Other long term committments | 417 | 381 | ||
Total Commitments | 3,203 | 3,894 | ||
Contractual commitments | 3,203 | 3,894 | ||
2 Years | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation and storage | 1,927 | 2,011 | ||
Product Purchases | 0 | 1,509 | ||
Real estate | 57 | 50 | ||
Obligation to fund equity-accounted affiliate | 94 | 105 | ||
Other long term committments | 194 | 90 | ||
Total Commitments | 2,272 | 3,765 | ||
Contractual commitments | 2,272 | 3,765 | ||
3 Years | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation and storage | 1,680 | 1,542 | ||
Product Purchases | 0 | 922 | ||
Real estate | 59 | 50 | ||
Obligation to fund equity-accounted affiliate | 94 | 96 | ||
Other long term committments | 184 | 75 | ||
Total Commitments | 2,017 | 2,685 | ||
Contractual commitments | 2,017 | 2,685 | ||
4 Years | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation and storage | 1,663 | 1,416 | ||
Product Purchases | 0 | 922 | ||
Real estate | 63 | 50 | ||
Obligation to fund equity-accounted affiliate | 89 | 96 | ||
Other long term committments | 175 | 74 | ||
Total Commitments | 1,990 | 2,558 | ||
Contractual commitments | 1,990 | 2,558 | ||
5 Years | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation and storage | 1,641 | 1,360 | ||
Product Purchases | 0 | 922 | ||
Real estate | 58 | 54 | ||
Obligation to fund equity-accounted affiliate | 52 | 91 | ||
Other long term committments | 166 | 65 | ||
Total Commitments | 1,917 | 2,492 | ||
Contractual commitments | 1,917 | 2,492 | ||
Thereafter | ||||
Disclosure Of Commitments And Contingent Liabilities [Line Items] | ||||
Transportation and storage | 15,738 | 13,005 | ||
Product Purchases | 0 | 3,457 | ||
Real estate | 604 | 604 | ||
Obligation to fund equity-accounted affiliate | 90 | 143 | ||
Other long term committments | 965 | 395 | ||
Total Commitments | 17,397 | 17,604 | ||
Contractual commitments | $ 17,397 | $ 17,604 |
Prior Period Revisions (Details
Prior Period Revisions (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | $ 55,474 | $ 71,765 | |
Purchased Product | [1] | 24,715 | 33,958 |
Transportation and Blending | [1] | 10,141 | 11,126 |
Operating | [1] | 6,352 | 5,816 |
Depreciation, Depletion and Amortization | 4,644 | 4,679 | |
Purchased Product, Transportation And Blending, Operating | 50,900 | ||
Oil Sands | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 34,683 | ||
Purchased Product | 4,718 | ||
Gross sales and purchased product | 29,965 | ||
Conventional | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 4,439 | ||
Transportation and Blending | 250 | ||
Gross Sales Less Transportation And Blending | 4,189 | ||
U.S. Refining | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 30,218 | ||
Purchased Product | 26,020 | ||
Gross sales and purchased product | 4,198 | ||
Corporate and Eliminations | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | (8,234) | (7,387) | |
Purchased Product | (6,710) | (5,192) | |
Transportation and Blending | (947) | (1,175) | |
Operating | (539) | (1,023) | |
Depreciation, Depletion and Amortization | $ 107 | 113 | |
Gross sales less purchased product, transportation and blending and operating | 3 | ||
Previously Reported | |||
Disclosure of changes in accounting estimates [line items] | |||
Purchased Product | 33,801 | ||
Transportation and Blending | 11,530 | ||
Operating | 5,569 | ||
Purchased Product, Transportation And Blending, Operating | 50,900 | ||
Previously Reported | Oil Sands | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 34,775 | ||
Purchased Product | 4,810 | ||
Gross sales and purchased product | 29,965 | ||
Previously Reported | Conventional | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 4,332 | ||
Transportation and Blending | 143 | ||
Gross Sales Less Transportation And Blending | 4,189 | ||
Previously Reported | U.S. Refining | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 30,310 | ||
Purchased Product | 26,112 | ||
Gross sales and purchased product | 4,198 | ||
Previously Reported | Corporate and Eliminations | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | (7,464) | ||
Purchased Product | (5,533) | ||
Transportation and Blending | (664) | ||
Operating | (1,270) | ||
Gross sales less purchased product, transportation and blending and operating | 3 | ||
Revisions | |||
Disclosure of changes in accounting estimates [line items] | |||
Purchased Product | 157 | ||
Transportation and Blending | (404) | ||
Operating | 247 | ||
Purchased Product, Transportation And Blending, Operating | 0 | ||
Revisions | Oil Sands | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | (92) | ||
Purchased Product | (92) | ||
Gross sales and purchased product | 0 | ||
Revisions | Conventional | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 107 | ||
Transportation and Blending | 107 | ||
Gross Sales Less Transportation And Blending | 0 | ||
Revisions | U.S. Refining | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | (92) | ||
Purchased Product | (92) | ||
Gross sales and purchased product | 0 | ||
Revisions | Corporate and Eliminations | |||
Disclosure of changes in accounting estimates [line items] | |||
Gross Sales | 77 | ||
Purchased Product | 341 | ||
Transportation and Blending | (511) | ||
Operating | 247 | ||
Gross sales less purchased product, transportation and blending and operating | $ 0 | ||
[1] Comparative periods reflect certain revisions. See Note 39. |