Cover Page
Cover Page | 12 Months Ended |
Dec. 31, 2023 shares | |
Document Information [Line Items] | |
Document Type | 40-F |
Document Registration Statement | false |
Document Annual Report | true |
Current Fiscal Year End Date | --12-31 |
Document Period End Date | Dec. 31, 2023 |
Entity File Number | 001-12138 |
Entity Registrant Name | CANADIAN NATURAL RESOURCES LIMITED |
Entity Incorporation, State or Country Code | A0 |
Entity Address, Address Line One | 2100 |
Entity Address, Address Line Two | 855-2nd Street S.W. |
Entity Address, City or Town | Calgary |
Entity Address, State or Province | AB |
Entity Address, Country | CA |
Entity Address, Postal Zip Code | T2P 4J8 |
City Area Code | 403 |
Local Phone Number | 517-7345 |
Title of 12(b) Security | Common Shares, no par value |
Trading Symbol | CNQ |
Security Exchange Name | NYSE |
Annual Information Form | true |
Audited Annual Financial Statements | true |
Entity Common Stock, Shares Outstanding | 1,072,408,000 |
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] | false |
Entity Central Index Key | 0001017413 |
Document Fiscal Year Focus | 2023 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Business Contact | |
Document Information [Line Items] | |
Contact Personnel Name | CT Corporation System |
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 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Auditor Information [Abstract] | |
Auditor Firm ID | 271 |
Auditor Name | PricewaterhouseCoopers LLP" |
Auditor Location | Calgary, Canada |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Current assets | ||
Cash and cash equivalents | $ 877 | $ 920 |
Accounts receivable | 3,189 | 3,555 |
Inventory | 2,034 | 1,815 |
Prepaids and other | 471 | 215 |
Investments | 525 | 491 |
Current portion of other long-term assets | 71 | 61 |
Current assets | 7,167 | 7,057 |
Non-current assets | ||
Exploration and evaluation assets | 2,208 | 2,226 |
Property, plant and equipment | 64,581 | 64,859 |
Lease assets | 1,458 | 1,447 |
Other long-term assets | 541 | 553 |
Assets | 75,955 | 76,142 |
Current liabilities | ||
Accounts payable | 1,418 | 1,341 |
Accrued liabilities | 3,534 | 4,209 |
Current income taxes payable | 0 | 1,324 |
Current portion of long-term debt | 980 | 404 |
Current portion of other long-term liabilities | 1,503 | 1,373 |
Current liabilities | 7,435 | 8,651 |
Long-term debt | 9,819 | 11,041 |
Other long-term liabilities | 8,686 | 8,161 |
Deferred income taxes | 10,183 | 10,114 |
Liabilities | 36,123 | 37,967 |
SHAREHOLDERS’ EQUITY | ||
Share capital | 10,712 | 10,294 |
Retained earnings | 28,948 | 27,672 |
Accumulated other comprehensive income | 172 | 209 |
Shareholders' equity | 39,832 | 38,175 |
Liabilities and shareholders' equity | $ 75,955 | $ 76,142 |
Consolidated Statements of Earn
Consolidated Statements of Earnings - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Profit or loss [abstract] | |||
Product sales | $ 40,835 | $ 49,530 | $ 32,854 |
Less: royalties | (4,867) | (7,232) | (2,797) |
Revenue | 35,968 | 42,298 | 30,057 |
Expenses | |||
Production | 8,480 | 8,712 | 7,152 |
Transportation, blending and feedstock | 9,302 | 9,973 | 6,604 |
Depletion, depreciation and amortization | 6,413 | 7,353 | 5,724 |
Administration | 452 | 415 | 366 |
Share-based compensation | 491 | 804 | 514 |
Asset retirement obligation accretion | 366 | 281 | 185 |
Interest and other financing expense | 636 | 549 | 711 |
Risk management activities (gain) loss | (2) | (35) | 36 |
Foreign exchange (gain) loss | (279) | 738 | (127) |
Gain on acquisitions | 0 | 0 | (478) |
Income from North West Redwater Partnership | 0 | 0 | (400) |
Gain from investments | (56) | (196) | (141) |
Total expenses | 25,803 | 28,594 | 20,146 |
Earnings before taxes | 10,165 | 13,704 | 9,911 |
Current income tax expense | 1,879 | 2,906 | 1,848 |
Deferred income tax expense (recovery) | 53 | (139) | 399 |
Net earnings | $ 8,233 | $ 10,937 | $ 7,664 |
Net earnings per common share | |||
Net earnings per common share - basic (in CAD per share) | $ 7.54 | $ 9.64 | $ 6.49 |
Net earnings per common share - diluted (in CAD per share) | $ 7.47 | $ 9.52 | $ 6.46 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of comprehensive income [abstract] | |||
Net earnings | $ 8,233 | $ 10,937 | $ 7,664 |
Net change in derivative financial instruments designated as cash flow hedges | |||
Unrealized income, net of taxes of $nil (2022 – $1 million, 2021 – $2 million) | 2 | 4 | 15 |
Reclassification to net earnings, net of taxes of $nil (2022 – $1 million, 2021 – $1 million) | (5) | (6) | (7) |
Net change in derivative financial instruments designated as cash flow hedges | (3) | (2) | 8 |
Foreign currency translation adjustment | |||
Translation of net investment | (34) | 212 | (17) |
Other comprehensive (loss) income, net of taxes | (37) | 210 | (9) |
Comprehensive income | $ 8,196 | $ 11,147 | $ 7,655 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of comprehensive income [abstract] | |||
Unrealized income, tax | $ 0 | $ 1 | $ 2 |
Reclassification to net earnings, tax | $ 0 | $ 1 | $ 1 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) $ in Millions | Total | Share capital | Share capital Common shares | Retained earnings | Retained earnings Common shares | Accumulated other comprehensive income (loss) |
Balance – beginning of year at Dec. 31, 2020 | $ 9,606 | $ 22,766 | $ 8 | |||
Issued upon exercise of stock options | 707 | |||||
Previously recognized liability on stock options exercised for common shares | 139 | |||||
Net earnings | $ 7,664 | 7,664 | ||||
Dividends on common shares | (2,355) | |||||
Purchase of common shares under Normal Course Issuer Bid | $ (284) | $ (1,297) | ||||
Other comprehensive (loss) income, net of taxes | (9) | (9) | ||||
Balance – end of year at Dec. 31, 2021 | 36,945 | 10,168 | 10,168 | 26,778 | (1) | |
Issued upon exercise of stock options | 442 | 442 | ||||
Previously recognized liability on stock options exercised for common shares | 387 | 387 | ||||
Net earnings | 10,937 | 10,937 | ||||
Dividends on common shares | (5,175) | |||||
Purchase of common shares under Normal Course Issuer Bid | (703) | (4,868) | ||||
Other comprehensive (loss) income, net of taxes | 210 | 210 | ||||
Balance – end of year at Dec. 31, 2022 | 38,175 | 10,294 | 10,294 | 27,672 | 209 | |
Issued upon exercise of stock options | 372 | 372 | ||||
Previously recognized liability on stock options exercised for common shares | 435 | 435 | ||||
Net earnings | 8,233 | 8,233 | ||||
Dividends on common shares | (4,028) | |||||
Purchase of common shares under Normal Course Issuer Bid | (3,318) | (389) | (2,929) | $ (2,929) | ||
Other comprehensive (loss) income, net of taxes | (37) | (37) | ||||
Balance – end of year at Dec. 31, 2023 | $ 39,832 | $ 10,712 | $ 10,712 | $ 28,948 | $ 172 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Operating activities | ||||
Net earnings | $ 8,233 | $ 10,937 | $ 7,664 | |
Non-cash items | ||||
Depletion, depreciation and amortization | 6,413 | 7,353 | 5,724 | |
Share-based compensation | 491 | 804 | 514 | |
Asset retirement obligation accretion | 366 | 281 | 185 | |
Unrealized risk management loss (gain) | 12 | (28) | 19 | |
Unrealized foreign exchange (gain) loss | (260) | 852 | (205) | |
Gain on acquisitions | 0 | 0 | (478) | |
Gain from investments | (34) | (182) | (132) | |
Deferred income tax expense (recovery) | 53 | (139) | 399 | |
Realized foreign exchange (gain) loss | [1] | 0 | (62) | 118 |
Proceeds on settlement of cross currency swap | 0 | 89 | 0 | |
Abandonment expenditures | (509) | (449) | (307) | |
Other | 5 | (144) | 13 | |
Net change in non-cash working capital | (2,417) | 79 | 964 | |
Cash flows from operating activities | 12,353 | 19,391 | 14,478 | |
Financing activities | ||||
Repayment of bank credit facilities and commercial paper, net | 0 | (1,156) | (6,151) | |
Repayment of medium-term notes | (416) | (1,498) | 0 | |
Repayment of US dollar debt securities | 0 | (1,356) | (628) | |
Settlement of long-term debt acquired | 0 | 0 | (183) | |
Proceeds on settlement of cross currency swaps | 0 | 69 | 0 | |
Payment of lease liabilities | (285) | (232) | (209) | |
Issue of common shares on exercise of stock options | 372 | 442 | 707 | |
Dividends on common shares | (3,891) | (4,926) | (2,170) | |
Purchase of common shares under Normal Course Issuer Bid | (3,318) | (5,571) | (1,581) | |
Cash flows used in financing activities | (7,538) | (14,228) | (10,215) | |
Investing activities | ||||
Net expenditures on exploration and evaluation assets | (44) | (33) | (1) | |
Net expenditures on property, plant and equipment | (4,865) | (5,103) | (4,492) | |
Proceeds from investment | 0 | 0 | 128 | |
Repayment of North West Redwater Partnership subordinated debt advances | 0 | 0 | 555 | |
Net change in non-cash working capital | 51 | 149 | 107 | |
Cash flows used in investing activities | (4,858) | (4,987) | (3,703) | |
(Decrease) increase in cash and cash equivalents | (43) | 176 | 560 | |
Cash and cash equivalents – beginning of year | 920 | 744 | 184 | |
Cash and cash equivalents – end of year | 877 | 920 | 744 | |
Interest paid on long-term debt, net | 602 | 613 | 672 | |
Income taxes paid (received) | $ 3,317 | $ 3,057 | $ (62) | |
[1] Consists of the realized foreign exchange gain on settlement of cross currency swaps in 2022, and the realized foreign exchange loss on repayment of US dollar debt securities in 2022 and 2021. |
Accounting Policies
Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Accounting Policies | Accounting Policies Canadian Natural Resources Limited (the "Company") is a senior independent crude oil and natural gas exploration, development and production company. The Company’s exploration and production operations are focused in North America, largely in Western Canada; the United Kingdom ("UK") portion of the North Sea; and Côte d’Ivoire and South Africa in Offshore Africa. The Oil Sands Mining and Upgrading segment produces synthetic crude oil through bitumen mining and upgrading operations at Horizon Oil Sands ("Horizon") and through the Company's direct and indirect interest in the Athabasca Oil Sands Project ("AOSP"). Within Western Canada, in the Midstream and Refining segment, the Company maintains certain activities that include pipeline operations, an electricity co-generation system and an investment in the North West Redwater Partnership ("NWRP"), a general partnership formed to upgrade and refine bitumen in the Province of Alberta. The Company was incorporated in Alberta, Canada. The address of its registered office is 2100, 855 - 2 Street S.W., Calgary, Alberta, Canada. The Company’s consolidated financial statements and the related notes have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). The accounting policies adopted by the Company under IFRS are set out below. The Company has consistently applied the same accounting policies throughout all periods presented, except where IFRS permits new accounting standards to be adopted prospectively. Changes in the Company's accounting policies are discussed in note 2. (A) PRINCIPLES OF CONSOLIDATION The consolidated financial statements have been prepared under the historical cost basis, unless otherwise required. The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and wholly owned partnerships. Subsidiaries include all entities over which the Company has control. Subsidiaries are consolidated from the date on which the Company obtains control. They are deconsolidated from the date that control ceases. Certain of the Company’s activities are conducted through joint arrangements in which two or more parties have joint control. Where the Company has determined that it has a direct ownership interest in jointly controlled assets and obligations for the liabilities (a "joint operation"), the assets, liabilities, revenue and expenses related to the joint operation are included in the consolidated financial statements in proportion to the Company’s interest. Where the Company has determined that it has an interest in jointly controlled entities (a "joint venture"), it uses the equity method of accounting. Under the equity method, the Company’s initial and subsequent investments are recognized at cost and subsequently adjusted for the Company’s share of the joint venture’s income or loss, less distributions received. If the Company’s share of the joint venture’s loss equals or exceeds its interest in the joint venture, the Company discontinues recognizing its share of further losses. The Company resumes recognizing profits when its share of profits exceeds the accumulated share of losses not recognized. Joint ventures accounted for using the equity method of accounting are tested for impairment whenever objective evidence indicates that the carrying amount of the investment may not be recoverable. Indications of impairment include a history of losses, significant capital expenditure overruns, liquidity concerns, financial restructuring of the investee or significant adverse changes in the technological, economic or legal environment. The amount of the impairment is measured as the difference between the carrying amount of the investment and the higher of its fair value less costs of disposal and its value in use. Impairment losses are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized. (B) INVENTORY Inventory is primarily comprised of product inventory, materials and supplies and other inventory, including emissions credits, and is carried at the lower of cost and net realizable value. Product inventory is comprised of crude oil held for sale, including pipeline linefill and crude oil stored in floating production, storage and offloading vessels ("FPSO"). Cost of product inventory consists of purchase costs, direct production costs, directly attributable overhead and depletion, depreciation and amortization and is determined on a first-in, first-out basis. Net realizable value for product inventory is determined by reference to forward prices. Cost for materials and supplies consists of purchase costs and is based on a first-in, first-out or an average cost basis. Net realizable value for materials and supplies and other inventory is determined by reference to current market prices. Emissions credit inventory generated in the normal course of business is initially measured in accordance with the Company's accounting policy for government grants. (C) EXPLORATION AND EVALUATION ASSETS Exploration and evaluation ("E&E") assets consist of the Company’s crude oil and natural gas exploration projects that are pending the determination of proved reserves. E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E costs do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore an area. These costs are recognized in net earnings. Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by management, the E&E assets are tested for impairment upon reclassification to property, plant and equipment. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. An E&E asset is derecognized upon disposal or when no future economic benefits are expected to arise from its use. Any gain or loss arising on derecognition of the asset is recognized in net earnings within depletion, depreciation and amortization. E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of the related Cash Generating Units ("CGUs"), aggregated at a segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. (D) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is measured at cost less accumulated depletion and depreciation and recoverability charges. Assets under construction are not depleted or depreciated until available for their intended use. Exploration and Production The cost of an asset comprises its acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Property acquisition costs are comprised of the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant components of an item of property, plant and equipment, including crude oil and natural gas interests, have different useful lives, they are accounted for separately. Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves, except for certain major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future development expenditures required to develop proved reserves. Oil Sands Mining and Upgrading Capitalized costs for the Oil Sands Mining and Upgrading segment are reported separately from the Company’s North America Exploration and Production segment. Capitalized costs include acquisition costs, construction and development costs, overburden removal costs incurred during the initial development of a mine at Horizon and AOSP, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Mine-related costs are depleted using the unit-of-production method based on proved reserves. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from overburden removal activity. Costs of the upgraders and related infrastructure located on the Horizon and AOSP sites are depreciated on the unit-of-production method based on the estimated productive capacity of the respective upgraders and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life ranging from 2 to 20 years. Midstream, Refining and Head Office The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream, refining and head office assets. Midstream and Refining assets are depreciated on a straight-line basis over their estimated useful lives ranging from 5 to 30 years. Head office assets are depreciated on a declining balance basis. Useful lives The depletion rates and expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes in depletion rates and useful lives accounted for prospectively. Derecognition A property, plant and equipment asset is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is recognized in net earnings within depletion, depreciation and amortization. Major maintenance expenditures Inspection costs associated with major turnarounds are capitalized and depreciated over the period to the next major turnaround. Maintenance costs are expensed as incurred. Impairment The Company assesses property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into CGUs, which are the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGU's recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and a recoverability charge is taken through depletion, depreciation and amortization expense. In subsequent periods, an assessment is made at each reporting date to determine whether there is any indication that previously recognized recoverability charges may no longer exist or may have decreased. If such indication exists, the recoverable amount is re-estimated and the net carrying amount of the asset is increased to its revised recoverable amount. The revised recoverable amount cannot exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, had no recoverability charge been recognized for the asset in prior periods. A reversal of a recoverability charge is recognized in net earnings. After a reversal, the depletion, depreciation and amortization charge is adjusted in future periods to allocate the asset’s revised carrying amount over its remaining useful life. (E) BUSINESS COMBINATIONS Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair value of the net assets acquired is recognized as an asset. Any excess of the fair value of the net assets acquired over the consideration paid is recognized in net earnings. (F) LEASES The Company recognizes a lease asset and a lease liability at the commencement date of the lease contract. The lease asset is initially measured at cost. The cost of a lease asset includes the amount of the initial measurement of the lease liability, lease payments made prior to the commencement date, initial direct costs and estimates of the asset retirement obligation, if any. Subsequent to initial recognition, the lease asset is depreciated using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term. Lease liabilities are initially measured at the present value of lease payments discounted at the rate implicit in the lease, or if not readily determinable, the Company's incremental borrowing rate. Lease liabilities are remeasured if there are changes in the lease term or if the Company changes its assessment of whether it is reasonably certain it will exercise a purchase, extension or termination option. Lease liabilities are also remeasured if there are changes in the estimate of the amounts payable under the lease due to changes in indices or rates, or residual value guarantees. Lease assets are reported in a separate caption in the consolidated balance sheet. Lease liabilities are reported within other long-term liabilities in the consolidated balance sheet. Where the Company acts as the operator of a joint operation, the Company recognizes 100% of the related lease asset and lease liability. As the Company recovers its joint operation partners' share of the costs of the lease contract, these recoveries are recognized as other income in the consolidated statements of earnings. (G) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on all of its property, plant and equipment and certain exploration and evaluation assets based on current legislation and operating practices. Provisions for asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Provisions are measured at the present value of management’s best estimate of expenditures required to settle the obligation as at the date of the balance sheets. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense, whereas changes due to discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against the provision. (H) FOREIGN CURRENCY TRANSLATION Functional and presentation currency Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the currency of the primary economic environment in which the subsidiary operates (the "functional currency"). When the Company disposes of its entire interest in a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings. (I) REVENUE RECOGNITION AND COSTS OF GOODS SOLD Revenue from the sale of crude oil and NGLs and natural gas products is recognized when performance obligations in the sales contract are satisfied and it is probable that the Company will collect the consideration to which it is entitled. Performance obligations are generally satisfied at the point in time when the product is delivered to a location specified in a contract and control passes to the customer. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. Contracts for sale of the Company’s products generally have terms of less than a year, with certain contracts extending beyond one year. Contracts in North America generally specify delivery of crude oil and NGLs and natural gas throughout the term of the contract. Contracts in the North Sea and Offshore Africa generally specify delivery of crude oil at a point in time. Sales of the Company’s crude oil and NGLs and natural gas products to customers are made pursuant to contracts based on prevailing commodity pricing at or near the time of delivery and volumes of product delivered. Revenues are typically collected in the month following delivery and accordingly, the Company has elected to apply the practical expedient to not adjust consideration for the effects of a financing component. Purchases and sales of crude oil and NGLs and natural gas with the same counterparty, made to facilitate sales to customers or potential customers, that are entered into in contemplation of one another, are combined and recorded as non-monetary exchanges and measured at the net settlement amount. Revenue in the consolidated statement of earnings represents the Company’s share of product sales net of royalty payments to governments and other mineral interest owners. The Company discloses the disaggregation of revenues from sales of crude oil and NGLs and natural gas in the segmented information in note 22. Related costs of goods sold are comprised of production, transportation, blending and feedstock, and depletion, depreciation and amortization expenses. These amounts have been separately presented in the consolidated statements of earnings. (J) PRODUCTION SHARING CONTRACTS Production generated from Côte d’Ivoire in Offshore Africa is shared under the terms of various Production Sharing Contracts ("PSCs"). Product sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the respective government state oil companies (the "Governments"). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated to royalty expense and current income tax expense in accordance with the terms of the respective PSCs. (K) INCOME TAX The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases. Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected to apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise on the initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the transaction, affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on possible future distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the Company and it is probable that a distribution will not be made in the foreseeable future, or when distributions can be made without incurring income taxes. Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is no longer probable that sufficient future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different periods, using income tax rates that are substantively enacted at each reporting date. (L) SHARE-BASED COMPENSATION The Company’s Stock Option Plan (the "Option Plan") provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are remeasured each reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the Black-Scholes valuation model under a graded vesting method. Expected volatility is estimated based on historic results. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability associated with the stock options are recorded as share capital. The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined by individual employee performance and the extent to which certain other performance measures are met. PSUs vest three years from original grant date. The liability for PSUs is initially measured in reference to the Company's stock price and the number of awards expected to vest and is remeasured at each reporting period for changes in the fair value of the liability. The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term assets. (M) FINANCIAL INSTRUMENTS The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost; financial liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest method. Cash and cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are solely comprised of payments of principal and interest. Investments in publicly traded shares are classified as fair value through profit or loss. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss. Financial assets and liabilities are also categorized using a three-level hierarchy that reflects the significance of the inputs used in making fair value measurements for these assets and liabilities. The fair values of financial assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values of financial assets and liabilities in Level 2 are based on inputs other than Level 1 quoted prices that are observable for the asset or liability either directly (as prices) or indirectly (derived from prices). The fair values of Level 3 financial assets and liabilities are not based on observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability. Transaction costs in respect of financial instruments at fair value through profit or loss are recognized in net earnings. Transaction costs in respect of other financial instruments are included in the initial measurement of the financial instrument. Impairment of financial assets At each reporting date, on a forward looking basis, the Company assesses the expected credit losses associated with its financial assets carried at amortized cost. Expected credit losses are measured as the difference between the cash flows that are due to the Company and the cash flows that the Company expects to receive, discounted at the effective interest rate determined at initial recognition. For trade accounts receivable, the Company applies the simplified approach permitted by IFRS 9, which requires expected lifetime credit losses to be recognized from initial recognition of the receivables. To measure expected credit losses, accounts receivable are grouped based on the number of days the receivables have been outstanding and internal credit assessments of the customers. Credit risk for longer-term receivables is assessed based on an external credit rating of the counterparty. For longer-term receivables with credit risk that has not increased significantly since the date of recognition, the Company measures the expected credit loss as the 12-month expected credit loss. Changes in the provision for expected credit loss are recognized in net earnings. (N) RISK MANAGEMENT ACTIVITIES The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis. The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural gas commodity price contracts are recognized in risk management activities in net earnings. Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized in risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are recognized in risk management activities in net earnings. Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred under accumulated other comprehensive income and amortized into net earnings in the periods in which the underlying hedged items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net earnings. Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in risk management activities in net earnings. (O) GOVERNMENT GRANTS The Company receives or is eligible for government grants, including emissions credits. Government grants are recognized in net earnings when there is reasonable assurance that the Company will comply with the conditions attached to the grant and the grant will be received. Emissions performance and offset credits generated under the Alberta Technology Innovation and Emissions Reduction (“TIER”) regulation are initially recorded at the value prescribed by the Alberta TIER fund compliance rates in effect at the time the credits are recognized. (P) PER COMMON SHARE AMOUNTS The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in either cash or shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of cash settlement or share settlement under the treasury stock method. (Q) SHARE CAPITAL Common shares are classified as equity. Costs directly attributable to the issue of new shares or options are included in equity as a deduction from proceeds, net of tax. When the Company acquires its own common shares, share capital is reduced by the average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as a reduction of retained earnings. Shares are cancelled upon purchase. |
Changes in Accounting Policies
Changes in Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Changes in Accounting Policies | Changes in Accounting Policies In May 2023, the IASB issued amendments to IAS 12 "Income Taxes" related to the accounting for deferred taxes arising in those jurisdictions implementing the Organization for Economic Co-operation and Development's Pillar Two model rules ("Pillar Two Legislation"). The amendments were effective immediately and adopted in the second quarter of 2023. Pillar Two Legislation did not have a significant impact on the Company’s financial results in 2023, and based on legislation substantively enacted to date in jurisdictions in which the Company currently operates, is not expected to have a significant impact on the Company's results in future periods. In May 2021, the IASB issued amendments to IAS 12 "Income Taxes" to require companies to recognize deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. In February 2021, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to require companies to disclose their material accounting policy information rather than their significant accounting policies. To support this amendment the IASB also amended IFRS Practice Statement 2 "Making Materiality Judgements". The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. In January 2020, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to clarify that liabilities are classified as either current or non-current, depending on the existence of the substantive right at the end of the reporting period for an entity to defer settlement of the liability for at least twelve months after the reporting period. In October 2022, the IASB issued further amendments to specify that the classification of debt as current or non-current at the reporting date is not affected by covenants to be complied with after the reporting date, and added disclosure requirements about these covenants. All amendments are effective January 1, 2024 with early adoption permitted. The amendments are required to be adopted retrospectively. These amendments have no impact on the Company's consolidated financial statements. |
Accounting Standards Issued But
Accounting Standards Issued But Not Yet Applied | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Accounting Standards Issued But Not Yet Applied | Changes in Accounting Policies In May 2023, the IASB issued amendments to IAS 12 "Income Taxes" related to the accounting for deferred taxes arising in those jurisdictions implementing the Organization for Economic Co-operation and Development's Pillar Two model rules ("Pillar Two Legislation"). The amendments were effective immediately and adopted in the second quarter of 2023. Pillar Two Legislation did not have a significant impact on the Company’s financial results in 2023, and based on legislation substantively enacted to date in jurisdictions in which the Company currently operates, is not expected to have a significant impact on the Company's results in future periods. In May 2021, the IASB issued amendments to IAS 12 "Income Taxes" to require companies to recognize deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. In February 2021, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to require companies to disclose their material accounting policy information rather than their significant accounting policies. To support this amendment the IASB also amended IFRS Practice Statement 2 "Making Materiality Judgements". The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. In January 2020, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to clarify that liabilities are classified as either current or non-current, depending on the existence of the substantive right at the end of the reporting period for an entity to defer settlement of the liability for at least twelve months after the reporting period. In October 2022, the IASB issued further amendments to specify that the classification of debt as current or non-current at the reporting date is not affected by covenants to be complied with after the reporting date, and added disclosure requirements about these covenants. All amendments are effective January 1, 2024 with early adoption permitted. The amendments are required to be adopted retrospectively. These amendments have no impact on the Company's consolidated financial statements. |
Critical Accounting Estimates a
Critical Accounting Estimates and Judgements | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Critical Accounting Estimates and Judgements | Critical Accounting Estimates and Judgements The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below. (A) CRUDE OIL AND NATURAL GAS RESERVES Purchase price allocations, depletion, depreciation and amortization, asset retirement obligations, and amounts used in impairment calculations are based on estimates of crude oil and natural gas reserves. Reserves estimates are based on estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures, all of which are subject to many uncertainties, interpretations and judgements including the potential impact of climate related matters and in accordance with related government regulations. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information. (B) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on its property, plant and equipment based on current legislation and operating practices. Estimated future costs include assumptions of dates of future abandonment and technological advances and estimates of future inflation rates and discount rates. Actual costs may vary from the estimated provision due to changes in environmental legislation, the impact of inflation, changes in technology, changes in operating practices, revisions to work scope, changes in the date of abandonment due to changes in reserves life, and the potential impact of climate related matters and in accordance with related government regulations. These differences may have a material impact on the estimated provision. (C) INCOME TAXES The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be due. (D) FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility, interest rate yield curves and foreign exchange rates. (E) PURCHASE PRICE ALLOCATIONS Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation, and amortization expense and impairment tests. (F) SHARE-BASED COMPENSATION The Company has made various assumptions in estimating the fair values of stock options granted under its Option Plan, including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the estimated fair value of the liability. (G) IDENTIFICATION OF CGUs CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, shared infrastructures, and the way in which management monitors the Company’s operations. (H) IMPAIRMENT OF ASSETS The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGUs' or the assets' fair value less costs of disposal and its value in use. These calculations require the use of estimates and assumptions and are subject to change as new information becomes available, including information on future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and operating costs, after-tax discount rates (currently ranging from 10% to 12%), and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs. (I) LEASES Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility. To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit in the lease is not readily determinable. (J) CONTINGENCIES Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a future event. The assessment of contingencies requires the application of judgements and estimates including the determination of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows required to settle the contingency. |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2023 | |
Inventories [Abstract] | |
Inventory | Inventory 2023 2022 Product inventory $ 546 $ 611 Materials, supplies and other 1,488 1,204 $ 2,034 $ 1,815 During 2023, approximately $29 billion of purchased and produced inventory was recorded as expense (2022 – approximately $33 billion). |
Exploration and Evaluation Asse
Exploration and Evaluation Assets | 12 Months Ended |
Dec. 31, 2023 | |
Exploration For And Evaluation Of Mineral Resources [Abstract] | |
Exploration and Evaluation Assets | Exploration and Evaluation Assets Exploration and Production Oil Sands Mining and Upgrading Total North America North Sea Offshore Africa Cost At December 31, 2021 $ 2,057 $ — $ 91 $ 102 $ 2,250 Additions/Acquisitions 41 — 5 — 46 Transfers to property, plant and equipment (71) — — — (71) Derecognitions and other (1) — — — (1) Foreign exchange adjustments — — 2 — 2 At December 31, 2022 2,026 — 98 102 2,226 Additions/Acquisitions 45 — 3 — 48 Transfers to property, plant and equipment (38) — — (25) (63) Derecognitions and other (2) — — — (2) Foreign exchange adjustments — — (1) — (1) At December 31, 2023 $ 2,031 $ — $ 100 $ 77 $ 2,208 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2023 | |
Property, plant and equipment [abstract] | |
Property, Plant and Equipment | Property, Plant and Equipment Exploration and Production Oil Sands Mining and Upgrading Midstream and Refining Head Office Total North America North Sea Offshore Africa Cost At December 31, 2021 $ 77,834 $ 7,438 $ 3,980 $ 46,856 $ 466 $ 508 $ 137,082 Additions/Acquisitions 3,564 304 75 1,380 8 25 5,356 Transfers from exploration and evaluation assets 71 — — — — 71 Derecognitions (1) (394) (1) — (469) — — (864) Disposals — — — (35) — — (35) Foreign exchange adjustments and other — 517 277 — — 3 797 At December 31, 2022 81,075 8,258 4,332 47,732 474 536 142,407 Additions/Acquisitions 2,951 558 187 2,088 10 30 5,824 Transfers from exploration and evaluation assets 38 — — 25 — — 63 Derecognitions (1) (581) — — (470) — — (1,051) Foreign exchange adjustments and other — (210) (110) — — — (320) At December 31, 2023 $ 83,483 $ 8,606 $ 4,409 $ 49,375 $ 484 $ 566 $ 146,923 Accumulated depletion and depreciation At December 31, 2021 $ 52,732 $ 5,951 $ 2,923 $ 8,499 $ 183 $ 394 $ 70,682 Expense 3,502 117 148 1,684 15 23 5,489 Derecognitions (1) (394) (1) — (469) — — (864) Disposals — — — (2) — — (2) Recoverability charge — 1,620 — — — — 1,620 Foreign exchange adjustments and other (5) 419 206 — — 3 623 At December 31, 2022 55,835 8,106 3,277 9,712 198 420 77,548 Expense 3,592 40 177 1,856 15 24 5,704 Derecognitions (1) (581) — — (470) — — (1,051) Recoverability charge — 436 — — — — 436 Foreign exchange adjustments and other (6) (200) (96) 7 — — (295) At December 31, 2023 $ 58,840 $ 8,382 $ 3,358 $ 11,105 $ 213 $ 444 $ 82,342 Net book value At December 31, 2023 $ 24,643 $ 224 $ 1,051 $ 38,270 $ 271 $ 122 $ 64,581 At December 31, 2022 $ 25,240 $ 152 $ 1,055 $ 38,020 $ 276 $ 116 $ 64,859 (1) An asset is derecognized when no future economic benefits are expected to arise from its continued use or disposal. Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked crude oil reserves as at December 31, 2022 and is accelerating abandonment. As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash charge of $651 million (after-tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge of $1,620 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $969 million. As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a non-cash charge of $113 million (after-tax) related to an increase in its estimate of the future abandonment costs for the Ninian field in the North Sea. The non-cash charge is comprised of a recoverability charge of $436 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $323 million. The Company’s estimate of its asset retirement obligation liability, including the Ninian field recoverability charge and associated tax recoveries, is subject to revision in future periods as abandonment efforts progress. As at December 31, 2023, the Company completed its normal course assessment of the recoverability of its other property, plant and equipment and exploration and evaluation assets, and determined the carrying amounts of all its cash generating units to be recoverable. As at December 31, 2023, property, plant and equipment included project costs, not subject to depletion and depreciation, of $191 million in the Oil Sands Mining and Upgrading segment (2022 – $162 million in the Oil Sands Mining and Upgrading segment). ACQUISITIONS IN 2022 & 2021 During 2022, the Company acquired a number of crude oil and natural gas properties in the North America Exploration and Production segment for net cash consideration of $513 million and assumed associated asset retirement obligations of $11 million. No net deferred income tax liabilities were recognized and no pre-tax gains were recognized on these transactions. During 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm Resources Ltd. ("Storm") for total cash consideration of $771 million. In connection with the acquisition the Company assumed certain product transportation and processing commitments (note 20). During 2021, the Company completed two acquisitions of natural gas producing assets and related processing infrastructure in the Montney region of British Columbia, including property, plant and equipment assets of $257 million and exploration and evaluation assets of $13 million, for cash consideration of $131 million. In connection with the acquisitions, the Company assumed asset retirement obligations of $58 million, other liabilities of $65 million, and recognized a deferred tax asset of $462 million. A gain of $478 million was recognized as a result of the acquisitions, representing the excess of the fair value of the net assets acquired compared with the total purchase consideration. Acquisitions in the comparative years have been accounted for as business combinations using the acquisition method of accounting. Gains reported on the acquisitions represent the excess of the fair value of the net assets acquired compared to the total purchase consideration. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of leases [Abstract] | |
Leases | Leases LEASE ASSETS Product transportation and storage Field equipment and power Offshore vessels and equipment Office leases and other Total At December 31, 2021 $ 974 $ 354 $ 99 $ 81 $ 1,508 Additions 44 110 28 — 182 Depreciation (106) (86) (31) (21) (244) Foreign exchange and other — (1) 1 1 1 At December 31, 2022 912 377 97 61 1,447 Additions 27 218 49 23 317 Depreciation (98) (111) (45) (19) (273) Foreign exchange and other (1) (2) (30) — (33) At December 31, 2023 $ 840 $ 482 $ 71 $ 65 $ 1,458 LEASE ASSETS, BY SEGMENT As at December 31, 2023 and 2022, the Company had the following lease assets by segment: 2023 2022 Exploration and Production North America $ 280 $ 277 North Sea 18 1 Offshore Africa 119 98 Oil Sands Mining and Upgrading 1,001 1,015 Head Office 40 56 $ 1,458 $ 1,447 LEASE LIABILITIES The Company measures its lease liabilities at the discounted value of its lease payments during the lease term. Lease liabilities at December 31, 2023 and 2022, were as follows: 2023 2022 Lease liabilities $ 1,555 $ 1,540 Less: current portion 298 244 $ 1,257 $ 1,296 In addition to the lease assets disclosed above, on an ongoing basis the Company enters into short-term leases related to its Exploration and Production and Oil Sands Mining and Upgrading activities. Other amounts included in net earnings and cash flows during 2023 and 2022 are provided below: 2023 2022 Expenses relating to short-term leases (1) $ 403 $ 410 Interest expense on lease liabilities $ 64 $ 60 Variable lease payments not included in the measurement of lease liabilities $ 59 $ 49 Total cash outflows for leases (2) $ 1,325 $ 1,204 (1) During 2023, the Company capitalized $514 million (2022 – $453 million) of short-term leases as additions to property, plant and equipment. (2) Comprised of cash outflows relating to lease liabilities, short-term leases, and variable lease payments. |
Investments
Investments | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Investments | Investments As at December 31, 2023 and 2022, the Company had the following investment: 2023 2022 Investment in PrairieSky Royalty Ltd. $ 525 $ 491 INVESTMENT IN PRAIRIESKY ROYALTY LTD. The Company’s 22.6 million common shares investment in PrairieSky Royalty Ltd. ("PrairieSky") does not constitute significant influence, and is accounted for at fair value through profit or loss, measured at each reporting date. As at December 31, 2023 the market price per common share was $23.20 (December 31, 2022 – $21.70; December 31, 2021 – $13.63). As at December 31, 2023, the Company’s investment in PrairieSky was classified as a current asset. PrairieSky is in the business of acquiring and managing oil and gas royalty income assets through indirect third-party oil and gas development. The gain from the investment in PrairieSky was comprised as follows: 2023 2022 2021 Gain from investment $ (34) $ (182) $ (81) Dividend income (22) (14) (7) $ (56) $ (196) $ (88) INVESTMENT IN INTER PIPELINE LTD. During 2021, in accordance with a third-party offer to purchase, the Company elected to take total cash proceeds of $128 million, or $20.00 per common share, in exchange for its 6.4 million common shares investment in Inter Pipeline Ltd ("Inter Pipeline"). In 2021, the Company also recognized a $53 million gain from the investment in Inter Pipeline comprised of a $51 million fair value gain on the investment and $2 million of dividend income. The Company's investment did not constitute significant influence, and was accounted for at fair value through profit or loss, measured at each reporting date. |
Other Long-Term Assets
Other Long-Term Assets | 12 Months Ended |
Dec. 31, 2023 | |
Subclassifications of assets, liabilities and equities [abstract] | |
Other Long-Term Assets | Other Long-Term Assets 2023 2022 Long-term prepayments, contracts and other (1) $ 279 $ 269 Prepaid cost of service toll 179 199 Long-term inventory 141 137 Risk management (note 19) 13 9 612 614 Less: current portion 71 61 $ 541 $ 553 (1) Includes physical product sales contracts assumed in acquisitions in prior periods, accrued interest on the deferred PRT recovery, and the unamortized portion of the Company's share bonus program. INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP The Company has a 50% equity investment in North West Redwater Partnership ("NWRP"). NWRP operates a 50,000 barrels per day bitumen upgrader and refinery that processes approximately 12,500 barrels per day (25% toll payer) of bitumen feedstock for the Company and 37,500 barrels per day (75% toll payer) of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC"), an agent of the Government of Alberta. The Company is unconditionally obligated to pay its 25% pro rata share of the debt component of the monthly fee-for-service toll over the 40-year tolling period until 2058 (note 20). Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment (note 22). On June 30, 2021, the equity partners together with the toll payers, agreed to optimize the structure of NWRP to better align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest remained unchanged. Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048 to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, and issued lower cost senior secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the Company received a $400 million distribution from NWRP during 2021. To facilitate the Optimization Transaction, NWRP issued $500 million of 1.20% series L senior secured bonds due December 2023, $500 million of 2.00% series M senior secured bonds due December 2026, $1,000 million of 2.80% series N senior secured bonds due June 2031, and $600 million of 3.75% series O senior secured bonds due June 2051. During 2023, NWRP repaid the $500 million of 1.20% series L senior secured bonds. As at December 31, 2023, NWRP had borrowings of $2,559 million under the syndicated credit facility (December 31, 2022 – $2,318 million), and borrowings of $77 million under its short-term demand operating facility (December 31, 2022 – $nil). During 2023, NWRP's syndicated credit facility was reduced by $60 million to $3,115 million (2022 – $3,175 million) following the repayment and cancellation of the portion of the non-revolving credit facility that matured in June 2023. NWRP's syndicated credit facility is comprised of a $2,175 million revolving credit facility, with $118 million maturing June 2024 and the remainder maturing June 2025, and a $940 million non-revolving credit facility maturing June 2025. During 2022, NWRP entered into a $150 million facility to support letters of credit. The assets, liabilities, partners’ equity, product sales and equity (loss) income related to NWRP at December 31, 2023 and 2022 were comprised as follows: 2023 2022 Current assets $ 349 $ 257 Non-current assets $ 10,508 $ 10,729 Current liabilities $ 1,054 $ 849 Non-current liabilities $ 10,913 $ 11,239 Partners’ equity $ (1,110) $ (1,102) Partners’ equity at Company's 50% interest $ (555) $ (551) Revenue (1) $ 1,527 $ 1,267 Net (loss) income (2) $ (8) $ 22 (1) Included in NWRP's revenue for 2023 is $335 million (2022 – $317 million) related to the Company's 25% share of the refining toll. (2) Included in the net (loss) income for 2023 is the impact of depreciation and amortization expense of $387 million (2022 – $245 million) and interest and other financing expense of $500 million (2022 – $422 million). The carrying value of the Company’s interest in NWRP is $nil, and as at December 31, 2023, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $555 million (2022 – $551 million). The Company's unrecognized equity loss from NWRP for 2023 was $4 million (2022 – recovery of the unrecognized share of the equity loss of $11 million; 2021 – unrecognized equity loss of $9 million and partnership distributions were $400 million). |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Long-Term Debt | Long-Term Debt 2023 2022 Canadian dollar denominated debt, unsecured Medium-term notes 1.45% debentures due November 16, 2023 $ — $ 404 3.55% debentures due June 3, 2024 320 332 3.42% debentures due December 1, 2026 441 441 2.50% debentures due January 17, 2028 225 225 4.85% debentures due May 30, 2047 300 300 1,286 1,702 US dollar denominated debt, unsecured US dollar debt securities 3.80% due April 15, 2024 (US$500 million) 660 677 3.90% due February 1, 2025 (US$600 million) 792 812 2.05% due July 15, 2025 (US$600 million) 792 812 3.85% due June 1, 2027 (US$1,250 million) 1,651 1,692 2.95% due July 15, 2030 (US$500 million) 660 677 7.20% due January 15, 2032 (US$400 million) 528 541 6.45% due June 30, 2033 (US$350 million) 462 474 5.85% due February 1, 2035 (US$350 million) 462 474 6.50% due February 15, 2037 (US$450 million) 594 609 6.25% due March 15, 2038 (US$1,100 million) 1,453 1,488 6.75% due February 1, 2039 (US$400 million) 528 541 4.95% due June 1, 2047 (US$750 million) 991 1,015 9,573 9,812 Long-term debt before transaction costs and original issue discounts, net 10,859 11,514 Less: original issue discounts, net (1) 11 13 transaction costs (1) (2) 49 56 10,799 11,445 Less: current portion of long-term debt (1) (2) 980 404 $ 9,819 $ 11,041 (1) The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt. (2) Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. BANK CREDIT FACILITIES AND COMMERCIAL PAPER As at December 31, 2023, the Company had undrawn bank credit facilities of $5,450 million. Details of these facilities are described below. The Company also has certain other dedicated credit facilities supporting letters of credit. ▪ a $100 million demand credit facility; ▪ a $500 million revolving credit facility, maturing February 2025; ▪ a $2,425 million revolving syndicated credit facility, maturing June 2025; and ▪ a $2,425 million revolving syndicated credit facility, maturing June 2027. During 2023, the Company extended its $2,425 million revolving syndicated credit facility, originally maturing June 2024, to June 2027. During 2022, the Company repaid and cancelled the $1,150 million non-revolving term credit facility maturing February 2023. During 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations. Borrowings under the Company's revolving term credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, SOFR, US base rate or Canadian prime rate. During 2022, the Company repaid and cancelled $500 million of the non-revolving portion of the term credit facility, amended the remaining facility to a $500 million revolving credit facility, and extended maturity from February 2023 to February 2024. During 2023, the Company extended its $500 million revolving credit facility from February 2024 to February 2025. The Company’s borrowings under its US commercial paper program are authorized up to a maximum US$2,500 million. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program. The Company’s weighted average interest rate on total long-term debt outstanding for the year ended December 31, 2023 was 4.8% (December 31, 2022 – 4.3%). As at December 31, 2023, letters of credit and guarantees aggregating to $446 million were outstanding (December 31, 2022 – $637 million). MEDIUM-TERM NOTES During 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expires in August 2025, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. During 2023, the Company repaid $405 million of 1.45% medium-term notes. During 2022, the Company repaid $1,000 million of 3.31% medium-term notes. During 2022, the Company repaid through market purchases $95 million of 1.45% medium-term notes due November 2023, $169 million of 3.55% medium-term notes due June 2024, $159 million of 3.42% medium-term notes due December 2026, and $75 million of 2.50% medium-term notes due January 2028. US DOLLAR DEBT SECURITIES During 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expires in August 2025, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023. SCHEDULED DEBT REPAYMENTS Scheduled debt repayments are as follows: Year Repayment 2024 $ 980 2025 $ 1,584 2026 $ 441 2027 $ 1,651 2028 $ 225 Thereafter $ 5,978 |
Other Long-Term Liabilities
Other Long-Term Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Subclassifications of assets, liabilities and equities [abstract] | |
Other Long-Term Liabilities | Other Long-Term Liabilities 2023 2022 Asset retirement obligations $ 7,690 $ 6,908 Lease liabilities (note 8) 1,555 1,540 Share-based compensation 780 832 Transportation and processing contracts (1) 87 159 Risk management (note 19) 4 3 Other 73 92 10,189 9,534 Less: current portion 1,503 1,373 $ 8,686 $ 8,161 (1) Product transportation and processing obligations assumed from acquisitions in prior years (note 7). ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and discounted using a weighted average discount rate of 5.2% (2022 – 5.6%; 2021 – 4.0%) and inflation rates of up to 2% (December 31, 2022 – up to 2%). Reconciliations of the discounted asset retirement obligations were as follows: 2023 2022 2021 Balance – beginning of year $ 6,908 $ 6,806 $ 5,861 Liabilities incurred 25 20 5 Liabilities acquired, net — 11 76 Liabilities settled (509) (449) (307) Asset retirement obligation accretion 366 281 185 Revision of cost, inflation and timing estimates (1) 621 897 508 Impact of regulatory changes (2) — 982 1,208 Change in discount rates 314 (1,698) (723) Foreign exchange adjustments (35) 58 (7) Balance – end of year 7,690 6,908 6,806 Less: current portion 634 495 249 $ 7,056 $ 6,413 $ 6,557 (1) Includes normal course revisions of cost, inflation and timing estimates, as well as revisions related to the acceleration of the abandonment and subsequent cost estimate increases on future abandonment at the Ninian field in the North Sea in 2022 and 2023. (2) Reflects changes to the estimated timing of settlement of the Company's asset retirement obligations due to provincial regulatory changes in Alberta, British Columbia and Saskatchewan in 2022 and 2021. Segmented Asset Retirement Obligations 2023 2022 Exploration and Production North America $ 4,471 $ 4,326 North Sea 1,441 1,011 Offshore Africa 165 143 Oil Sands Mining and Upgrading 1,612 1,427 Midstream and Refining 1 1 $ 7,690 $ 6,908 SHARE-BASED COMPENSATION The liability for share-based compensation includes costs incurred under the Company’s Option and PSU plans. The Company’s Option Plan provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The PSU plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined with reference to the value of the Company's shares, and by individual employee performance and the extent to which certain other performance measures are met. The Company recognizes a liability for potential cash settlements under these plans. The current portion of the liability represents the maximum amount of the liability payable within the next twelve month period if all vested stock options and PSUs are settled in cash. 2023 2022 2021 Balance – beginning of year $ 832 $ 489 $ 160 Share-based compensation expense 491 804 514 Cash payment for stock options surrendered and PSUs vested (110) (79) (48) Transferred to common shares (435) (387) (139) Other 2 5 2 Balance – end of year 780 832 489 Less: current portion 538 559 329 $ 242 $ 273 $ 160 Included within share-based compensation liability as at December 31, 2023 was $96 million (2022 – $127 million; 2021 – $90 million) related to PSUs granted to certain executive employees. The fair value of stock options outstanding was estimated using the Black-Scholes valuation model with the following weighted average assumptions: 2023 2022 2021 Fair value $ 35.93 $ 32.96 $ 16.98 Share price $ 86.81 $ 75.19 $ 53.45 Expected volatility 30.9% 35.8% 35.5% Expected dividend yield 4.6% 4.5% 4.4% Risk free interest rate 3.6% 3.8% 1.1% Expected forfeiture rate 5.4% 5.0% 4.7% Expected stock option life (1) 4.2 years 4.2 years 4.2 years (1) At original time of grant. The intrinsic value of vested stock options at December 31, 2023 was $164 million (2022 – $208 million; 2021 – $112 million). |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Income Taxes | Income Taxes The provision for income tax was as follows: Expense (recovery) 2023 2022 2021 Current corporate income tax – North America (1) $ 1,853 $ 2,789 $ 1,841 Current corporate income tax – North Sea (6) 69 7 Current corporate income tax – Offshore Africa 73 74 21 Current PRT (2) – North Sea (58) (42) (34) Other taxes 17 16 13 Current income tax 1,879 2,906 1,848 Deferred corporate income tax 267 302 399 Deferred PRT (2) – North Sea (214) (441) — Deferred income tax 53 (139) 399 Income tax $ 1,932 $ 2,767 $ 2,247 (1) Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments. (2) Petroleum Revenue Tax. As at December 31, 2022, the Company recognized deferred tax recoveries comprised of a deferred corporate income tax recovery of $528 million and a deferred PRT recovery of $441 million in connection with the Company's de-booking of its crude oil reserves and acceleration of the abandonment at the Ninian field in the North Sea (note 7). As at December 31, 2023, the Company recognized deferred tax recoveries comprised of a deferred corporate income tax recovery of $118 million and a deferred PRT recovery of $205 million in connection with the increase in the Company's estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea (note 7). The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax rates to earnings before taxes. The reasons for the difference are as follows: 2023 2022 2021 Canadian statutory income tax rate 23.3% 23.2% 23.2% Income tax provision at statutory rate $ 2,364 $ 3,180 $ 2,298 Effect on income taxes of: UK PRT and other taxes (255) (467) (21) Impact of UK PRT and other taxes on corporate income tax 105 190 11 Foreign and domestic tax rate differentials (104) (203) (11) Non-taxable portion of capital gains (35) 65 (26) Stock options exercised for common shares 91 159 98 Non-taxable gain on corporate acquisitions — — (110) Revisions arising from prior year tax filings (174) (186) 16 Change in unrecognized capital loss carryforward asset (35) 65 (26) Other (25) (36) 18 Income tax $ 1,932 $ 2,767 $ 2,247 The following table summarizes the temporary differences that give rise to the net deferred income tax liability: 2023 2022 Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets $ 12,172 $ 11,985 Lease assets 336 336 Investments 54 56 Investment in North West Redwater Partnership 904 903 Taxable PRT for corporate income tax 256 176 Other 41 25 13,763 13,481 Deferred income tax assets Asset retirement obligations (2,098) (1,822) Lease liabilities (356) (354) Share-based compensation (31) (33) Loss carryforwards (417) (652) Unrealized foreign exchange loss on long-term debt (39) (67) Deferred PRT (639) (439) (3,580) (3,367) Net deferred income tax liability $ 10,183 $ 10,114 Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows: 2023 2022 2021 Property, plant and equipment and exploration and evaluation assets $ 196 $ (334) $ 184 Lease assets 1 (15) (30) Unrealized foreign exchange on long-term debt 28 (81) 34 Unrealized risk management activities — (12) 19 Asset retirement obligations (292) (74) (213) Lease liabilities (3) 11 25 Share-based compensation 2 (11) (10) Loss carryforwards 235 618 202 Investments (2) 21 21 Investment in North West Redwater Partnership 1 53 83 Deferred PRT 86 (441) — Taxable PRT for corporate income tax (214) 176 — Other 15 (50) 84 $ 53 $ (139) $ 399 The following table summarizes the movements of the net deferred income tax liability during the year: 2023 2022 2021 Balance – beginning of year $ 10,114 $ 10,220 $ 10,144 Deferred income tax expense (recovery) 53 (139) 399 Deferred income tax expense included in other comprehensive (loss) income — — 1 Foreign exchange adjustments 16 33 (2) Business combinations — — (322) Balance – end of year $ 10,183 $ 10,114 $ 10,220 Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company’s reported results of operations, financial position or liquidity. Deferred income tax assets are recognized for temporary differences to the extent that the realization of the related tax benefit through future taxable profits is probable. Deferred PRT assets will be recovered from the UK Government, directly or through other third parties, as related abandonment expenditures are made. The Company has not recognized deferred income tax assets with respect to taxable capital loss carryforwards in excess of $1,000 million in North America, which can be carried forward indefinitely and only applied against future taxable capital gains. In addition, the Company has not recognized deferred income tax assets related to North American tax pools of approximately $950 million, which can only be claimed against income from certain oil and gas properties. Deferred income tax liabilities have not been recognized on the unremitted net earnings of wholly controlled subsidiaries. The Company is able to control the timing and amount of distributions and no taxes are payable on distributions from these subsidiaries provided that the distributions remain within certain limits. |
Share Capital
Share Capital | 12 Months Ended |
Dec. 31, 2023 | |
Share Capital, Reserves And Other Equity Interest [Abstract] | |
Share Capital | Share Capital AUTHORIZED Preferred shares issuable in a series. Unlimited number of common shares without par value. 2023 2022 ISSUED COMMON SHARES Number of shares (thousands) Amount Number of shares (thousands) Amount Balance – beginning of year 1,102,636 $ 10,294 1,168,369 $ 10,168 Issued upon exercise of stock options 9,822 372 11,605 442 Previously recognized liability on stock options exercised for common shares — 435 — 387 Purchase of common shares under Normal Course Issuer Bid (40,050) (389) (77,338) (703) Balance – end of year 1,072,408 $ 10,712 1,102,636 $ 10,294 PREFERRED SHARES Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges, restrictions and conditions attached to the shares will be determined by the Board of Directors of the Company. DIVIDENDS The Company has paid regular quarterly dividends in each year since 2001. The dividend policy undergoes periodic review by the Board of Directors and is subject to change. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $1.05 per common share, beginning with the dividend payable on April 5, 2024. On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share. On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share. On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share. On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share, from $0.5875 per common share. NORMAL COURSE ISSUER BID On March 8, 2023, the Company's application was approved for a Normal Course Issuer Bid ("NCIB") to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up to 92,296,006 common shares, over a 12-month period commencing March 13, 2023 and ending March 12, 2024. For the year ended December 31, 2023, the Company purchased 40,050,000 common shares at a weighted average price of $82.86 per common share for a total cost of $3,318 million. Retained earnings were reduced by $2,929 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2023, up to and including February 27, 2024, the Company purchased 4,000,000 common shares at a weighted average price of $85.54 per common share for a total cost of $342 million. On February 28, 2024, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE. SHARE SPLIT On February 28, 2024, the Company's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024. SHARE-BASED COMPENSATION – STOCK OPTIONS The Company’s Option Plan provides for the granting of stock options to employees. Stock options granted under the Option Plan have terms ranging from five The Option Plan is a "rolling 7%" plan, whereby the aggregate number of common shares that may be reserved for issuance under the plan shall not exceed 7% of the common shares outstanding from time to time. The following table summarizes information relating to stock options outstanding at December 31, 2023 and 2022: 2023 2022 Stock options ( thousands) Weighted average exercise price Stock options (thousands) Weighted average exercise price Outstanding – beginning of year 31,150 $ 42.37 38,327 $ 35.88 Granted 7,024 $ 80.17 7,547 $ 68.15 Exercised for common shares (9,822) $ 37.84 (11,605) $ 38.06 Surrendered for cash settlement (218) $ 38.77 (441) $ 38.43 Forfeited (1,929) $ 50.86 (2,678) $ 41.43 Outstanding – end of year 26,205 $ 53.60 31,150 $ 42.37 Exercisable – end of year 3,672 $ 42.14 5,522 $ 37.60 The range of exercise prices of stock options outstanding and exercisable at December 31, 2023 was as follows: Stock options outstanding Stock options exercisable Range of exercise prices Stock options outstanding (thousands) Weighted average remaining term (years) Weighted average exercise price Stock options exercisable (thousands) Weighted average exercise price $20.76 – $29.99 5,441 2.01 $ 27.42 969 $ 24.84 $30.00 – $39.99 5,411 1.03 $ 36.67 1,227 $ 36.56 $40.00 – $49.99 2,381 2.41 $ 40.52 630 $ 40.50 $50.00 – $59.99 433 3.86 $ 54.24 30 $ 54.24 $60.00 – $69.99 3,837 3.49 $ 64.90 301 $ 64.21 $70.00 – $79.99 7,787 4.18 $ 78.48 515 $ 76.35 $80.00 – $86.06 915 5.72 $ 84.12 — $ — 26,205 2.87 $ 53.60 3,672 $ 42.14 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2023 | |
Analysis Of Other Comprehensive Income By Item [Abstract] | |
Accumulated Other Comprehensive Income | Accumulated Other Comprehensive Income The components of accumulated other comprehensive income, net of taxes, were as follows: 2023 2022 Derivative financial instruments designated as cash flow hedges $ 72 $ 75 Foreign currency translation adjustment 100 134 $ 172 $ 209 |
Capital Disclosures
Capital Disclosures | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Capital Disclosures | Capital Disclosures The Company has defined its capital to mean its long-term debt and consolidated shareholders’ equity, as determined at each reporting date. The Company’s objectives when managing its capital structure are to maintain financial flexibility and balance to enable the Company to access capital markets to sustain its on-going operations and support its growth strategies. The Company primarily monitors capital on the basis of an internally derived financial measure referred to as its "debt to book capitalization ratio", which is the ratio of current and long-term debt less cash and cash equivalents divided by the sum of the carrying value of shareholders' equity plus current and long-term debt less cash and cash equivalents. The Company's internal targeted range for its debt to book capitalization ratio is 25% to 45%. The ratio may fall below or exceed the targeted range depending on the timing of acquisitions, the execution of the Company's capital program, and commodity price and foreign currency volatility. As at December 31, 2023, the ratio was below the target range at 20%. Readers are cautioned that the debt to book capitalization ratio is not defined by IFRS and this financial measure may not be comparable to similar measures presented by other companies. Further, there are no assurances that the Company will continue to use this measure to monitor capital or will not alter the method of calculation of this measure in the future. 2023 2022 Long-term debt $ 10,799 $ 11,445 Less: cash and cash equivalents 877 920 Long-term debt, net $ 9,922 $ 10,525 Total shareholders’ equity $ 39,832 $ 38,175 Debt to book capitalization 20% 22% The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit facility agreements to not exceed 65%. At December 31, 2023, the Company was in compliance with this covenant. |
Net Earnings Per Common Share
Net Earnings Per Common Share | 12 Months Ended |
Dec. 31, 2023 | |
Earnings per share [abstract] | |
Net Earnings Per Common Share | Net Earnings Per Common Share 2023 2022 2021 Weighted average common shares outstanding – basic (thousands of shares) 1,091,312 1,134,960 1,181,250 Effect of dilutive stock options (thousands of shares) 10,812 14,222 5,307 Weighted average common shares outstanding – diluted (thousands of shares) 1,102,124 1,149,182 1,186,557 Net earnings $ 8,233 $ 10,937 $ 7,664 Net earnings per common share – basic $ 7.54 $ 9.64 $ 6.49 – diluted $ 7.47 $ 9.52 $ 6.46 In 2023, the Company excluded 3,230,000 potentially anti-dilutive stock options from the calculation of diluted earnings per common share (2022 – 2,039,000; 2021 – 3,496,000). |
Interest and Other Financing Ex
Interest and Other Financing Expense | 12 Months Ended |
Dec. 31, 2023 | |
Borrowing costs [abstract] | |
Interest and Other Financing Expense | Interest and Other Financing Expense 2023 2022 2021 Interest and other financing expense Long-term debt $ 627 $ 610 $ 681 Lease liabilities 64 60 62 Total interest and other financing expense 691 670 743 Total interest income and other (55) (121) (32) Net interest and other financing expense $ 636 $ 549 $ 711 |
Financial Instruments
Financial Instruments | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Financial Instruments | Financial Instruments The Company's financial instruments are comprised of cash and cash equivalents, accounts receivable, investments, risk management assets and liabilities, accounts payable, accrued liabilities, lease liabilities and long-term debt. These financial instruments, with the exception of investments and risk management assets and liabilities, are classified as financial assets and liabilities at amortized cost. Investments are classified as financial assets at fair value through profit or loss and are based on quoted market prices. Risk management assets and liabilities are classified as derivatives held for trading or as cash flow hedges. At each measurement date, the estimated fair values of derivative financial instruments in Level 2 have been determined based on appropriate internal valuation methodologies and/or third party indications, including quoted forward prices for commodities, foreign exchange rates, interest yield curves and other volatility factors. The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were recognized in the financial statements as follows: Asset (liability) 2023 2022 Balance – beginning of year $ 6 $ 55 Net change in fair value of outstanding derivative financial instruments recognized in: Risk management activities (1) 3 70 Foreign exchange — (119) Balance – end of year 9 6 Less: current portion 8 — $ 1 $ 6 (1) Risk management assets and liabilities are disclosed in note 10 and note 12, respectively. Net (gain) loss from risk management activities for the years ended December 31, were as follows: 2023 2022 2021 Net realized risk management (gain) loss $ (14) $ (7) $ 17 Net unrealized risk management loss (gain) 12 (28) 19 $ (2) $ (35) $ 36 The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt. The Company's financial instruments are categorized as Level 1 with the exception of risk management assets and liabilities which are categorized as Level 2. There were no transfers between Level 1, 2 and 3 financial instruments. The fair value of the Company’s fixed rate long-term debt is outlined below: 2023 2022 Carrying amount Level 1 Carrying amount Level 1 Fixed rate long-term debt (1) (2) $ (10,799) $ (10,795) $ (11,445) $ (10,796) (1) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (2) Includes the current portion of fixed rate long-term debt. RISK MANAGEMENT The Company periodically uses derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the Company’s consolidated balance sheets. Asset (liability) 2023 2022 Derivatives held for trading Natural gas (1) $ (3) $ 3 Foreign currency forward contracts 12 3 $ 9 $ 6 Included within: Current portion of other long-term assets $ 12 $ 3 Current portion of other long-term liabilities (4) (3) Other long-term assets 1 6 $ 9 $ 6 (1) In 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial hedge contracts for the period of January to December 2024. FINANCIAL RISK FACTORS The Company's financial risks are consistent with those disclosed in notes 1 and 4. a) Market risk Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. The Company’s market risk is comprised of commodity price risk, interest rate risk, and foreign currency exchange risk. COMMODITY PRICE RISK MANAGEMENT The Company periodically uses commodity derivative financial instruments to manage its exposure to commodity price risk associated with the sale of its future crude oil and natural gas production and with natural gas purchases. The Company's outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month. INTEREST RATE RISK MANAGEMENT The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. Interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At December 31, 2023, the Company had no interest rate swap contracts outstanding. FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-term debt, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt, commercial paper and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. During 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the US$1,100 million 6.25% US dollar debt securities due March 2038. The Company realized cash proceeds of $158 million on settlement. As at December 31, 2023, the Company had US$1,003 million of foreign currency forward contracts outstanding (December 31, 2022 – US$1,017 million), with original terms of up to 90 days, all of which were designated as derivatives held for trading. FINANCIAL INSTRUMENT SENSITIVITIES The following table summarizes the annualized sensitivities of the Company’s 2023 net earnings and other comprehensive income to changes in the fair value of financial instruments outstanding as at December 31, 2023, resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those disclosed in the Company’s other continuous disclosure documents, are limited to the impact of changes in a specified variable applied to financial instruments only and do not represent the impact of a change in the variable on the operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear. 2023 2022 Increase (decrease) to net earnings Increase (decrease) to other comprehensive income Increase (decrease) to net earnings Increase (decrease) to other comprehensive income Interest rate risk Increase interest rate 1% $ (5) $ — $ (4) $ — Decrease interest rate 1% $ 5 $ — $ 4 $ — Foreign currency exchange rate risk Weakening of the Canadian dollar by US$0.01 $ (128) $ — $ (135) $ — Strengthening of the Canadian dollar by US$0.01 $ 125 $ — $ 131 $ — b) Credit risk Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge an obligation. COUNTERPARTY CREDIT RISK MANAGEMENT The Company’s accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. At December 31, 2023, substantially all of the Company’s accounts receivable were due within normal trade terms and the average expected credit loss was approximately 1% of the Company's accounts receivable balance (December 31, 2022 – 1%). The Company is also exposed to possible losses in the event of nonperformance by counterparties to derivative financial instruments; however, the Company manages this credit risk by entering into agreements with counterparties that are substantially all investment grade financial institutions. As at December 31, 2023, the Company had net risk of $11 million with specific counterparties related to derivative financial instruments (December 31, 2022 – $7 million). The carrying amount of financial assets approximates the maximum credit exposure. c) Liquidity risk Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to debt capital markets, to meet obligations as they become due. The Company believes it has adequate bank credit facilities to provide liquidity to manage fluctuations in the timing of the receipt and/or disbursement of operating cash flows. The maturity dates of the Company’s financial liabilities were as follows: Less than 1 year 1 to less than 2 years 2 to less than 5 years Thereafter Accounts payable $ 1,418 $ — $ — $ — Accrued liabilities $ 3,534 $ — $ — $ — Long-term debt (1) $ 980 $ 1,584 $ 2,317 $ 5,978 Other long-term liabilities (2) $ 302 $ 184 $ 428 $ 645 Interest and other financing expense (3) $ 582 $ 518 $ 1,257 $ 3,362 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. (2) Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 million. (3) Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates at December 31, 2023. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company’s commitments as at December 31, 2023: 2024 2025 2026 2027 2028 Thereafter Product transportation and processing (1) $ 1,572 $ 1,595 $ 1,408 $ 1,358 $ 1,242 $ 13,380 North West Redwater Partnership service toll (2) $ 158 $ 157 $ 139 $ 126 $ 130 $ 4,985 Offshore vessels and equipment $ 36 $ — $ — $ — $ — $ — Field equipment and power $ 38 $ 25 $ 23 $ 22 $ 22 $ 193 Other $ 145 $ 111 $ 112 $ 25 $ 26 $ 355 (1) The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion reflects interim tolls approved by the Canada Energy Regulator in 2023, and is subject to change pending the approval of final tolls. (2) Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $3,011 million of interest payable over the 40-year tolling period, ending in 2058 (note 10). In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of its various development projects. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position. |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash Flow Information | 12 Months Ended |
Dec. 31, 2023 | |
Statement Of Cash Flows, Additional Disclosures [Abstract] | |
Supplemental Disclosure of Cash Flow Information | Supplemental Disclosure of Cash Flow Information 2023 2022 2021 Changes in non-cash working capital: Accounts receivable $ 368 $ (441) $ (850) Inventory (219) (266) (487) Prepaids and other (23) (20) 39 Accounts payable 78 537 80 Accrued liabilities (812) 896 525 Current income tax (liabilities) assets (1,558) (282) 1,918 Other long-term liabilities (200) (196) (154) Net changes in non-cash working capital $ (2,366) $ 228 $ 1,071 Relating to: Operating activities $ (2,417) $ 79 $ 964 Investing activities 51 149 107 $ (2,366) $ 228 $ 1,071 The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended December 31, 2023 and 2022: Long-term debt Cash flow hedges on US dollar debt securities Lease liabilities Liabilities from financing activities At December 31, 2021 $ 14,694 $ (119) $ 1,584 $ 16,159 Changes from financing cash flows: Repayment of long-term debt, net (1) (4,010) — — (4,010) Proceeds on settlement of cross currency swaps — 69 — 69 Payment of lease liabilities — — (232) (232) Non-cash changes: Lease additions — — 182 182 Changes in foreign exchange and fair value (2) 761 50 6 817 At December 31, 2022 11,445 — 1,540 12,985 Changes from financing cash flows: Repayment of long-term debt, net (1) (416) — — (416) Payment of lease liabilities — — (285) (285) Non-cash changes: Lease additions — — 317 317 Changes in foreign exchange and fair value (2) (230) — (17) (247) At December 31, 2023 $ 10,799 $ — $ 1,555 $ 12,354 (1) Includes original issue discounts and premiums, and directly attributable transaction costs. (2) Includes foreign exchange (gain) loss, changes in the fair value of cash flow hedges on US dollar debt securities, the amortization of original issue discounts and premiums and directly attributable transaction costs, and derecognition of lease liabilities. |
Segmented Information
Segmented Information | 12 Months Ended |
Dec. 31, 2023 | |
Operating Segments [Abstract] | |
Segmented Information | Segmented Information The Company’s exploration and production activities are conducted in three geographic segments: North America, North Sea and Offshore Africa. These activities include the exploration, development, production and marketing of crude oil, natural gas liquids and natural gas. The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and production activities. Midstream and Refining activities include the Company’s pipeline operations, an electricity co-generation system and NWRP. Segmented revenue and segmented results include transactions between business segments. Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers are based on the location of the seller. Inter-segment elimination and Other includes internal and corporate transportation and electricity charges. Production, processing and other purchasing and selling activities, that are not included in the preceding segments are also reported in the segmented information as Inter-segment eliminations and Other. Operating segments have been determined based on the nature of the Company’s activities and the geographic locations in which the Company operates, and are consistent with the level of information regularly provided to and reviewed by the Company’s chief operating decision makers. North America North Sea Offshore Africa (millions of Canadian dollars) 2023 2022 2021 2023 2022 2021 2023 2022 2021 Segmented product sales Crude oil and NGLs (1) $ 17,375 $ 20,755 $ 14,478 $ 435 $ 623 $ 607 $ 577 $ 694 $ 420 Natural gas 2,375 4,931 2,484 7 13 5 51 55 31 Other income and revenue (2) 10 217 119 — — (1) 9 8 7 Total segmented product sales 19,760 25,903 17,081 442 636 611 637 757 458 Less: royalties (2,443) (3,918) (1,694) (1) (1) (1) (57) (71) (21) Segmented revenue 17,317 21,985 15,387 441 635 610 580 686 437 Segmented expenses Production 3,617 3,754 2,963 342 437 383 141 114 91 Transportation, blending and feedstock (1) 5,808 6,394 4,772 7 6 7 1 1 1 Depletion, depreciation and amortization (3) 3,679 3,595 3,569 494 1,747 160 213 173 142 Asset retirement obligation accretion 234 171 101 46 33 21 8 7 6 Risk management activities (commodity derivatives) 24 18 29 — — — — — — Gain on acquisitions — — (478) — — — — — — Income from NWRP — — — — — — — — — Total segmented expenses 13,362 13,932 10,956 889 2,223 571 363 295 240 Segmented earnings (loss) $ 3,955 $ 8,053 $ 4,431 $ (448) $ (1,588) $ 39 $ 217 $ 391 $ 197 Non-segmented expenses Administration Share-based compensation Interest and other financing expense Risk management activities (other) Foreign exchange (gain) loss Gain from investments Total non-segmented expenses Earnings before taxes Current income tax Deferred income tax Net earnings (1) Includes blending and feedstock costs associated with the processing of third party bitumen and other purchased feedstock in the Oil Sands Mining and Upgrading segment. (2) Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations partners' share of the costs of lease contracts. (3) Includes a recoverability charge in depletion, depreciation and amortization, related to the Ninian field in the North Sea at December 31, 2023 for $436 million (December 31, 2022 – $1,620 million) (note 7). Oil Sands Mining and Upgrading Midstream and Refining Inter-segment elimination and Other Total 2023 2022 2021 2023 2022 2021 2023 2022 2021 2023 2022 2021 $ 18,661 $ 20,804 $ 14,033 $ 76 $ 80 $ 78 $ 176 $ 53 $ (360) $ 37,300 $ 43,009 $ 29,256 — — — — — — 142 237 196 2,575 5,236 2,716 5 149 73 926 906 681 10 5 3 960 1,285 882 18,666 20,953 14,106 1,002 986 759 328 295 (161) 40,835 49,530 32,854 (2,366) (3,242) (1,081) — — — — — — (4,867) (7,232) (2,797) 16,300 17,711 13,025 1,002 986 759 328 295 (161) 35,968 42,298 30,057 3,989 4,076 3,414 332 271 234 59 60 67 8,480 8,712 7,152 2,563 2,652 1,505 664 691 550 259 229 (231) 9,302 9,973 6,604 2,011 1,822 1,838 16 16 15 — — — 6,413 7,353 5,724 78 70 57 — — — — — — 366 281 185 — — — — — — — — — 24 18 29 — — — — — — — — — — — (478) — — — — — (400) — — — — — (400) 8,641 8,620 6,814 1,012 978 399 318 289 (164) 24,585 26,337 18,816 $ 7,659 $ 9,091 $ 6,211 $ (10) $ 8 $ 360 $ 10 $ 6 $ 3 $ 11,383 $ 15,961 $ 11,241 452 415 366 491 804 514 636 549 711 (26) (53) 7 (279) 738 (127) (56) (196) (141) 1,218 2,257 1,330 10,165 13,704 9,911 1,879 2,906 1,848 53 (139) 399 $ 8,233 $ 10,937 $ 7,664 CAPITAL EXPENDITURES (1) 2023 2022 Net expenditures Non-cash and fair value changes (2) Capitalized costs Net expenditures Non-cash and fair value changes (2) Capitalized costs Exploration and evaluation assets Exploration and Production North America $ 41 $ (36) $ 5 $ 28 $ (59) $ (31) Offshore Africa 3 — 3 5 — 5 Oil Sands Mining and Upgrading — (25) (25) — — — 44 (61) (17) 33 (59) (26) Property, plant and equipment Exploration and Production North America 2,729 (321) 2,408 3,105 136 3,241 North Sea 33 525 558 126 177 303 Offshore Africa 169 18 187 119 (44) 75 2,931 222 3,153 3,350 269 3,619 Oil Sands Mining and Upgrading 1,894 (251) 1,643 1,719 (843) 876 Midstream and Refining 10 — 10 9 (1) 8 Head Office 30 — 30 25 — 25 4,865 (29) 4,836 5,103 (575) 4,528 $ 4,909 $ (90) $ 4,819 $ 5,136 $ (634) $ 4,502 (1) This table provides a reconciliation of capitalized costs, reported in note 6 and note 7, to net expenditures reported in the investing activities section of the statements of cash flows. The reconciliation excludes the impact of foreign exchange adjustments. (2) Derecognitions, asset retirement obligations, transfer of exploration and evaluation assets, and other fair value adjustments. SEGMENTED ASSETS 2023 2022 Exploration and Production North America $ 30,058 $ 31,135 North Sea 602 378 Offshore Africa 1,380 1,322 Other 32 54 Oil Sands Mining and Upgrading 42,865 42,102 Midstream and Refining 856 979 Head Office 162 172 $ 75,955 $ 76,142 |
Remuneration of Directors and S
Remuneration of Directors and Senior Management | 12 Months Ended |
Dec. 31, 2023 | |
Related Party [Abstract] | |
Remuneration of Directors and Senior Management | Remuneration of Directors and Senior Management REMUNERATION OF NON-MANAGEMENT DIRECTORS 2023 2022 2021 Fees earned $ 3 $ 2 $ 2 REMUNERATION OF SENIOR MANAGEMENT (1) 2023 2022 2021 Salary $ 2 $ 2 $ 2 Common stock option based awards 13 12 10 Annual incentive plans 5 5 6 Long-term incentive plans 19 18 19 $ 39 $ 37 $ 37 (1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to shareholders for the respective years. |
Supplementary Oil And Gas Infor
Supplementary Oil And Gas Information (Unaudited) | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Supplementary Oil And Gas Information (Unaudited) | Supplementary Oil & Gas Information for the Fiscal Year Ended December 31, 2023 (Unaudited) This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board ("FASB") Topic 932 – "Extractive Activities – Oil and Gas" and where applicable, financial information is prepared in accordance with International Financial Reporting Standards ("IFRS"). For the years ended December 31, 2023, 2022, 2021 and 2020 the Company filed its reserves information under National Instrument 51-101 – "Standards of Disclosure of Oil and Gas Activities" ("NI 51-101"), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. There are significant differences in the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission ("SEC") requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards can be material. For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2023, 2022, 2021 and 2020 the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The Company has used the following 12-month average benchmark prices to determine its 2023 and 2022 reserves for SEC requirements. Crude Oil and NGLs Natural Gas WTI WCS Canadian Light Sweet Cromer LSB Brent Edmonton C5+ Henry Hub AECO BC Westcoast Station 2 (US$/bbl) (C$/bbl) (C$/bbl) (C$/bbl) (US$/bbl) (C$/bbl) (US$/MMBtu) (C$/MMBtu) (C$/MMBtu) 2023 78.10 79.95 100.93 99.48 82.51 103.43 2.75 2.79 2.10 2022 94.13 99.40 118.90 117.76 97.98 119.93 6.44 5.59 4.51 A foreign exchange rate of US$0.7407/C$1.00 was used in the 2023 evaluation (2022 - US$0.7709/C$1.00), determined on the same basis as the 12-month average price. Net Proved Crude Oil and Natural Gas Reserves The Company retains Independent Qualified Reserves Evaluators to evaluate and review the Company's proved crude oil, bitumen, synthetic crude oil ("SCO"), natural gas, and natural gas liquids ("NGLs") reserves. ▪ For the years ended December 31, 2023, 2022, 2021 and 2020, the reports by GLJ Ltd. covered 100% of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules, effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals. ▪ For the years ended December 31, 2023, 2022, 2021 and 2020, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s crude oil, bitumen, natural gas and NGLs reserves. Proved crude oil and natural gas reserves, as defined within the SEC's Regulation S-X, are the estimated quantities of oil and gas that by analysis of geoscience and engineering data demonstrate with reasonable certainty to be economically producible, from a given date forward, from known reservoirs under existing economic conditions, operating methods and government regulations. Developed crude oil and natural gas reserves are reserves of any category that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped crude oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change. The following tables summarize the Company's proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2023, 2022, 2021 and 2020: North America Crude Oil and NGLs (MMbbl) (1) Synthetic Bitumen (2) Crude Oil North North Offshore Total Net Proved Reserves Reserves, December 31, 2020 6,847 2,413 525 9,785 87 71 9,943 Extensions and discoveries — 101 14 115 — — 115 Improved recovery — 19 14 33 — — 33 Purchases of reserves in place — — 52 52 — — 52 Sales of reserves in place — — — — — — — Production (150) (103) (45) (297) (6) (5) (309) Economic revisions due to prices (3) (927) (296) 108 (1,115) 1 (4) (1,118) Revisions of prior estimates 174 155 40 369 (3) 2 368 Reserves, December 31, 2021 5,944 2,289 708 8,941 79 64 9,083 Extensions and discoveries — 195 11 205 — — 205 Improved recovery 29 5 21 56 — — 56 Purchases of reserves in place — 267 21 288 — — 288 Sales of reserves in place — — — — — — — Production (128) (91) (45) (265) (5) (5) (274) Economic revisions due to prices (3) (455) (263) (73) (791) 1 (2) (792) Revisions of prior estimates — 144 54 198 (64) — 134 Reserves, December 31, 2022 5,390 2,546 696 8,632 11 57 8,700 Extensions and discoveries 162 67 51 280 — — 280 Improved recovery 28 9 37 75 — — 75 Purchases of reserves in place — — — — — — — Sales of reserves in place — — (1) (1) — — (1) Production (141) (102) (47) (289) (5) (4) (298) Economic revisions due to prices (3) 333 123 29 484 — 1 485 Revisions of prior estimates 68 26 1 94 3 1 98 Reserves, December 31, 2023 5,840 2,669 767 9,276 9 54 9,339 Net Proved Developed Reserves December 31, 2020 6,770 628 285 7,682 32 37 7,751 December 31, 2021 5,929 584 370 6,883 39 38 6,960 December 31, 2022 5,389 582 359 6,330 5 34 6,369 December 31, 2023 5,804 610 337 6,752 6 30 6,787 (1) Information in the reserves data tables may not add due to rounding. (2) Bitumen as defined by the SEC, "is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis." Under this definition, all the Company's thermal and primary heavy crude oil reserves have been classified as bitumen. (3) Includes changes due to commodity price and resulting royalty volumes. 2023 total proved Crude Oil and NGLs reserves increased by 639 MMbbl: ▪ Extensions and discoveries: Increase of 280 MMbbl primarily due to pit extensions at Oil Sands Mining and Upgrading (SCO) and infill drilling/future offset additions at various Bitumen, natural gas (NGLs) and Crude Oil properties. ▪ Improved recovery: Increase of 75 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil properties as well as improved recovery at Oil Sands Mining and Upgrading (SCO) and Bitumen properties. ▪ Sales of reserves in place: Decrease of 1 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in Alberta. ▪ Production: Decrease of 298 MMbbl. ▪ Economic revisions due to prices: Increase of 485 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and various Bitumen properties due to lower bitumen pricing resulting in lower royalties and higher net reserves. ▪ Revisions of prior estimates: Increase of 98 MMbbl primarily due to transfers from beyond the 50-year reserves life cutoff at Oil Sands Mining and Upgrading (SCO) and improved performance at various Bitumen properties. 2022 total proved Crude Oil and NGLs reserves decreased by 383 MMbbl: ▪ Extensions and discoveries: Increase of 205 MMbbl primarily due to extension drilling/future offset additions at various Bitumen properties. ▪ Improved recovery: Increase of 56 MMbbl primarily due to improved recovery at Oil Sands Mining and Upgrading (SCO) and infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil properties. ▪ Purchases of reserves in place: Increase of 288 MMbbl primarily due to a Bitumen acquisition in Alberta. ▪ Production: Decrease of 274 MMbbl. ▪ Economic revisions due to prices: Decrease of 792 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and various Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves. ▪ Revisions of prior estimates: Increase of 134 MMbbl primarily due to improved performance at various Bitumen, North America Crude Oil and natural gas (NGLs) properties, partially offset by removal of future undeveloped reserves at North Sea. 2021 total proved Crude Oil and NGLs reserves decreased by 860 MMbbl: ▪ Extensions and discoveries: Increase of 115 MMbbl primarily due to extension drilling/future offset additions at various Bitumen properties. ▪ Improved recovery: Increase of 33 MMbbl primarily due to increased recovery of thermal Bitumen at Jackfish and Kirby properties and infill drilling/future offset additions at various Crude Oil and natural gas (NGLs) properties. ▪ Purchases of reserves in place: Increase of 52 MMbbl primarily due to natural gas (NGLs) acquisitions in northeast British Columbia. ▪ Production: Decrease of 309 MMbbl. ▪ Economic revisions due to prices: Decrease of 1,118 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and thermal Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves. ▪ Revisions of prior estimates: Increase of 368 MMbbl primarily due to transfers from beyond the 50-year reserves life cutoff at Oil Sands Mining and Upgrading (SCO) and improved performance at various North America and Offshore Africa Crude Oil, Bitumen and natural gas (NGLs) properties. Natural Gas (Bcf) (1) North America North Sea Offshore Africa Total Net Proved Reserves Reserves, December 31, 2020 7,655 12 34 7,701 Extensions and discoveries 545 — — 545 Improved recovery 161 — — 161 Purchases of reserves in place 1,654 — — 1,654 Sales of reserves in place (1) — — (1) Production (581) (1) (4) (587) Economic revisions due to prices (2) 712 — (4) 708 Revisions of prior estimates 1,139 (3) — 1,136 Reserves, December 31, 2021 11,285 8 25 11,318 Extensions and discoveries 251 — — 251 Improved recovery 192 — — 192 Purchases of reserves in place 228 — — 228 Sales of reserves in place — — — — Production (688) (1) (4) (693) Economic revisions due to prices (2) (572) — (3) (575) Revisions of prior estimates 1,521 (3) 7 1,526 Reserves, December 31, 2022 12,217 4 25 12,246 Extensions and discoveries 1,185 — — 1,185 Improved recovery 603 — — 603 Purchases of reserves in place — — — — Sales of reserves in place (6) — — (6) Production (750) (1) (4) (755) Economic revisions due to prices (2) 87 — 1 88 Revisions of prior estimates 57 (1) 1 58 Reserves, December 31, 2023 13,393 3 23 13,419 Net Proved Developed Reserves December 31, 2020 3,116 6 22 3,144 December 31, 2021 4,469 3 20 4,492 December 31, 2022 4,956 1 19 4,975 December 31, 2023 4,029 1 10 4,040 (1) Information in the reserves data tables may not add due to rounding. (2) Includes changes due to commodity price and resulting royalty volumes. 2023 total proved Natural Gas reserves increased by 1,173 Bcf primarily due to the following: ▪ Extensions and discoveries: Increase of 1,185 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪ Improved recovery: Increase of 603 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northwest British Columbia. ▪ Sales of reserves in place: Decrease of 6 Bcf primarily due to dispositions from various Natural Gas properties in Alberta. ▪ Production: Decrease of 755 Bcf. ▪ Economic revisions due to prices: Increase of 88 Bcf primarily at various North America Natural Gas properties due to lower natural gas pricing resulting in lower royalties and higher net reserves. ▪ Revisions of prior estimates: Increase of 58 Bcf primarily due to category transfers from probable to proved partially offset by negative revisions in various North American core areas as a result of decreased performance. 2022 total proved Natural Gas reserves increased by 928 Bcf primarily due to the following: ▪ Extensions and discoveries: Increase of 251 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪ Improved recovery: Increase of 192 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪ Purchases of reserves in place: Increase of 228 Bcf primarily due to property acquisitions in North America core areas. ▪ Production: Decrease of 693 Bcf. ▪ Economic revisions due to prices: Decrease of 575 Bcf primarily at various North America natural gas properties due to higher natural gas pricing resulting in higher royalties and lower net reserves. ▪ Revisions of prior estimates: Increase of 1,526 Bcf primarily due to overall positive revisions in several North American core areas as a result of increased performance and category transfers from probable to proved. 2021 total proved Natural Gas reserves increased by 3,617 Bcf primarily due to the following: ▪ Extensions and discoveries: Increase of 545 Bcf primarily due to extension drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪ Improved recovery: Increase of 161 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. ▪ Purchases of reserves in place: Increase of 1,654 Bcf primarily due to the Storm Resources Ltd. and other acquisitions in northeast British Columbia. ▪ Sales of reserves in place: Decrease of 1 Bcf from Natural Gas properties in North America. ▪ Production: Decrease of 587 Bcf. ▪ Economic revisions due to prices: Increase of 708 Bcf primarily due to increased Natural Gas price in North America. ▪ Revisions of prior estimates: Increase of 1,136 Bcf primarily due to overall positive revisions in several North American core areas as a result of increased performance and category transfers from probable to proved. Capitalized Costs Related to Crude Oil and Natural Gas Activities 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 132,858 $ 8,606 $ 4,409 $ 145,873 Unproved properties 2,108 — 100 2,208 134,966 8,606 4,509 148,081 Less: accumulated depletion and depreciation (69,945) (8,382) (3,358) (81,685) Net capitalized costs $ 65,021 $ 224 $ 1,151 $ 66,396 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 128,807 $ 8,258 $ 4,332 $ 141,397 Unproved properties 2,128 — 98 2,226 130,935 8,258 4,430 143,623 Less: accumulated depletion and depreciation (65,547) (8,106) (3,277) (76,930) Net capitalized costs $ 65,388 $ 152 $ 1,153 $ 66,693 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 124,690 $ 7,438 $ 3,980 $ 136,108 Unproved properties 2,159 — 91 2,250 126,849 7,438 4,071 138,358 Less: accumulated depletion and depreciation (61,231) (5,951) (2,923) (70,105) Net capitalized costs $ 65,618 $ 1,487 $ 1,148 $ 68,253 Costs Incurred in Crude Oil and Natural Gas Activities 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ — $ — $ — $ — Unproved — — — — Exploration 43 — 3 46 Development 5,039 558 187 5,784 Costs incurred $ 5,082 $ 558 $ 190 $ 5,830 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 524 $ — $ — $ 524 Unproved — — — — Exploration 40 — 5 45 Development 4,387 304 75 4,766 Costs incurred $ 4,951 $ 304 $ 80 $ 5,335 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 1,371 $ — $ — $ 1,371 Unproved 26 — — 26 Exploration 4 — 8 12 Development 4,301 208 48 4,557 Costs incurred $ 5,702 $ 208 $ 56 $ 5,966 Results of Operations from Crude Oil and Natural Gas Producing Activities The Company's results of operations from crude oil and natural gas producing activities for the years ended December 31, 2023, 2022 and 2021 are summarized in the following tables: 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 26,773 $ 442 $ 581 $ 27,796 Production (7,606) (342) (141) (8,089) Transportation (1,550) (7) (1) (1,558) Depletion, depreciation and amortization (5,690) (494) (213) (6,397) Asset retirement obligation accretion (312) (46) (8) (366) Petroleum revenue tax — 273 — 273 Income tax (2,700) 70 (54) (2,684) Results of operations $ 8,915 $ (104) $ 164 $ 8,975 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 31,698 $ 635 $ 687 $ 33,020 Production (7,830) (437) (114) (8,381) Transportation (1,424) (6) (1) (1,431) Depletion, depreciation and amortization (5,417) (1,747) (173) (7,337) Asset retirement obligation accretion (241) (33) (7) (281) Petroleum revenue tax — 483 — 483 Income tax (3,896) 442 (98) (3,552) Results of operations $ 12,890 $ (663) $ 294 $ 12,521 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 23,111 $ 611 $ 438 $ 24,160 Production (6,377) (383) (91) (6,851) Transportation (1,176) (7) (1) (1,184) Depletion, depreciation and amortization (5,407) (160) (142) (5,709) Asset retirement obligation accretion (158) (21) (6) (185) Petroleum revenue tax — 33 — 33 Income tax (2,317) (29) (50) (2,396) Results of operations $ 7,676 $ 44 $ 148 $ 7,868 Standardized Measure of Discounted Future Net Cash Flows from Proved Crude Oil and Natural Gas Reserves and Changes Therein The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been computed using the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including: ▪ Future production will include production not only from proved properties, but may also include production from probable and possible reserves; ▪ Future production of crude oil and natural gas from proved properties will differ from reserves estimated; ▪ Future production rates will vary from those estimated; ▪ Future prices and costs rather than 12-month average prices and costs as at the balance sheet date will apply; ▪ Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change; ▪ Future estimated income taxes do not take into account the effects of future exploration and evaluation expenditures; and ▪ Future development and asset retirement obligations will differ from those estimated. Future net revenues, development, production and asset retirement obligation costs have been based upon the estimates referred to above. The following tables summarize the Company's future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 - "Extractive Activities - Oil and Gas": 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 863,544 $ 1,067 $ 6,144 $ 870,755 Future production costs (276,498) (636) (1,880) (279,014) Future development costs and asset retirement obligations (86,615) (1,873) (1,927) (90,415) Future income taxes (113,516) 967 (508) (113,057) Future net cash flows 386,915 (475) 1,829 388,269 10% annual discount for timing of future cash flows (278,814) 168 (887) (279,533) Standardized measure of future net cash flows (1) $ 108,101 $ (307) $ 942 $ 108,736 (1) Includes abandonment cost estimates for the Ninian field. 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 986,672 $ 1,506 $ 7,304 $ 995,482 Future production costs (303,270) (691) (1,998) (305,959) Future development costs and asset retirement obligations (83,803) (1,416) (1,439) (86,658) Future income taxes (136,905) 517 (900) (137,288) Future net cash flows 462,694 (84) 2,967 465,577 10% annual discount for timing of future cash flows (327,333) 84 (1,330) (328,579) Standardized measure of future net cash flows (1) $ 135,361 $ — $ 1,637 $ 136,998 (1) Includes abandonment cost estimates for the Ninian field. 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 679,123 $ 7,791 $ 5,581 $ 692,495 Future production costs (238,144) (4,074) (1,818) (244,036) Future development costs and asset retirement obligations (77,375) (1,857) (1,142) (80,374) Future income taxes (81,860) (719) (565) (83,144) Future net cash flows 281,744 1,141 2,056 284,941 10% annual discount for timing of future cash flows (201,227) (142) (788) (202,157) Standardized measure of future net cash flows $ 80,517 $ 999 $ 1,268 $ 82,784 The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table: (millions of Canadian dollars) 2023 2022 2021 Sales of crude oil and natural gas produced, net of production costs $ (18,174) $ (23,242) $ (16,149) Net changes in sales prices and production costs (47,145) 79,291 74,558 Extensions, discoveries and improved recovery 8,196 6,198 2,948 Changes in estimated future development costs (1,511) (3,640) (2,773) Purchases of proved reserves in place — 5,745 4,010 Sales of proved reserves in place (47) — (1) Revisions of previous reserve estimates 6,647 (9,956) (186) Accretion of discount 17,769 10,712 3,460 Changes in production timing and other (2,831) 5,463 6,638 Net change in income taxes 8,834 (16,357) (17,232) Net change (28,262) 54,214 55,273 Balance - beginning of year 136,998 82,784 27,511 Balance - end of year $ 108,736 $ 136,998 $ 82,784 |
Accounting Policies (Policies)
Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
IFRS Compliance | The Company’s consolidated financial statements and the related notes have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). The accounting policies adopted by the Company under IFRS are set out below. The Company has consistently applied the same accounting policies throughout all periods presented, except where IFRS permits new accounting standards to be adopted prospectively. Changes in the Company's accounting policies are discussed in note 2. |
Principles of Consolidation | PRINCIPLES OF CONSOLIDATION The consolidated financial statements have been prepared under the historical cost basis, unless otherwise required. The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and wholly owned partnerships. Subsidiaries include all entities over which the Company has control. Subsidiaries are consolidated from the date on which the Company obtains control. They are deconsolidated from the date that control ceases. Certain of the Company’s activities are conducted through joint arrangements in which two or more parties have joint control. Where the Company has determined that it has a direct ownership interest in jointly controlled assets and obligations for the liabilities (a "joint operation"), the assets, liabilities, revenue and expenses related to the joint operation are included in the consolidated financial statements in proportion to the Company’s interest. Where the Company has determined that it has an interest in jointly controlled entities (a "joint venture"), it uses the equity method of accounting. Under the equity method, the Company’s initial and subsequent investments are recognized at cost and subsequently adjusted for the Company’s share of the joint venture’s income or loss, less distributions received. If the Company’s share of the joint venture’s loss equals or exceeds its interest in the joint venture, the Company discontinues recognizing its share of further losses. The Company resumes recognizing profits when its share of profits exceeds the accumulated share of losses not recognized. Joint ventures accounted for using the equity method of accounting are tested for impairment whenever objective evidence indicates that the carrying amount of the investment may not be recoverable. Indications of impairment include a history of losses, significant capital expenditure overruns, liquidity concerns, financial restructuring of the investee or significant adverse changes in the technological, economic or legal environment. The amount of the impairment is measured as the difference between the carrying amount of the investment and the higher of its fair value less costs of disposal and its value in use. Impairment losses are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized. |
Inventory | INVENTORY Inventory is primarily comprised of product inventory, materials and supplies and other inventory, including emissions credits, and is carried at the lower of cost and net realizable value. Product inventory is comprised of crude oil held for sale, including pipeline linefill and crude oil stored in floating production, storage and offloading vessels ("FPSO"). Cost of product inventory consists of purchase costs, direct production costs, directly attributable overhead and depletion, depreciation and amortization and is determined on a first-in, first-out basis. Net realizable value for product inventory is determined by reference to forward prices. Cost for materials and supplies consists of purchase costs and is based on a first-in, first-out or an average cost basis. Net realizable value for materials and supplies and other inventory is determined by reference to current market prices. Emissions credit inventory generated in the normal course of business is initially measured in accordance with the Company's accounting policy for government grants. |
Exploration and Evaluation Assets | EXPLORATION AND EVALUATION ASSETS Exploration and evaluation ("E&E") assets consist of the Company’s crude oil and natural gas exploration projects that are pending the determination of proved reserves. E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E costs do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore an area. These costs are recognized in net earnings. Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by management, the E&E assets are tested for impairment upon reclassification to property, plant and equipment. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. An E&E asset is derecognized upon disposal or when no future economic benefits are expected to arise from its use. Any gain or loss arising on derecognition of the asset is recognized in net earnings within depletion, depreciation and amortization. E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of the related Cash Generating Units ("CGUs"), aggregated at a segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is measured at cost less accumulated depletion and depreciation and recoverability charges. Assets under construction are not depleted or depreciated until available for their intended use. Exploration and Production The cost of an asset comprises its acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Property acquisition costs are comprised of the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant components of an item of property, plant and equipment, including crude oil and natural gas interests, have different useful lives, they are accounted for separately. Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves, except for certain major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future development expenditures required to develop proved reserves. Oil Sands Mining and Upgrading Capitalized costs for the Oil Sands Mining and Upgrading segment are reported separately from the Company’s North America Exploration and Production segment. Capitalized costs include acquisition costs, construction and development costs, overburden removal costs incurred during the initial development of a mine at Horizon and AOSP, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Mine-related costs are depleted using the unit-of-production method based on proved reserves. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from overburden removal activity. Costs of the upgraders and related infrastructure located on the Horizon and AOSP sites are depreciated on the unit-of-production method based on the estimated productive capacity of the respective upgraders and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life ranging from 2 to 20 years. Midstream, Refining and Head Office The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream, refining and head office assets. Midstream and Refining assets are depreciated on a straight-line basis over their estimated useful lives ranging from 5 to 30 years. Head office assets are depreciated on a declining balance basis. Useful lives The depletion rates and expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes in depletion rates and useful lives accounted for prospectively. Derecognition A property, plant and equipment asset is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is recognized in net earnings within depletion, depreciation and amortization. Major maintenance expenditures Inspection costs associated with major turnarounds are capitalized and depreciated over the period to the next major turnaround. Maintenance costs are expensed as incurred. Impairment The Company assesses property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into CGUs, which are the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGU's recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and a recoverability charge is taken through depletion, depreciation and amortization expense. In subsequent periods, an assessment is made at each reporting date to determine whether there is any indication that previously recognized recoverability charges may no longer exist or may have decreased. If such indication exists, the recoverable amount is re-estimated and the net carrying amount of the asset is increased to its revised recoverable amount. The revised recoverable amount cannot exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, had no recoverability charge been recognized for the asset in prior periods. A reversal of a recoverability charge is recognized in net earnings. After a reversal, the depletion, depreciation and amortization charge is adjusted in future periods to allocate the asset’s revised carrying amount over its remaining useful life. |
Business Combinations | BUSINESS COMBINATIONS Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair value of the net assets acquired is recognized as an asset. Any excess of the fair value of the net assets acquired over the consideration paid is recognized in net earnings. |
Leases | LEASES The Company recognizes a lease asset and a lease liability at the commencement date of the lease contract. The lease asset is initially measured at cost. The cost of a lease asset includes the amount of the initial measurement of the lease liability, lease payments made prior to the commencement date, initial direct costs and estimates of the asset retirement obligation, if any. Subsequent to initial recognition, the lease asset is depreciated using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term. Lease liabilities are initially measured at the present value of lease payments discounted at the rate implicit in the lease, or if not readily determinable, the Company's incremental borrowing rate. Lease liabilities are remeasured if there are changes in the lease term or if the Company changes its assessment of whether it is reasonably certain it will exercise a purchase, extension or termination option. Lease liabilities are also remeasured if there are changes in the estimate of the amounts payable under the lease due to changes in indices or rates, or residual value guarantees. Lease assets are reported in a separate caption in the consolidated balance sheet. Lease liabilities are reported within other long-term liabilities in the consolidated balance sheet. Where the Company acts as the operator of a joint operation, the Company recognizes 100% of the related lease asset and lease liability. As the Company recovers its joint operation partners' share of the costs of the lease contract, these recoveries are recognized as other income in the consolidated statements of earnings. |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on all of its property, plant and equipment and certain exploration and evaluation assets based on current legislation and operating practices. Provisions for asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Provisions are measured at the present value of management’s best estimate of expenditures required to settle the obligation as at the date of the balance sheets. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense, whereas changes due to discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against the provision. |
Foreign Currency Translation | FOREIGN CURRENCY TRANSLATION Functional and presentation currency Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the currency of the primary economic environment in which the subsidiary operates (the "functional currency"). When the Company disposes of its entire interest in a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings. |
Revenue Recognition | Revenue from the sale of crude oil and NGLs and natural gas products is recognized when performance obligations in the sales contract are satisfied and it is probable that the Company will collect the consideration to which it is entitled. Performance obligations are generally satisfied at the point in time when the product is delivered to a location specified in a contract and control passes to the customer. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. Contracts for sale of the Company’s products generally have terms of less than a year, with certain contracts extending beyond one year. Contracts in North America generally specify delivery of crude oil and NGLs and natural gas throughout the term of the contract. Contracts in the North Sea and Offshore Africa generally specify delivery of crude oil at a point in time. Sales of the Company’s crude oil and NGLs and natural gas products to customers are made pursuant to contracts based on prevailing commodity pricing at or near the time of delivery and volumes of product delivered. Revenues are typically collected in the month following delivery and accordingly, the Company has elected to apply the practical expedient to not adjust consideration for the effects of a financing component. Purchases and sales of crude oil and NGLs and natural gas with the same counterparty, made to facilitate sales to customers or potential customers, that are entered into in contemplation of one another, are combined and recorded as non-monetary exchanges and measured at the net settlement amount. |
Cost of Goods Sold | Related costs of goods sold are comprised of production, transportation, blending and feedstock, and depletion, depreciation and amortization expenses. These amounts have been separately presented in the consolidated statements of earnings. |
Production Sharing Contracts | PRODUCTION SHARING CONTRACTS Production generated from Côte d’Ivoire in Offshore Africa is shared under the terms of various Production Sharing Contracts ("PSCs"). Product sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the respective government state oil companies (the "Governments"). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated to royalty expense and current income tax expense in accordance with the terms of the respective PSCs. |
Income Tax | INCOME TAX The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases. Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected to apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise on the initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the transaction, affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on possible future distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the Company and it is probable that a distribution will not be made in the foreseeable future, or when distributions can be made without incurring income taxes. Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is no longer probable that sufficient future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different periods, using income tax rates that are substantively enacted at each reporting date. |
Share-based Compensation | SHARE-BASED COMPENSATION The Company’s Stock Option Plan (the "Option Plan") provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are remeasured each reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the Black-Scholes valuation model under a graded vesting method. Expected volatility is estimated based on historic results. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability associated with the stock options are recorded as share capital. The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined by individual employee performance and the extent to which certain other performance measures are met. PSUs vest three years from original grant date. The liability for PSUs is initially measured in reference to the Company's stock price and the number of awards expected to vest and is remeasured at each reporting period for changes in the fair value of the liability. The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term assets. |
Financial Instruments | FINANCIAL INSTRUMENTS The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost; financial liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest method. Cash and cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are solely comprised of payments of principal and interest. Investments in publicly traded shares are classified as fair value through profit or loss. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss. Financial assets and liabilities are also categorized using a three-level hierarchy that reflects the significance of the inputs used in making fair value measurements for these assets and liabilities. The fair values of financial assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values of financial assets and liabilities in Level 2 are based on inputs other than Level 1 quoted prices that are observable for the asset or liability either directly (as prices) or indirectly (derived from prices). The fair values of Level 3 financial assets and liabilities are not based on observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability. Transaction costs in respect of financial instruments at fair value through profit or loss are recognized in net earnings. Transaction costs in respect of other financial instruments are included in the initial measurement of the financial instrument. Impairment of financial assets At each reporting date, on a forward looking basis, the Company assesses the expected credit losses associated with its financial assets carried at amortized cost. Expected credit losses are measured as the difference between the cash flows that are due to the Company and the cash flows that the Company expects to receive, discounted at the effective interest rate determined at initial recognition. For trade accounts receivable, the Company applies the simplified approach permitted by IFRS 9, which requires expected lifetime credit losses to be recognized from initial recognition of the receivables. To measure expected credit losses, accounts receivable are grouped based on the number of days the receivables have been outstanding and internal credit assessments of the customers. Credit risk for longer-term receivables is assessed based on an external credit rating of the counterparty. For longer-term receivables with credit risk that has not increased significantly since the date of recognition, the Company measures the expected credit loss as the 12-month expected credit loss. Changes in the provision for expected credit loss are recognized in net earnings. |
Risk Management Activities | RISK MANAGEMENT ACTIVITIES The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis. The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural gas commodity price contracts are recognized in risk management activities in net earnings. Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized in risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are recognized in risk management activities in net earnings. Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred under accumulated other comprehensive income and amortized into net earnings in the periods in which the underlying hedged items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net earnings. Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in risk management activities in net earnings. |
Government Grants | GOVERNMENT GRANTS The Company receives or is eligible for government grants, including emissions credits. Government grants are recognized in net earnings when there is reasonable assurance that the Company will comply with the conditions attached to the grant and the grant will be received. Emissions performance and offset credits generated under the Alberta Technology Innovation and Emissions Reduction (“TIER”) regulation are initially recorded at the value prescribed by the Alberta TIER fund compliance rates in effect at the time the credits are recognized. |
Per Common Share Amounts | PER COMMON SHARE AMOUNTS The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in either cash or shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of cash settlement or share settlement under the treasury stock method. |
Share Capital | SHARE CAPITAL Common shares are classified as equity. Costs directly attributable to the issue of new shares or options are included in equity as a deduction from proceeds, net of tax. When the Company acquires its own common shares, share capital is reduced by the average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as a reduction of retained earnings. Shares are cancelled upon purchase. |
Accounting Standards Issued But Not Yet Applied | Accounting Standards Issued But Not Yet Applied In January 2020, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to clarify that liabilities are classified as either current or non-current, depending on the existence of the substantive right at the end of the reporting period for an entity to defer settlement of the liability for at least twelve months after the reporting period. In October 2022, the IASB issued further amendments to specify that the classification of debt as current or non-current at the reporting date is not affected by covenants to be complied with after the reporting date, and added disclosure requirements about these covenants. All amendments are effective January 1, 2024 with early adoption permitted. The amendments are required to be adopted retrospectively. These amendments have no impact on the Company's consolidated financial statements. |
Critical Accounting Estimates and Judgements | Critical Accounting Estimates and Judgements The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below. (A) CRUDE OIL AND NATURAL GAS RESERVES Purchase price allocations, depletion, depreciation and amortization, asset retirement obligations, and amounts used in impairment calculations are based on estimates of crude oil and natural gas reserves. Reserves estimates are based on estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures, all of which are subject to many uncertainties, interpretations and judgements including the potential impact of climate related matters and in accordance with related government regulations. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information. (B) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on its property, plant and equipment based on current legislation and operating practices. Estimated future costs include assumptions of dates of future abandonment and technological advances and estimates of future inflation rates and discount rates. Actual costs may vary from the estimated provision due to changes in environmental legislation, the impact of inflation, changes in technology, changes in operating practices, revisions to work scope, changes in the date of abandonment due to changes in reserves life, and the potential impact of climate related matters and in accordance with related government regulations. These differences may have a material impact on the estimated provision. (C) INCOME TAXES The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be due. (D) FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility, interest rate yield curves and foreign exchange rates. (E) PURCHASE PRICE ALLOCATIONS Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation, and amortization expense and impairment tests. (F) SHARE-BASED COMPENSATION The Company has made various assumptions in estimating the fair values of stock options granted under its Option Plan, including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the estimated fair value of the liability. (G) IDENTIFICATION OF CGUs CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, shared infrastructures, and the way in which management monitors the Company’s operations. (H) IMPAIRMENT OF ASSETS The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGUs' or the assets' fair value less costs of disposal and its value in use. These calculations require the use of estimates and assumptions and are subject to change as new information becomes available, including information on future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and operating costs, after-tax discount rates (currently ranging from 10% to 12%), and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs. (I) LEASES Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility. To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit in the lease is not readily determinable. (J) CONTINGENCIES Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a future event. The assessment of contingencies requires the application of judgements and estimates including the determination of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows required to settle the contingency. |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Inventories [Abstract] | |
Schedule of Inventory | 2023 2022 Product inventory $ 546 $ 611 Materials, supplies and other 1,488 1,204 $ 2,034 $ 1,815 |
Exploration and Evaluation As_2
Exploration and Evaluation Assets (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Exploration For And Evaluation Of Mineral Resources [Abstract] | |
Detailed Information About Exploration and Evaluation Assets | Exploration and Production Oil Sands Mining and Upgrading Total North America North Sea Offshore Africa Cost At December 31, 2021 $ 2,057 $ — $ 91 $ 102 $ 2,250 Additions/Acquisitions 41 — 5 — 46 Transfers to property, plant and equipment (71) — — — (71) Derecognitions and other (1) — — — (1) Foreign exchange adjustments — — 2 — 2 At December 31, 2022 2,026 — 98 102 2,226 Additions/Acquisitions 45 — 3 — 48 Transfers to property, plant and equipment (38) — — (25) (63) Derecognitions and other (2) — — — (2) Foreign exchange adjustments — — (1) — (1) At December 31, 2023 $ 2,031 $ — $ 100 $ 77 $ 2,208 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, plant and equipment [abstract] | |
Detailed Information About Property, Plant and Equipment | Exploration and Production Oil Sands Mining and Upgrading Midstream and Refining Head Office Total North America North Sea Offshore Africa Cost At December 31, 2021 $ 77,834 $ 7,438 $ 3,980 $ 46,856 $ 466 $ 508 $ 137,082 Additions/Acquisitions 3,564 304 75 1,380 8 25 5,356 Transfers from exploration and evaluation assets 71 — — — — 71 Derecognitions (1) (394) (1) — (469) — — (864) Disposals — — — (35) — — (35) Foreign exchange adjustments and other — 517 277 — — 3 797 At December 31, 2022 81,075 8,258 4,332 47,732 474 536 142,407 Additions/Acquisitions 2,951 558 187 2,088 10 30 5,824 Transfers from exploration and evaluation assets 38 — — 25 — — 63 Derecognitions (1) (581) — — (470) — — (1,051) Foreign exchange adjustments and other — (210) (110) — — — (320) At December 31, 2023 $ 83,483 $ 8,606 $ 4,409 $ 49,375 $ 484 $ 566 $ 146,923 Accumulated depletion and depreciation At December 31, 2021 $ 52,732 $ 5,951 $ 2,923 $ 8,499 $ 183 $ 394 $ 70,682 Expense 3,502 117 148 1,684 15 23 5,489 Derecognitions (1) (394) (1) — (469) — — (864) Disposals — — — (2) — — (2) Recoverability charge — 1,620 — — — — 1,620 Foreign exchange adjustments and other (5) 419 206 — — 3 623 At December 31, 2022 55,835 8,106 3,277 9,712 198 420 77,548 Expense 3,592 40 177 1,856 15 24 5,704 Derecognitions (1) (581) — — (470) — — (1,051) Recoverability charge — 436 — — — — 436 Foreign exchange adjustments and other (6) (200) (96) 7 — — (295) At December 31, 2023 $ 58,840 $ 8,382 $ 3,358 $ 11,105 $ 213 $ 444 $ 82,342 Net book value At December 31, 2023 $ 24,643 $ 224 $ 1,051 $ 38,270 $ 271 $ 122 $ 64,581 At December 31, 2022 $ 25,240 $ 152 $ 1,055 $ 38,020 $ 276 $ 116 $ 64,859 (1) An asset is derecognized when no future economic benefits are expected to arise from its continued use or disposal. |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of leases [Abstract] | |
Schedule of Lease Assets | Product transportation and storage Field equipment and power Offshore vessels and equipment Office leases and other Total At December 31, 2021 $ 974 $ 354 $ 99 $ 81 $ 1,508 Additions 44 110 28 — 182 Depreciation (106) (86) (31) (21) (244) Foreign exchange and other — (1) 1 1 1 At December 31, 2022 912 377 97 61 1,447 Additions 27 218 49 23 317 Depreciation (98) (111) (45) (19) (273) Foreign exchange and other (1) (2) (30) — (33) At December 31, 2023 $ 840 $ 482 $ 71 $ 65 $ 1,458 LEASE ASSETS, BY SEGMENT As at December 31, 2023 and 2022, the Company had the following lease assets by segment: 2023 2022 Exploration and Production North America $ 280 $ 277 North Sea 18 1 Offshore Africa 119 98 Oil Sands Mining and Upgrading 1,001 1,015 Head Office 40 56 $ 1,458 $ 1,447 |
Schedule of Lease Liabilities | Lease liabilities at December 31, 2023 and 2022, were as follows: 2023 2022 Lease liabilities $ 1,555 $ 1,540 Less: current portion 298 244 $ 1,257 $ 1,296 |
Schedule of Leases Impact on Net Earnings and Cash Flow | Other amounts included in net earnings and cash flows during 2023 and 2022 are provided below: 2023 2022 Expenses relating to short-term leases (1) $ 403 $ 410 Interest expense on lease liabilities $ 64 $ 60 Variable lease payments not included in the measurement of lease liabilities $ 59 $ 49 Total cash outflows for leases (2) $ 1,325 $ 1,204 (1) During 2023, the Company capitalized $514 million (2022 – $453 million) of short-term leases as additions to property, plant and equipment. (2) Comprised of cash outflows relating to lease liabilities, short-term leases, and variable lease payments. |
Investments (Tables)
Investments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Summary of Investments | As at December 31, 2023 and 2022, the Company had the following investment: 2023 2022 Investment in PrairieSky Royalty Ltd. $ 525 $ 491 The gain from the investment in PrairieSky was comprised as follows: 2023 2022 2021 Gain from investment $ (34) $ (182) $ (81) Dividend income (22) (14) (7) $ (56) $ (196) $ (88) |
Other Long-Term Assets (Tables)
Other Long-Term Assets (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Subclassifications of assets, liabilities and equities [abstract] | |
Disclosure of Other Long-term Assets | 2023 2022 Long-term prepayments, contracts and other (1) $ 279 $ 269 Prepaid cost of service toll 179 199 Long-term inventory 141 137 Risk management (note 19) 13 9 612 614 Less: current portion 71 61 $ 541 $ 553 (1) Includes physical product sales contracts assumed in acquisitions in prior periods, accrued interest on the deferred PRT recovery, and the unamortized portion of the Company's share bonus program. |
Summary of Assets, Liabilities, Partners' Equity and Equity (Loss) Income Related to Joint Venture | The assets, liabilities, partners’ equity, product sales and equity (loss) income related to NWRP at December 31, 2023 and 2022 were comprised as follows: 2023 2022 Current assets $ 349 $ 257 Non-current assets $ 10,508 $ 10,729 Current liabilities $ 1,054 $ 849 Non-current liabilities $ 10,913 $ 11,239 Partners’ equity $ (1,110) $ (1,102) Partners’ equity at Company's 50% interest $ (555) $ (551) Revenue (1) $ 1,527 $ 1,267 Net (loss) income (2) $ (8) $ 22 (1) Included in NWRP's revenue for 2023 is $335 million (2022 – $317 million) related to the Company's 25% share of the refining toll. (2) Included in the net (loss) income for 2023 is the impact of depreciation and amortization expense of $387 million (2022 – $245 million) and interest and other financing expense of $500 million (2022 – $422 million). |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Summary of Long-term Debt | 2023 2022 Canadian dollar denominated debt, unsecured Medium-term notes 1.45% debentures due November 16, 2023 $ — $ 404 3.55% debentures due June 3, 2024 320 332 3.42% debentures due December 1, 2026 441 441 2.50% debentures due January 17, 2028 225 225 4.85% debentures due May 30, 2047 300 300 1,286 1,702 US dollar denominated debt, unsecured US dollar debt securities 3.80% due April 15, 2024 (US$500 million) 660 677 3.90% due February 1, 2025 (US$600 million) 792 812 2.05% due July 15, 2025 (US$600 million) 792 812 3.85% due June 1, 2027 (US$1,250 million) 1,651 1,692 2.95% due July 15, 2030 (US$500 million) 660 677 7.20% due January 15, 2032 (US$400 million) 528 541 6.45% due June 30, 2033 (US$350 million) 462 474 5.85% due February 1, 2035 (US$350 million) 462 474 6.50% due February 15, 2037 (US$450 million) 594 609 6.25% due March 15, 2038 (US$1,100 million) 1,453 1,488 6.75% due February 1, 2039 (US$400 million) 528 541 4.95% due June 1, 2047 (US$750 million) 991 1,015 9,573 9,812 Long-term debt before transaction costs and original issue discounts, net 10,859 11,514 Less: original issue discounts, net (1) 11 13 transaction costs (1) (2) 49 56 10,799 11,445 Less: current portion of long-term debt (1) (2) 980 404 $ 9,819 $ 11,041 (1) The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt. (2) Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. |
Schedule of Debt Repayments | Scheduled debt repayments are as follows: Year Repayment 2024 $ 980 2025 $ 1,584 2026 $ 441 2027 $ 1,651 2028 $ 225 Thereafter $ 5,978 The maturity dates of the Company’s financial liabilities were as follows: Less than 1 year 1 to less than 2 years 2 to less than 5 years Thereafter Accounts payable $ 1,418 $ — $ — $ — Accrued liabilities $ 3,534 $ — $ — $ — Long-term debt (1) $ 980 $ 1,584 $ 2,317 $ 5,978 Other long-term liabilities (2) $ 302 $ 184 $ 428 $ 645 Interest and other financing expense (3) $ 582 $ 518 $ 1,257 $ 3,362 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. (2) Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 million. (3) Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates at December 31, 2023. |
Other Long-Term Liabilities (Ta
Other Long-Term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Subclassifications of assets, liabilities and equities [abstract] | |
Disclosure of Other Long-term Liabilities | 2023 2022 Asset retirement obligations $ 7,690 $ 6,908 Lease liabilities (note 8) 1,555 1,540 Share-based compensation 780 832 Transportation and processing contracts (1) 87 159 Risk management (note 19) 4 3 Other 73 92 10,189 9,534 Less: current portion 1,503 1,373 $ 8,686 $ 8,161 (1) |
Summary of Asset Retirement Obligations | Reconciliations of the discounted asset retirement obligations were as follows: 2023 2022 2021 Balance – beginning of year $ 6,908 $ 6,806 $ 5,861 Liabilities incurred 25 20 5 Liabilities acquired, net — 11 76 Liabilities settled (509) (449) (307) Asset retirement obligation accretion 366 281 185 Revision of cost, inflation and timing estimates (1) 621 897 508 Impact of regulatory changes (2) — 982 1,208 Change in discount rates 314 (1,698) (723) Foreign exchange adjustments (35) 58 (7) Balance – end of year 7,690 6,908 6,806 Less: current portion 634 495 249 $ 7,056 $ 6,413 $ 6,557 (1) Includes normal course revisions of cost, inflation and timing estimates, as well as revisions related to the acceleration of the abandonment and subsequent cost estimate increases on future abandonment at the Ninian field in the North Sea in 2022 and 2023. (2) Reflects changes to the estimated timing of settlement of the Company's asset retirement obligations due to provincial regulatory changes in Alberta, British Columbia and Saskatchewan in 2022 and 2021. Segmented Asset Retirement Obligations 2023 2022 Exploration and Production North America $ 4,471 $ 4,326 North Sea 1,441 1,011 Offshore Africa 165 143 Oil Sands Mining and Upgrading 1,612 1,427 Midstream and Refining 1 1 $ 7,690 $ 6,908 |
Summary of Share-based Compensation Liability | The current portion of the liability represents the maximum amount of the liability payable within the next twelve month period if all vested stock options and PSUs are settled in cash. 2023 2022 2021 Balance – beginning of year $ 832 $ 489 $ 160 Share-based compensation expense 491 804 514 Cash payment for stock options surrendered and PSUs vested (110) (79) (48) Transferred to common shares (435) (387) (139) Other 2 5 2 Balance – end of year 780 832 489 Less: current portion 538 559 329 $ 242 $ 273 $ 160 |
Disclosure of Weighted Average Assumptions Used | The fair value of stock options outstanding was estimated using the Black-Scholes valuation model with the following weighted average assumptions: 2023 2022 2021 Fair value $ 35.93 $ 32.96 $ 16.98 Share price $ 86.81 $ 75.19 $ 53.45 Expected volatility 30.9% 35.8% 35.5% Expected dividend yield 4.6% 4.5% 4.4% Risk free interest rate 3.6% 3.8% 1.1% Expected forfeiture rate 5.4% 5.0% 4.7% Expected stock option life (1) 4.2 years 4.2 years 4.2 years (1) At original time of grant. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Schedule of Provision for Income Tax | The provision for income tax was as follows: Expense (recovery) 2023 2022 2021 Current corporate income tax – North America (1) $ 1,853 $ 2,789 $ 1,841 Current corporate income tax – North Sea (6) 69 7 Current corporate income tax – Offshore Africa 73 74 21 Current PRT (2) – North Sea (58) (42) (34) Other taxes 17 16 13 Current income tax 1,879 2,906 1,848 Deferred corporate income tax 267 302 399 Deferred PRT (2) – North Sea (214) (441) — Deferred income tax 53 (139) 399 Income tax $ 1,932 $ 2,767 $ 2,247 (1) Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments. (2) Petroleum Revenue Tax. |
Schedule of Provision for Income Tax Reconciliation | The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax rates to earnings before taxes. The reasons for the difference are as follows: 2023 2022 2021 Canadian statutory income tax rate 23.3% 23.2% 23.2% Income tax provision at statutory rate $ 2,364 $ 3,180 $ 2,298 Effect on income taxes of: UK PRT and other taxes (255) (467) (21) Impact of UK PRT and other taxes on corporate income tax 105 190 11 Foreign and domestic tax rate differentials (104) (203) (11) Non-taxable portion of capital gains (35) 65 (26) Stock options exercised for common shares 91 159 98 Non-taxable gain on corporate acquisitions — — (110) Revisions arising from prior year tax filings (174) (186) 16 Change in unrecognized capital loss carryforward asset (35) 65 (26) Other (25) (36) 18 Income tax $ 1,932 $ 2,767 $ 2,247 |
Summary of Major Temporary Differences, Movements in Deferred Tax Assets and Liabilities, and Net Deferred Income Tax Liability | The following table summarizes the temporary differences that give rise to the net deferred income tax liability: 2023 2022 Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets $ 12,172 $ 11,985 Lease assets 336 336 Investments 54 56 Investment in North West Redwater Partnership 904 903 Taxable PRT for corporate income tax 256 176 Other 41 25 13,763 13,481 Deferred income tax assets Asset retirement obligations (2,098) (1,822) Lease liabilities (356) (354) Share-based compensation (31) (33) Loss carryforwards (417) (652) Unrealized foreign exchange loss on long-term debt (39) (67) Deferred PRT (639) (439) (3,580) (3,367) Net deferred income tax liability $ 10,183 $ 10,114 Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows: 2023 2022 2021 Property, plant and equipment and exploration and evaluation assets $ 196 $ (334) $ 184 Lease assets 1 (15) (30) Unrealized foreign exchange on long-term debt 28 (81) 34 Unrealized risk management activities — (12) 19 Asset retirement obligations (292) (74) (213) Lease liabilities (3) 11 25 Share-based compensation 2 (11) (10) Loss carryforwards 235 618 202 Investments (2) 21 21 Investment in North West Redwater Partnership 1 53 83 Deferred PRT 86 (441) — Taxable PRT for corporate income tax (214) 176 — Other 15 (50) 84 $ 53 $ (139) $ 399 The following table summarizes the movements of the net deferred income tax liability during the year: 2023 2022 2021 Balance – beginning of year $ 10,114 $ 10,220 $ 10,144 Deferred income tax expense (recovery) 53 (139) 399 Deferred income tax expense included in other comprehensive (loss) income — — 1 Foreign exchange adjustments 16 33 (2) Business combinations — — (322) Balance – end of year $ 10,183 $ 10,114 $ 10,220 |
Share Capital (Tables)
Share Capital (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share Capital, Reserves And Other Equity Interest [Abstract] | |
Summary of Outstanding Common Stock | 2023 2022 ISSUED COMMON SHARES Number of shares (thousands) Amount Number of shares (thousands) Amount Balance – beginning of year 1,102,636 $ 10,294 1,168,369 $ 10,168 Issued upon exercise of stock options 9,822 372 11,605 442 Previously recognized liability on stock options exercised for common shares — 435 — 387 Purchase of common shares under Normal Course Issuer Bid (40,050) (389) (77,338) (703) Balance – end of year 1,072,408 $ 10,712 1,102,636 $ 10,294 |
Summary of Stock Option Activity | The following table summarizes information relating to stock options outstanding at December 31, 2023 and 2022: 2023 2022 Stock options ( thousands) Weighted average exercise price Stock options (thousands) Weighted average exercise price Outstanding – beginning of year 31,150 $ 42.37 38,327 $ 35.88 Granted 7,024 $ 80.17 7,547 $ 68.15 Exercised for common shares (9,822) $ 37.84 (11,605) $ 38.06 Surrendered for cash settlement (218) $ 38.77 (441) $ 38.43 Forfeited (1,929) $ 50.86 (2,678) $ 41.43 Outstanding – end of year 26,205 $ 53.60 31,150 $ 42.37 Exercisable – end of year 3,672 $ 42.14 5,522 $ 37.60 |
Summary of Range of Exercise Prices of Stock Options Outstanding | The range of exercise prices of stock options outstanding and exercisable at December 31, 2023 was as follows: Stock options outstanding Stock options exercisable Range of exercise prices Stock options outstanding (thousands) Weighted average remaining term (years) Weighted average exercise price Stock options exercisable (thousands) Weighted average exercise price $20.76 – $29.99 5,441 2.01 $ 27.42 969 $ 24.84 $30.00 – $39.99 5,411 1.03 $ 36.67 1,227 $ 36.56 $40.00 – $49.99 2,381 2.41 $ 40.52 630 $ 40.50 $50.00 – $59.99 433 3.86 $ 54.24 30 $ 54.24 $60.00 – $69.99 3,837 3.49 $ 64.90 301 $ 64.21 $70.00 – $79.99 7,787 4.18 $ 78.48 515 $ 76.35 $80.00 – $86.06 915 5.72 $ 84.12 — $ — 26,205 2.87 $ 53.60 3,672 $ 42.14 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Analysis Of Other Comprehensive Income By Item [Abstract] | |
Components of Accumulated Other Comprehensive Income, Net of Taxes | The components of accumulated other comprehensive income, net of taxes, were as follows: 2023 2022 Derivative financial instruments designated as cash flow hedges $ 72 $ 75 Foreign currency translation adjustment 100 134 $ 172 $ 209 |
Capital Disclosures (Tables)
Capital Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Disclosure of Detailed Information About Capital | 2023 2022 Long-term debt $ 10,799 $ 11,445 Less: cash and cash equivalents 877 920 Long-term debt, net $ 9,922 $ 10,525 Total shareholders’ equity $ 39,832 $ 38,175 Debt to book capitalization 20% 22% |
Net Earnings Per Common Share (
Net Earnings Per Common Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings per share [abstract] | |
Net Earnings Per Common Share | 2023 2022 2021 Weighted average common shares outstanding – basic (thousands of shares) 1,091,312 1,134,960 1,181,250 Effect of dilutive stock options (thousands of shares) 10,812 14,222 5,307 Weighted average common shares outstanding – diluted (thousands of shares) 1,102,124 1,149,182 1,186,557 Net earnings $ 8,233 $ 10,937 $ 7,664 Net earnings per common share – basic $ 7.54 $ 9.64 $ 6.49 – diluted $ 7.47 $ 9.52 $ 6.46 |
Interest and Other Financing _2
Interest and Other Financing Expense (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Borrowing costs [abstract] | |
Disclosure of Interest and Other Financing Expense | 2023 2022 2021 Interest and other financing expense Long-term debt $ 627 $ 610 $ 681 Lease liabilities 64 60 62 Total interest and other financing expense 691 670 743 Total interest income and other (55) (121) (32) Net interest and other financing expense $ 636 $ 549 $ 711 |
Financial Instruments (Tables)
Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Schedule of Financial Assets | The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were recognized in the financial statements as follows: Asset (liability) 2023 2022 Balance – beginning of year $ 6 $ 55 Net change in fair value of outstanding derivative financial instruments recognized in: Risk management activities (1) 3 70 Foreign exchange — (119) Balance – end of year 9 6 Less: current portion 8 — $ 1 $ 6 (1) Risk management assets and liabilities are disclosed in note 10 and note 12, respectively. |
Schedule of Financial Liabilities | The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were recognized in the financial statements as follows: Asset (liability) 2023 2022 Balance – beginning of year $ 6 $ 55 Net change in fair value of outstanding derivative financial instruments recognized in: Risk management activities (1) 3 70 Foreign exchange — (119) Balance – end of year 9 6 Less: current portion 8 — $ 1 $ 6 (1) Risk management assets and liabilities are disclosed in note 10 and note 12, respectively. |
Schedule of Information About Financial Instruments | Net (gain) loss from risk management activities for the years ended December 31, were as follows: 2023 2022 2021 Net realized risk management (gain) loss $ (14) $ (7) $ 17 Net unrealized risk management loss (gain) 12 (28) 19 $ (2) $ (35) $ 36 2023 2022 Carrying amount Level 1 Carrying amount Level 1 Fixed rate long-term debt (1) (2) $ (10,799) $ (10,795) $ (11,445) $ (10,796) (1) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (2) Includes the current portion of fixed rate long-term debt. The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the Company’s consolidated balance sheets. Asset (liability) 2023 2022 Derivatives held for trading Natural gas (1) $ (3) $ 3 Foreign currency forward contracts 12 3 $ 9 $ 6 Included within: Current portion of other long-term assets $ 12 $ 3 Current portion of other long-term liabilities (4) (3) Other long-term assets 1 6 $ 9 $ 6 (1) In 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial hedge contracts for the period of January to December 2024. |
Disclosure of Financial Instrument Sensitivities | The following table summarizes the annualized sensitivities of the Company’s 2023 net earnings and other comprehensive income to changes in the fair value of financial instruments outstanding as at December 31, 2023, resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those disclosed in the Company’s other continuous disclosure documents, are limited to the impact of changes in a specified variable applied to financial instruments only and do not represent the impact of a change in the variable on the operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear. 2023 2022 Increase (decrease) to net earnings Increase (decrease) to other comprehensive income Increase (decrease) to net earnings Increase (decrease) to other comprehensive income Interest rate risk Increase interest rate 1% $ (5) $ — $ (4) $ — Decrease interest rate 1% $ 5 $ — $ 4 $ — Foreign currency exchange rate risk Weakening of the Canadian dollar by US$0.01 $ (128) $ — $ (135) $ — Strengthening of the Canadian dollar by US$0.01 $ 125 $ — $ 131 $ — |
Schedule of Maturity Dates for Financial Liabilities | Scheduled debt repayments are as follows: Year Repayment 2024 $ 980 2025 $ 1,584 2026 $ 441 2027 $ 1,651 2028 $ 225 Thereafter $ 5,978 The maturity dates of the Company’s financial liabilities were as follows: Less than 1 year 1 to less than 2 years 2 to less than 5 years Thereafter Accounts payable $ 1,418 $ — $ — $ — Accrued liabilities $ 3,534 $ — $ — $ — Long-term debt (1) $ 980 $ 1,584 $ 2,317 $ 5,978 Other long-term liabilities (2) $ 302 $ 184 $ 428 $ 645 Interest and other financing expense (3) $ 582 $ 518 $ 1,257 $ 3,362 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. (2) Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 million. (3) Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates at December 31, 2023. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract] | |
Disclosure of Future Payments | The following table summarizes the Company’s commitments as at December 31, 2023: 2024 2025 2026 2027 2028 Thereafter Product transportation and processing (1) $ 1,572 $ 1,595 $ 1,408 $ 1,358 $ 1,242 $ 13,380 North West Redwater Partnership service toll (2) $ 158 $ 157 $ 139 $ 126 $ 130 $ 4,985 Offshore vessels and equipment $ 36 $ — $ — $ — $ — $ — Field equipment and power $ 38 $ 25 $ 23 $ 22 $ 22 $ 193 Other $ 145 $ 111 $ 112 $ 25 $ 26 $ 355 (1) The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion reflects interim tolls approved by the Canada Energy Regulator in 2023, and is subject to change pending the approval of final tolls. (2) Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $3,011 million of interest payable over the 40-year tolling period, ending in 2058 (note 10). |
Supplemental Disclosure of Ca_2
Supplemental Disclosure of Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Statement Of Cash Flows, Additional Disclosures [Abstract] | |
Schedule of Cash Flow Supplemental Disclosures | 2023 2022 2021 Changes in non-cash working capital: Accounts receivable $ 368 $ (441) $ (850) Inventory (219) (266) (487) Prepaids and other (23) (20) 39 Accounts payable 78 537 80 Accrued liabilities (812) 896 525 Current income tax (liabilities) assets (1,558) (282) 1,918 Other long-term liabilities (200) (196) (154) Net changes in non-cash working capital $ (2,366) $ 228 $ 1,071 Relating to: Operating activities $ (2,417) $ 79 $ 964 Investing activities 51 149 107 $ (2,366) $ 228 $ 1,071 |
Reconciliation of Liabilities Arising From Financing Activities | The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended December 31, 2023 and 2022: Long-term debt Cash flow hedges on US dollar debt securities Lease liabilities Liabilities from financing activities At December 31, 2021 $ 14,694 $ (119) $ 1,584 $ 16,159 Changes from financing cash flows: Repayment of long-term debt, net (1) (4,010) — — (4,010) Proceeds on settlement of cross currency swaps — 69 — 69 Payment of lease liabilities — — (232) (232) Non-cash changes: Lease additions — — 182 182 Changes in foreign exchange and fair value (2) 761 50 6 817 At December 31, 2022 11,445 — 1,540 12,985 Changes from financing cash flows: Repayment of long-term debt, net (1) (416) — — (416) Payment of lease liabilities — — (285) (285) Non-cash changes: Lease additions — — 317 317 Changes in foreign exchange and fair value (2) (230) — (17) (247) At December 31, 2023 $ 10,799 $ — $ 1,555 $ 12,354 (1) Includes original issue discounts and premiums, and directly attributable transaction costs. (2) Includes foreign exchange (gain) loss, changes in the fair value of cash flow hedges on US dollar debt securities, the amortization of original issue discounts and premiums and directly attributable transaction costs, and derecognition of lease liabilities. |
Segmented Information (Tables)
Segmented Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Operating Segments [Abstract] | |
Disclosure of Operating Segments | North America North Sea Offshore Africa (millions of Canadian dollars) 2023 2022 2021 2023 2022 2021 2023 2022 2021 Segmented product sales Crude oil and NGLs (1) $ 17,375 $ 20,755 $ 14,478 $ 435 $ 623 $ 607 $ 577 $ 694 $ 420 Natural gas 2,375 4,931 2,484 7 13 5 51 55 31 Other income and revenue (2) 10 217 119 — — (1) 9 8 7 Total segmented product sales 19,760 25,903 17,081 442 636 611 637 757 458 Less: royalties (2,443) (3,918) (1,694) (1) (1) (1) (57) (71) (21) Segmented revenue 17,317 21,985 15,387 441 635 610 580 686 437 Segmented expenses Production 3,617 3,754 2,963 342 437 383 141 114 91 Transportation, blending and feedstock (1) 5,808 6,394 4,772 7 6 7 1 1 1 Depletion, depreciation and amortization (3) 3,679 3,595 3,569 494 1,747 160 213 173 142 Asset retirement obligation accretion 234 171 101 46 33 21 8 7 6 Risk management activities (commodity derivatives) 24 18 29 — — — — — — Gain on acquisitions — — (478) — — — — — — Income from NWRP — — — — — — — — — Total segmented expenses 13,362 13,932 10,956 889 2,223 571 363 295 240 Segmented earnings (loss) $ 3,955 $ 8,053 $ 4,431 $ (448) $ (1,588) $ 39 $ 217 $ 391 $ 197 Non-segmented expenses Administration Share-based compensation Interest and other financing expense Risk management activities (other) Foreign exchange (gain) loss Gain from investments Total non-segmented expenses Earnings before taxes Current income tax Deferred income tax Net earnings (1) Includes blending and feedstock costs associated with the processing of third party bitumen and other purchased feedstock in the Oil Sands Mining and Upgrading segment. (2) Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations partners' share of the costs of lease contracts. (3) Includes a recoverability charge in depletion, depreciation and amortization, related to the Ninian field in the North Sea at December 31, 2023 for $436 million (December 31, 2022 – $1,620 million) (note 7). Oil Sands Mining and Upgrading Midstream and Refining Inter-segment elimination and Other Total 2023 2022 2021 2023 2022 2021 2023 2022 2021 2023 2022 2021 $ 18,661 $ 20,804 $ 14,033 $ 76 $ 80 $ 78 $ 176 $ 53 $ (360) $ 37,300 $ 43,009 $ 29,256 — — — — — — 142 237 196 2,575 5,236 2,716 5 149 73 926 906 681 10 5 3 960 1,285 882 18,666 20,953 14,106 1,002 986 759 328 295 (161) 40,835 49,530 32,854 (2,366) (3,242) (1,081) — — — — — — (4,867) (7,232) (2,797) 16,300 17,711 13,025 1,002 986 759 328 295 (161) 35,968 42,298 30,057 3,989 4,076 3,414 332 271 234 59 60 67 8,480 8,712 7,152 2,563 2,652 1,505 664 691 550 259 229 (231) 9,302 9,973 6,604 2,011 1,822 1,838 16 16 15 — — — 6,413 7,353 5,724 78 70 57 — — — — — — 366 281 185 — — — — — — — — — 24 18 29 — — — — — — — — — — — (478) — — — — — (400) — — — — — (400) 8,641 8,620 6,814 1,012 978 399 318 289 (164) 24,585 26,337 18,816 $ 7,659 $ 9,091 $ 6,211 $ (10) $ 8 $ 360 $ 10 $ 6 $ 3 $ 11,383 $ 15,961 $ 11,241 452 415 366 491 804 514 636 549 711 (26) (53) 7 (279) 738 (127) (56) (196) (141) 1,218 2,257 1,330 10,165 13,704 9,911 1,879 2,906 1,848 53 (139) 399 $ 8,233 $ 10,937 $ 7,664 2023 2022 Net expenditures Non-cash and fair value changes (2) Capitalized costs Net expenditures Non-cash and fair value changes (2) Capitalized costs Exploration and evaluation assets Exploration and Production North America $ 41 $ (36) $ 5 $ 28 $ (59) $ (31) Offshore Africa 3 — 3 5 — 5 Oil Sands Mining and Upgrading — (25) (25) — — — 44 (61) (17) 33 (59) (26) Property, plant and equipment Exploration and Production North America 2,729 (321) 2,408 3,105 136 3,241 North Sea 33 525 558 126 177 303 Offshore Africa 169 18 187 119 (44) 75 2,931 222 3,153 3,350 269 3,619 Oil Sands Mining and Upgrading 1,894 (251) 1,643 1,719 (843) 876 Midstream and Refining 10 — 10 9 (1) 8 Head Office 30 — 30 25 — 25 4,865 (29) 4,836 5,103 (575) 4,528 $ 4,909 $ (90) $ 4,819 $ 5,136 $ (634) $ 4,502 (1) This table provides a reconciliation of capitalized costs, reported in note 6 and note 7, to net expenditures reported in the investing activities section of the statements of cash flows. The reconciliation excludes the impact of foreign exchange adjustments. (2) Derecognitions, asset retirement obligations, transfer of exploration and evaluation assets, and other fair value adjustments. 2023 2022 Exploration and Production North America $ 30,058 $ 31,135 North Sea 602 378 Offshore Africa 1,380 1,322 Other 32 54 Oil Sands Mining and Upgrading 42,865 42,102 Midstream and Refining 856 979 Head Office 162 172 $ 75,955 $ 76,142 |
Remuneration of Directors and_2
Remuneration of Directors and Senior Management (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Related Party [Abstract] | |
Remuneration of Non-management Directors and Senior Management | REMUNERATION OF NON-MANAGEMENT DIRECTORS 2023 2022 2021 Fees earned $ 3 $ 2 $ 2 REMUNERATION OF SENIOR MANAGEMENT (1) 2023 2022 2021 Salary $ 2 $ 2 $ 2 Common stock option based awards 13 12 10 Annual incentive plans 5 5 6 Long-term incentive plans 19 18 19 $ 39 $ 37 $ 37 (1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to shareholders for the respective years. |
Supplementary Oil And Gas Inf_2
Supplementary Oil And Gas Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Schedule of Twelve Month Average Benchmark Prices | The Company has used the following 12-month average benchmark prices to determine its 2023 and 2022 reserves for SEC requirements. Crude Oil and NGLs Natural Gas WTI WCS Canadian Light Sweet Cromer LSB Brent Edmonton C5+ Henry Hub AECO BC Westcoast Station 2 (US$/bbl) (C$/bbl) (C$/bbl) (C$/bbl) (US$/bbl) (C$/bbl) (US$/MMBtu) (C$/MMBtu) (C$/MMBtu) 2023 78.10 79.95 100.93 99.48 82.51 103.43 2.75 2.79 2.10 2022 94.13 99.40 118.90 117.76 97.98 119.93 6.44 5.59 4.51 |
Schedule of Crude Oil, NGL's and Natural Gas Net Proved Reserve Quantities | The following tables summarize the Company's proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2023, 2022, 2021 and 2020: North America Crude Oil and NGLs (MMbbl) (1) Synthetic Bitumen (2) Crude Oil North North Offshore Total Net Proved Reserves Reserves, December 31, 2020 6,847 2,413 525 9,785 87 71 9,943 Extensions and discoveries — 101 14 115 — — 115 Improved recovery — 19 14 33 — — 33 Purchases of reserves in place — — 52 52 — — 52 Sales of reserves in place — — — — — — — Production (150) (103) (45) (297) (6) (5) (309) Economic revisions due to prices (3) (927) (296) 108 (1,115) 1 (4) (1,118) Revisions of prior estimates 174 155 40 369 (3) 2 368 Reserves, December 31, 2021 5,944 2,289 708 8,941 79 64 9,083 Extensions and discoveries — 195 11 205 — — 205 Improved recovery 29 5 21 56 — — 56 Purchases of reserves in place — 267 21 288 — — 288 Sales of reserves in place — — — — — — — Production (128) (91) (45) (265) (5) (5) (274) Economic revisions due to prices (3) (455) (263) (73) (791) 1 (2) (792) Revisions of prior estimates — 144 54 198 (64) — 134 Reserves, December 31, 2022 5,390 2,546 696 8,632 11 57 8,700 Extensions and discoveries 162 67 51 280 — — 280 Improved recovery 28 9 37 75 — — 75 Purchases of reserves in place — — — — — — — Sales of reserves in place — — (1) (1) — — (1) Production (141) (102) (47) (289) (5) (4) (298) Economic revisions due to prices (3) 333 123 29 484 — 1 485 Revisions of prior estimates 68 26 1 94 3 1 98 Reserves, December 31, 2023 5,840 2,669 767 9,276 9 54 9,339 Net Proved Developed Reserves December 31, 2020 6,770 628 285 7,682 32 37 7,751 December 31, 2021 5,929 584 370 6,883 39 38 6,960 December 31, 2022 5,389 582 359 6,330 5 34 6,369 December 31, 2023 5,804 610 337 6,752 6 30 6,787 (1) Information in the reserves data tables may not add due to rounding. (2) Bitumen as defined by the SEC, "is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis." Under this definition, all the Company's thermal and primary heavy crude oil reserves have been classified as bitumen. (3) Includes changes due to commodity price and resulting royalty volumes. Natural Gas (Bcf) (1) North America North Sea Offshore Africa Total Net Proved Reserves Reserves, December 31, 2020 7,655 12 34 7,701 Extensions and discoveries 545 — — 545 Improved recovery 161 — — 161 Purchases of reserves in place 1,654 — — 1,654 Sales of reserves in place (1) — — (1) Production (581) (1) (4) (587) Economic revisions due to prices (2) 712 — (4) 708 Revisions of prior estimates 1,139 (3) — 1,136 Reserves, December 31, 2021 11,285 8 25 11,318 Extensions and discoveries 251 — — 251 Improved recovery 192 — — 192 Purchases of reserves in place 228 — — 228 Sales of reserves in place — — — — Production (688) (1) (4) (693) Economic revisions due to prices (2) (572) — (3) (575) Revisions of prior estimates 1,521 (3) 7 1,526 Reserves, December 31, 2022 12,217 4 25 12,246 Extensions and discoveries 1,185 — — 1,185 Improved recovery 603 — — 603 Purchases of reserves in place — — — — Sales of reserves in place (6) — — (6) Production (750) (1) (4) (755) Economic revisions due to prices (2) 87 — 1 88 Revisions of prior estimates 57 (1) 1 58 Reserves, December 31, 2023 13,393 3 23 13,419 Net Proved Developed Reserves December 31, 2020 3,116 6 22 3,144 December 31, 2021 4,469 3 20 4,492 December 31, 2022 4,956 1 19 4,975 December 31, 2023 4,029 1 10 4,040 (1) Information in the reserves data tables may not add due to rounding. (2) Includes changes due to commodity price and resulting royalty volumes. |
Schedule of Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure | Capitalized Costs Related to Crude Oil and Natural Gas Activities 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 132,858 $ 8,606 $ 4,409 $ 145,873 Unproved properties 2,108 — 100 2,208 134,966 8,606 4,509 148,081 Less: accumulated depletion and depreciation (69,945) (8,382) (3,358) (81,685) Net capitalized costs $ 65,021 $ 224 $ 1,151 $ 66,396 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 128,807 $ 8,258 $ 4,332 $ 141,397 Unproved properties 2,128 — 98 2,226 130,935 8,258 4,430 143,623 Less: accumulated depletion and depreciation (65,547) (8,106) (3,277) (76,930) Net capitalized costs $ 65,388 $ 152 $ 1,153 $ 66,693 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 124,690 $ 7,438 $ 3,980 $ 136,108 Unproved properties 2,159 — 91 2,250 126,849 7,438 4,071 138,358 Less: accumulated depletion and depreciation (61,231) (5,951) (2,923) (70,105) Net capitalized costs $ 65,618 $ 1,487 $ 1,148 $ 68,253 |
Disclosure of Detailed Information About Costs Incurred In Crude Oil And Natural Gas Activities | Costs Incurred in Crude Oil and Natural Gas Activities 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ — $ — $ — $ — Unproved — — — — Exploration 43 — 3 46 Development 5,039 558 187 5,784 Costs incurred $ 5,082 $ 558 $ 190 $ 5,830 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 524 $ — $ — $ 524 Unproved — — — — Exploration 40 — 5 45 Development 4,387 304 75 4,766 Costs incurred $ 4,951 $ 304 $ 80 $ 5,335 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 1,371 $ — $ — $ 1,371 Unproved 26 — — 26 Exploration 4 — 8 12 Development 4,301 208 48 4,557 Costs incurred $ 5,702 $ 208 $ 56 $ 5,966 |
Disclosure Of Detailed Information About Results Of Operations From Crude Oil And Natural Gas Activities | The Company's results of operations from crude oil and natural gas producing activities for the years ended December 31, 2023, 2022 and 2021 are summarized in the following tables: 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 26,773 $ 442 $ 581 $ 27,796 Production (7,606) (342) (141) (8,089) Transportation (1,550) (7) (1) (1,558) Depletion, depreciation and amortization (5,690) (494) (213) (6,397) Asset retirement obligation accretion (312) (46) (8) (366) Petroleum revenue tax — 273 — 273 Income tax (2,700) 70 (54) (2,684) Results of operations $ 8,915 $ (104) $ 164 $ 8,975 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 31,698 $ 635 $ 687 $ 33,020 Production (7,830) (437) (114) (8,381) Transportation (1,424) (6) (1) (1,431) Depletion, depreciation and amortization (5,417) (1,747) (173) (7,337) Asset retirement obligation accretion (241) (33) (7) (281) Petroleum revenue tax — 483 — 483 Income tax (3,896) 442 (98) (3,552) Results of operations $ 12,890 $ (663) $ 294 $ 12,521 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 23,111 $ 611 $ 438 $ 24,160 Production (6,377) (383) (91) (6,851) Transportation (1,176) (7) (1) (1,184) Depletion, depreciation and amortization (5,407) (160) (142) (5,709) Asset retirement obligation accretion (158) (21) (6) (185) Petroleum revenue tax — 33 — 33 Income tax (2,317) (29) (50) (2,396) Results of operations $ 7,676 $ 44 $ 148 $ 7,868 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | The following tables summarize the Company's future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 - "Extractive Activities - Oil and Gas": 2023 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 863,544 $ 1,067 $ 6,144 $ 870,755 Future production costs (276,498) (636) (1,880) (279,014) Future development costs and asset retirement obligations (86,615) (1,873) (1,927) (90,415) Future income taxes (113,516) 967 (508) (113,057) Future net cash flows 386,915 (475) 1,829 388,269 10% annual discount for timing of future cash flows (278,814) 168 (887) (279,533) Standardized measure of future net cash flows (1) $ 108,101 $ (307) $ 942 $ 108,736 (1) Includes abandonment cost estimates for the Ninian field. 2022 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 986,672 $ 1,506 $ 7,304 $ 995,482 Future production costs (303,270) (691) (1,998) (305,959) Future development costs and asset retirement obligations (83,803) (1,416) (1,439) (86,658) Future income taxes (136,905) 517 (900) (137,288) Future net cash flows 462,694 (84) 2,967 465,577 10% annual discount for timing of future cash flows (327,333) 84 (1,330) (328,579) Standardized measure of future net cash flows (1) $ 135,361 $ — $ 1,637 $ 136,998 (1) Includes abandonment cost estimates for the Ninian field. 2021 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 679,123 $ 7,791 $ 5,581 $ 692,495 Future production costs (238,144) (4,074) (1,818) (244,036) Future development costs and asset retirement obligations (77,375) (1,857) (1,142) (80,374) Future income taxes (81,860) (719) (565) (83,144) Future net cash flows 281,744 1,141 2,056 284,941 10% annual discount for timing of future cash flows (201,227) (142) (788) (202,157) Standardized measure of future net cash flows $ 80,517 $ 999 $ 1,268 $ 82,784 |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows | The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table: (millions of Canadian dollars) 2023 2022 2021 Sales of crude oil and natural gas produced, net of production costs $ (18,174) $ (23,242) $ (16,149) Net changes in sales prices and production costs (47,145) 79,291 74,558 Extensions, discoveries and improved recovery 8,196 6,198 2,948 Changes in estimated future development costs (1,511) (3,640) (2,773) Purchases of proved reserves in place — 5,745 4,010 Sales of proved reserves in place (47) — (1) Revisions of previous reserve estimates 6,647 (9,956) (186) Accretion of discount 17,769 10,712 3,460 Changes in production timing and other (2,831) 5,463 6,638 Net change in income taxes 8,834 (16,357) (17,232) Net change (28,262) 54,214 55,273 Balance - beginning of year 136,998 82,784 27,511 Balance - end of year $ 108,736 $ 136,998 $ 82,784 |
Accounting Policies - Narrative
Accounting Policies - Narrative (Details) | 12 Months Ended |
Dec. 31, 2023 | |
Performance Share Units | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Vesting term (in years) | 3 years |
Bottom of range | Midstream and Refining | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life (in years) | 5 years |
Top of range | Midstream and Refining | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life (in years) | 30 years |
Other equipment | Bottom of range | Oil Sands Mining and Upgrading | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life (in years) | 2 years |
Other equipment | Top of range | Oil Sands Mining and Upgrading | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life (in years) | 20 years |
Critical Accounting Estimates_2
Critical Accounting Estimates and Judgements - Narrative (Details) | Dec. 31, 2023 |
Bottom of range | |
Disclosure of fair value measurement of assets [line items] | |
Discount rate used in current measurement of higher of fair value less costs of disposal or previous estimate of value in use | 10% |
Top of range | |
Disclosure of fair value measurement of assets [line items] | |
Discount rate used in current measurement of higher of fair value less costs of disposal or previous estimate of value in use | 12% |
Inventory - Schedule of Invento
Inventory - Schedule of Inventory (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Inventories [Abstract] | ||
Product inventory | $ 546 | $ 611 |
Materials, supplies and other | 1,488 | 1,204 |
Total inventory | 2,034 | 1,815 |
Cost of inventories recognised as expense during period | $ 29,000 | $ 33,000 |
Exploration and Evaluation As_3
Exploration and Evaluation Assets - Detailed information about exploration and evaluation assets (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | $ 2,226 | $ 2,250 |
Additions/Acquisitions | 48 | 46 |
Transfers to property, plant and equipment | (63) | (71) |
Derecognitions and other | (2) | (1) |
Foreign exchange adjustments | (1) | 2 |
Ending balance | 2,208 | 2,226 |
North America | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 2,026 | 2,057 |
Additions/Acquisitions | 45 | 41 |
Transfers to property, plant and equipment | (38) | (71) |
Derecognitions and other | (2) | (1) |
Foreign exchange adjustments | 0 | 0 |
Ending balance | 2,031 | 2,026 |
North Sea | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 0 | 0 |
Additions/Acquisitions | 0 | 0 |
Transfers to property, plant and equipment | 0 | 0 |
Derecognitions and other | 0 | 0 |
Foreign exchange adjustments | 0 | 0 |
Ending balance | 0 | 0 |
Offshore Africa | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 98 | 91 |
Additions/Acquisitions | 3 | 5 |
Transfers to property, plant and equipment | 0 | 0 |
Derecognitions and other | 0 | 0 |
Foreign exchange adjustments | (1) | 2 |
Ending balance | 100 | 98 |
Oil Sands Mining and Upgrading | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 102 | 102 |
Additions/Acquisitions | 0 | 0 |
Transfers to property, plant and equipment | (25) | 0 |
Derecognitions and other | 0 | 0 |
Foreign exchange adjustments | 0 | 0 |
Ending balance | $ 77 | $ 102 |
Property, Plant and Equipment -
Property, Plant and Equipment - Detailed information about property, plant and equipment (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | $ 64,859 | |
Property, plant and equipment at end of period | 64,581 | $ 64,859 |
North Sea | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Recoverability charge | 436 | 1,620 |
Operating segments | North America | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 25,240 | |
Property, plant and equipment at end of period | 24,643 | 25,240 |
Operating segments | North Sea | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 152 | |
Property, plant and equipment at end of period | 224 | 152 |
Operating segments | Offshore Africa | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 1,055 | |
Property, plant and equipment at end of period | 1,051 | 1,055 |
Operating segments | Oil Sands Mining and Upgrading | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 38,020 | |
Property, plant and equipment at end of period | 38,270 | 38,020 |
Operating segments | Midstream and Refining | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 276 | |
Property, plant and equipment at end of period | 271 | 276 |
Head Office | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 116 | |
Property, plant and equipment at end of period | 122 | 116 |
Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 142,407 | 137,082 |
Additions/Acquisitions | 5,824 | 5,356 |
Transfers from exploration and evaluation assets | 63 | 71 |
Derecognitions | (1,051) | (864) |
Disposals | (35) | |
Foreign exchange adjustments and other | 320 | (797) |
Property, plant and equipment at end of period | 146,923 | 142,407 |
Cost | Operating segments | North America | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 81,075 | 77,834 |
Additions/Acquisitions | 2,951 | 3,564 |
Transfers from exploration and evaluation assets | 38 | 71 |
Derecognitions | (581) | (394) |
Disposals | 0 | |
Foreign exchange adjustments and other | 0 | 0 |
Property, plant and equipment at end of period | 83,483 | 81,075 |
Cost | Operating segments | North Sea | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 8,258 | 7,438 |
Additions/Acquisitions | 558 | 304 |
Transfers from exploration and evaluation assets | 0 | 0 |
Derecognitions | 0 | (1) |
Disposals | 0 | |
Foreign exchange adjustments and other | 210 | (517) |
Property, plant and equipment at end of period | 8,606 | 8,258 |
Cost | Operating segments | Offshore Africa | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 4,332 | 3,980 |
Additions/Acquisitions | 187 | 75 |
Transfers from exploration and evaluation assets | 0 | 0 |
Derecognitions | 0 | 0 |
Disposals | 0 | |
Foreign exchange adjustments and other | 110 | (277) |
Property, plant and equipment at end of period | 4,409 | 4,332 |
Cost | Operating segments | Oil Sands Mining and Upgrading | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 47,732 | 46,856 |
Additions/Acquisitions | 2,088 | 1,380 |
Transfers from exploration and evaluation assets | 25 | |
Derecognitions | (470) | (469) |
Disposals | (35) | |
Foreign exchange adjustments and other | 0 | 0 |
Property, plant and equipment at end of period | 49,375 | 47,732 |
Cost | Operating segments | Midstream and Refining | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 474 | 466 |
Additions/Acquisitions | 10 | 8 |
Transfers from exploration and evaluation assets | 0 | 0 |
Derecognitions | 0 | 0 |
Disposals | 0 | |
Foreign exchange adjustments and other | 0 | 0 |
Property, plant and equipment at end of period | 484 | 474 |
Cost | Head Office | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | 536 | 508 |
Additions/Acquisitions | 30 | 25 |
Transfers from exploration and evaluation assets | 0 | 0 |
Derecognitions | 0 | 0 |
Disposals | 0 | |
Foreign exchange adjustments and other | 0 | (3) |
Property, plant and equipment at end of period | 566 | 536 |
Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | (77,548) | (70,682) |
Expense | 5,704 | 5,489 |
Derecognitions | 1,051 | 864 |
Disposals | 2 | |
Recoverability charge | 436 | 1,620 |
Foreign exchange adjustments and other | (295) | 623 |
Property, plant and equipment at end of period | (82,342) | (77,548) |
Accumulated depletion and depreciation | Operating segments | North America | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | (55,835) | (52,732) |
Expense | 3,592 | 3,502 |
Derecognitions | 581 | 394 |
Disposals | 0 | |
Recoverability charge | 0 | 0 |
Foreign exchange adjustments and other | (6) | (5) |
Property, plant and equipment at end of period | (58,840) | (55,835) |
Accumulated depletion and depreciation | Operating segments | North Sea | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | (8,106) | (5,951) |
Expense | 40 | 117 |
Derecognitions | 0 | 1 |
Disposals | 0 | |
Recoverability charge | 436 | 1,620 |
Foreign exchange adjustments and other | (200) | 419 |
Property, plant and equipment at end of period | (8,382) | (8,106) |
Accumulated depletion and depreciation | Operating segments | Offshore Africa | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | (3,277) | (2,923) |
Expense | 177 | 148 |
Derecognitions | 0 | 0 |
Disposals | 0 | |
Recoverability charge | 0 | 0 |
Foreign exchange adjustments and other | (96) | 206 |
Property, plant and equipment at end of period | (3,358) | (3,277) |
Accumulated depletion and depreciation | Operating segments | Oil Sands Mining and Upgrading | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | (9,712) | (8,499) |
Expense | 1,856 | 1,684 |
Derecognitions | 470 | 469 |
Disposals | 2 | |
Recoverability charge | 0 | 0 |
Foreign exchange adjustments and other | 7 | 0 |
Property, plant and equipment at end of period | (11,105) | (9,712) |
Accumulated depletion and depreciation | Operating segments | Midstream and Refining | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | (198) | (183) |
Expense | 15 | 15 |
Derecognitions | 0 | 0 |
Disposals | 0 | |
Recoverability charge | 0 | 0 |
Foreign exchange adjustments and other | 0 | 0 |
Property, plant and equipment at end of period | (213) | (198) |
Accumulated depletion and depreciation | Head Office | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Property, plant and equipment at beginning of period | (420) | (394) |
Expense | 24 | 23 |
Derecognitions | 0 | 0 |
Disposals | 0 | |
Recoverability charge | 0 | 0 |
Foreign exchange adjustments and other | 0 | 3 |
Property, plant and equipment at end of period | $ (444) | $ (420) |
Property, Plant and Equipment_2
Property, Plant and Equipment - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) property | |
STORM Resources Ltd | |||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | |||
Cash consideration | $ 771,000,000 | ||
North Sea | |||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | |||
Recoverability charge, net of taxes | $ 113,000,000 | $ 651,000,000 | |
Recoverability charge | 436,000,000 | 1,620,000,000 | |
Deferred income tax recovery | 323,000,000 | 969,000,000 | |
Oil Sands Mining and Upgrading | |||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | |||
Project costs not subject to depletion and depreciation | $ 191,000,000 | 162,000,000 | |
North America Exploration And Production segment - Crude Oil And Natural Gas Properties | |||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | |||
Total purchase consideration | 513,000,000 | ||
Asset retirement obligations | 11,000,000 | ||
Deferred tax liability | 0 | ||
Gains on acquisitions of property, plant and equipment, pre-tax | $ 0 | ||
British Columbia - Gas Producing Assets And Processing Infrastructure Segment | |||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | |||
Total purchase consideration | 131,000,000 | ||
Asset retirement obligations | 58,000,000 | ||
Gains on acquisitions of property, plant and equipment, pre-tax | $ 478,000,000 | ||
Number of acquisitions | property | 2 | ||
Property, plant and equipment | $ 257,000,000 | ||
Exploration and evaluation assets | 13,000,000 | ||
Non-current liabilities recognised as of acquisition date | 65,000,000 | ||
Deferred tax assets recognised as of acquisition date | $ 462,000,000 |
Leases - Lease Assets (Details)
Leases - Lease Assets (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure Of Information About Lease Assets Explanatory [Line Items] | ||
Lease assets, beginning balance | $ 1,447 | $ 1,508 |
Additions | 317 | 182 |
Depreciation | (273) | (244) |
Foreign exchange and other | (33) | 1 |
Lease assets, ending balance | 1,458 | 1,447 |
Product transportation and storage | ||
Disclosure Of Information About Lease Assets Explanatory [Line Items] | ||
Lease assets, beginning balance | 912 | 974 |
Additions | 27 | 44 |
Depreciation | (98) | (106) |
Foreign exchange and other | (1) | 0 |
Lease assets, ending balance | 840 | 912 |
Field equipment and power | ||
Disclosure Of Information About Lease Assets Explanatory [Line Items] | ||
Lease assets, beginning balance | 377 | 354 |
Additions | 218 | 110 |
Depreciation | (111) | (86) |
Foreign exchange and other | (2) | (1) |
Lease assets, ending balance | 482 | 377 |
Offshore vessels and equipment | ||
Disclosure Of Information About Lease Assets Explanatory [Line Items] | ||
Lease assets, beginning balance | 97 | 99 |
Additions | 49 | 28 |
Depreciation | (45) | (31) |
Foreign exchange and other | (30) | 1 |
Lease assets, ending balance | 71 | 97 |
Office leases and other | ||
Disclosure Of Information About Lease Assets Explanatory [Line Items] | ||
Lease assets, beginning balance | 61 | 81 |
Additions | 23 | 0 |
Depreciation | (19) | (21) |
Foreign exchange and other | 0 | 1 |
Lease assets, ending balance | $ 65 | $ 61 |
Leases - Lease Assets by Segmen
Leases - Lease Assets by Segment (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure of operating segments [line items] | |||
Lease assets | $ 1,458 | $ 1,447 | $ 1,508 |
Operating segments | North America | |||
Disclosure of operating segments [line items] | |||
Lease assets | 280 | 277 | |
Operating segments | North Sea | |||
Disclosure of operating segments [line items] | |||
Lease assets | 18 | 1 | |
Operating segments | Offshore Africa | |||
Disclosure of operating segments [line items] | |||
Lease assets | 119 | 98 | |
Operating segments | Oil Sands Mining and Upgrading | |||
Disclosure of operating segments [line items] | |||
Lease assets | 1,001 | 1,015 | |
Head Office | |||
Disclosure of operating segments [line items] | |||
Lease assets | $ 40 | $ 56 |
Leases - Lease Liabilities and
Leases - Lease Liabilities and Expense (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Lease liabilities [abstract] | |||
Lease liabilities | $ 1,555 | $ 1,540 | |
Less: current portion | 298 | 244 | |
Non-current lease liabilities | 1,257 | 1,296 | |
Expenses relating to short-term leases | 403 | 410 | |
Interest expense on lease liabilities | 64 | 60 | $ 62 |
Variable lease payments not included in the measurement of lease liabilities | 59 | 49 | |
Total cash outflows for leases | 1,325 | 1,204 | |
Increase through capitalization of short-term leases, property, plant and equipment | $ 514 | $ 453 |
Investments - Summary of Invest
Investments - Summary of Investments (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of detailed information about financial instruments [line items] | ||
Investments | $ 525 | $ 491 |
Investment in PrairieSky Royalty Ltd. | ||
Disclosure of detailed information about financial instruments [line items] | ||
Investments | $ 525 | $ 491 |
Investments - Narrative (Detail
Investments - Narrative (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of detailed information about financial instruments [line items] | |||
Gain from investment | $ 56 | $ 196 | $ 141 |
Investment in PrairieSky Royalty Ltd. | |||
Disclosure of detailed information about financial instruments [line items] | |||
Number of shares held as investment (in shares) | 22.6 | ||
Market price per common share (CAD per share) | $ 23.20 | $ 21.70 | $ 13.63 |
Gain from investment | $ 56 | $ 196 | $ 88 |
Fair value gain from investment | 34 | 182 | 81 |
Dividend income | $ 22 | $ 14 | $ 7 |
Inter Pipeline Ltd. | |||
Disclosure of detailed information about financial instruments [line items] | |||
Number of shares held as investment (in shares) | 6.4 | ||
Cash proceeds | $ 128 | ||
Cash proceeds per common share (CAD per share) | $ 20 | ||
Gain from investment | $ 53 | ||
Fair value gain from investment | 51 | ||
Dividend income | $ 2 |
Investments - PrairieSky (Detai
Investments - PrairieSky (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of detailed information about financial instruments [line items] | |||
Gain from investment | $ (56) | $ (196) | $ (141) |
Investment in PrairieSky Royalty Ltd. | |||
Disclosure of detailed information about financial instruments [line items] | |||
Gain from investment | (34) | (182) | (81) |
Dividend income | (22) | (14) | (7) |
Gain from investment | $ (56) | $ (196) | $ (88) |
Other Long-Term Assets - Schedu
Other Long-Term Assets - Schedule of other long-term assets (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Subclassifications of assets, liabilities and equities [abstract] | ||
Long-term prepayments, contracts and other | $ 279 | $ 269 |
Prepaid cost of service toll | 179 | 199 |
Long-term inventory | 141 | 137 |
Risk management | 13 | 9 |
Other assets | 612 | 614 |
Less: current portion | 71 | 61 |
Other long-term assets | $ 541 | $ 553 |
Other Long-Term Assets - Narrat
Other Long-Term Assets - Narrative (Details) | 12 Months Ended | |||
Jun. 30, 2021 | Dec. 31, 2023 CAD ($) bbl | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) | |
Disclosure of joint ventures [line items] | ||||
Repayment of North West Redwater Partnership subordinated debt advances | $ 0 | $ 0 | $ 555,000,000 | |
Borrowings | $ 10,799,000,000 | 11,445,000,000 | ||
North West Redwater Partnership | ||||
Disclosure of joint ventures [line items] | ||||
Toll payer percent for others | 75% | |||
North West Redwater Partnership | ||||
Disclosure of joint ventures [line items] | ||||
Company's voting percent interest in joint venture | 50% | |||
Processing agreement, barrels of bitumen feedstock per date for the Company | bbl | 12,500 | |||
Percent of pro rata share of debt company has committed paying to joint venture, toll payer percent | 25% | |||
Processing agreement, barrels of bitumen feedstock per date for others | bbl | 37,500 | |||
Term of commitment to joint venture | 40 years | |||
Optimization transaction extended period | 10 years | |||
Repayment of North West Redwater Partnership subordinated debt advances | $ 555,000,000 | |||
Partnership distributions | 400,000,000 | |||
Investments in joint ventures | $ 0 | |||
Cumulative unrecognised share of losses of joint ventures | 555,000,000 | 551,000,000 | ||
Unrecognised share of losses of joint ventures | $ 4,000,000 | $ 9,000,000 | ||
Recovery of unrecognised share of losses of joint ventures | 11,000,000 | |||
North West Redwater Partnership | Subordinate Debt | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings, interest rate | 6% | |||
North West Redwater Partnership | Senior Secured Bonds | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings, interest rate | 2.55% | |||
North West Redwater Partnership | Series L Senior Secured Bonds Due December 2023 | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings, interest rate | 1.20% | 1.20% | ||
Maximum credit facility | $ 500,000,000 | |||
Repayments of credit facility | $ 500,000,000 | |||
North West Redwater Partnership | Series M Senior Secured Bonds Due December 2026 | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings, interest rate | 2% | |||
Maximum credit facility | $ 500,000,000 | |||
North West Redwater Partnership | Series N Senior Secured Bonds Due June 2031 | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings, interest rate | 2.80% | |||
Maximum credit facility | $ 1,000,000,000 | |||
North West Redwater Partnership | Series O Senior Secured Bonds Due June 2051 | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings, interest rate | 3.75% | |||
Maximum credit facility | $ 600,000,000 | |||
North West Redwater Partnership | Syndicated credit facility | ||||
Disclosure of joint ventures [line items] | ||||
Maximum credit facility | 3,115,000,000 | 3,175,000,000 | ||
Maximum borrowing capacity decreased | 60,000,000 | |||
North West Redwater Partnership | Revolving Credit Facility | ||||
Disclosure of joint ventures [line items] | ||||
Maximum credit facility | 2,175,000,000 | |||
North West Redwater Partnership | Revolving Credit Facility Maturing in June 2024 | ||||
Disclosure of joint ventures [line items] | ||||
Maximum credit facility | 118,000,000 | |||
North West Redwater Partnership | Non Revolving Credit Facility Maturing June 2025 | ||||
Disclosure of joint ventures [line items] | ||||
Maximum credit facility | $ 940,000,000 | |||
North West Redwater Partnership | Letter of Credit | ||||
Disclosure of joint ventures [line items] | ||||
Maximum credit facility | 150,000,000 | |||
North West Redwater Partnership | North West Redwater Partnership | ||||
Disclosure of joint ventures [line items] | ||||
Barrels of bitumen feedstock processed per day | bbl | 50,000 | |||
North West Redwater Partnership | North West Redwater Partnership | Syndicated credit facility | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings | $ 2,559,000,000 | 2,318,000,000 | ||
North West Redwater Partnership | North West Redwater Partnership | Short term demand operating facility | ||||
Disclosure of joint ventures [line items] | ||||
Borrowings | $ 77,000,000 | $ 0 | ||
North West Redwater Partnership | North West Redwater Partnership | Alberta Petroleum Marketing Commission | ||||
Disclosure of joint ventures [line items] | ||||
Partnership interest transferred | 50% |
Other Long-Term Assets - Summar
Other Long-Term Assets - Summary of Assets, Liabilities, Partners' Equity and Equity (Loss) Income (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of joint ventures [line items] | |||
Current assets | $ 7,167 | $ 7,057 | |
Current liabilities | 7,435 | 8,651 | |
Partners' equity | 39,832 | 38,175 | $ 36,945 |
Revenue | 40,835 | 49,530 | 32,854 |
Net earnings | 8,233 | 10,937 | 7,664 |
Depletion, depreciation and amortization | 6,413 | 7,353 | 5,724 |
Interest and other financing expense | 636 | 549 | $ 711 |
North West Redwater Partnership | |||
Disclosure of joint ventures [line items] | |||
Partners' equity | (555) | (551) | |
Revenue | $ 335 | 317 | |
Company's voting percent interest in joint venture | 50% | ||
Percent of pro rata share of debt company has committed paying to joint venture, toll payer percent | 25% | ||
North West Redwater Partnership | |||
Disclosure of joint ventures [line items] | |||
Current assets | $ 349 | 257 | |
Non-current assets | 10,508 | 10,729 | |
Current liabilities | 1,054 | 849 | |
Non-current liabilities | 10,913 | 11,239 | |
Partners' equity | (1,110) | (1,102) | |
Revenue | 1,527 | 1,267 | |
Net earnings | (8) | 22 | |
Depletion, depreciation and amortization | 387 | 245 | |
Interest and other financing expense | $ 500 | $ 422 |
Long-Term Debt - Summary of Lon
Long-Term Debt - Summary of Long-term Debt (Details) $ 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] | ||||
Borrowings | $ 10,799 | $ 11,445 | ||
Current portion of long-term debt | 980 | 404 | ||
Long-term debt | 9,819 | 11,041 | ||
Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 10,859 | 11,514 | ||
Original issue discounts, net | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 11 | 13 | ||
Transaction costs | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 49 | 56 | ||
Medium-term notes | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 1,286 | $ 1,702 | ||
1.45% debentures due November 16, 2023 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 1.45% | 1.45% | ||
1.45% debentures due November 16, 2023 | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 0 | $ 404 | ||
3.55% debentures due June 3, 2024 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.55% | 3.55% | 3.55% | 3.55% |
3.55% debentures due June 3, 2024 | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 320 | $ 332 | ||
3.42% debentures due December 1, 2026 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.42% | 3.42% | 3.42% | 3.42% |
3.42% debentures due December 1, 2026 | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 441 | $ 441 | ||
2.50% debentures due January 17, 2028 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 2.50% | 2.50% | 2.50% | 2.50% |
2.50% debentures due January 17, 2028 | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 225 | $ 225 | ||
4.85% debentures due May 30, 2047 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 4.85% | 4.85% | ||
4.85% debentures due May 30, 2047 | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 300 | 300 | ||
Long-term debt | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 9,573 | 9,812 | ||
3.80% due April 15, 2024 (US$500 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.80% | 3.80% | ||
Notional amount | $ 500,000,000 | |||
3.80% due April 15, 2024 (US$500 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 660 | 677 | ||
3.90% due February 1, 2025 (US$600 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.90% | 3.90% | ||
Notional amount | $ 600,000,000 | |||
3.90% due February 1, 2025 (US$600 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 792 | 812 | ||
2.05% due July 15, 2025 (US$600 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 2.05% | 2.05% | ||
Notional amount | $ 600,000,000 | |||
2.05% due July 15, 2025 (US$600 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 792 | 812 | ||
3.85% due June 1, 2027 (US$1,250 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.85% | 3.85% | ||
Notional amount | $ 1,250,000,000 | |||
3.85% due June 1, 2027 (US$1,250 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 1,651 | 1,692 | ||
2.95% due July 15, 2030 (US$500 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 2.95% | 2.95% | ||
Notional amount | $ 500,000,000 | |||
2.95% due July 15, 2030 (US$500 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 660 | 677 | ||
7.20% due January 15, 2032 (US$400 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 7.20% | 7.20% | ||
Notional amount | $ 400,000,000 | |||
7.20% due January 15, 2032 (US$400 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 528 | 541 | ||
6.45% due June 30, 2033 (US$350 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 6.45% | 6.45% | ||
Notional amount | $ 350,000,000 | |||
6.45% due June 30, 2033 (US$350 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 462 | 474 | ||
5.85% due February 1, 2035 (US$350 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 5.85% | 5.85% | ||
Notional amount | $ 350,000,000 | |||
5.85% due February 1, 2035 (US$350 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 462 | 474 | ||
6.50% due February 15, 2037 (US$450 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 6.50% | 6.50% | ||
Notional amount | $ 450,000,000 | |||
6.50% due February 15, 2037 (US$450 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 594 | 609 | ||
6.25% due March 15, 2038 (US$1,100 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 6.25% | 6.25% | ||
Notional amount | $ 1,100,000,000 | $ 1,100,000,000 | ||
6.25% due March 15, 2038 (US$1,100 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 1,453 | 1,488 | ||
6.75% due February 1, 2039 (US$400 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 6.75% | 6.75% | ||
Notional amount | $ 400,000,000 | |||
6.75% due February 1, 2039 (US$400 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 528 | 541 | ||
4.95% due June 1, 2047 (US$750 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 4.95% | 4.95% | ||
Notional amount | $ 750,000,000 | |||
4.95% due June 1, 2047 (US$750 million) | Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 991 | $ 1,015 |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) | 12 Months Ended | |||||
Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 GBP (£) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 CAD ($) | Dec. 31, 2023 USD ($) | |
Disclosure of detailed information about borrowings [line items] | ||||||
Repayment of bank credit facilities and commercial paper, net | $ 0 | $ 1,156,000,000 | $ 6,151,000,000 | |||
Letters of credit and guarantees outstanding | 446,000,000 | 637,000,000 | ||||
Repayment of medium-term notes | 416,000,000 | 1,498,000,000 | 0 | |||
Repayment of long-term debt | 0 | 0 | $ 183,000,000 | |||
Bank credit facilities | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | 5,450,000,000 | |||||
Demand credit facility | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | 100,000,000 | |||||
Demand credit facility | North Sea | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Line of credit facility discontinued | £ | £ 5,000,000 | |||||
Revolving Credit Facility Maturing February 2025 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | 500,000,000 | |||||
Revolving syndicated credit facility maturing June 2025 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | 2,425,000,000 | |||||
Revolving Syndicated Credit Facility Maturing June 2027 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | 2,425,000,000 | |||||
Non-revolving term credit facility maturing February 2023 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Repayment of bank credit facilities and commercial paper, net | 1,150,000,000 | |||||
Non-Revolving Term Credit Facility Maturing March 2022 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Repayment of bank credit facilities and commercial paper, net | 500,000,000 | |||||
Revolving Term Credit Facility Maturing February 2024 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | $ 500,000,000 | |||||
Revolving Term Credit Facility Maturing February 2025 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | $ 500,000,000 | |||||
Commercial Paper | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Maximum credit facility | $ 2,500,000,000 | |||||
Long-term debt | Weighted average | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 4.80% | 4.30% | 4.80% | |||
Medium-term borrowings expiring August 2025 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Base shell prospectus borrowings, authorized | $ 3,000,000,000 | |||||
1.45% Medium-term Notes | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 1.45% | 1.45% | ||||
Repayment of medium-term notes | $ 405,000,000 | |||||
3.31% Medium-term Notes | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 3.31% | |||||
Repayment of medium-term notes | $ 1,000,000,000 | |||||
1.45% Medium-term Notes Due November 2023 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 1.45% | |||||
Repayment of medium-term notes | $ 95,000,000 | |||||
3.55% debentures due June 3, 2024 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 3.55% | 3.55% | 3.55% | |||
Repayment of medium-term notes | $ 169,000,000 | |||||
3.42% debentures due December 1, 2026 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 3.42% | 3.42% | 3.42% | |||
Repayment of medium-term notes | $ 159,000,000 | |||||
2.50% debentures due January 17, 2028 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 2.50% | 2.50% | 2.50% | |||
Repayment of medium-term notes | $ 75,000,000 | |||||
US dollar denominated debt, unsecured | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 2.95% | |||||
Base shell prospectus borrowings, authorized | $ 3,000,000,000 | |||||
Repayment of long-term debt | $ 1,000,000,000 |
Long-Term Debt - Schedule of De
Long-Term Debt - Schedule of Debt Repayments (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | $ 10,799 | $ 11,445 |
Gross carrying amount | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 10,859 | $ 11,514 |
Gross carrying amount | 2024 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 980 | |
Gross carrying amount | 2025 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 1,584 | |
Gross carrying amount | 2026 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 441 | |
Gross carrying amount | 2027 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 1,651 | |
Gross carrying amount | 2028 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 225 | |
Gross carrying amount | Thereafter | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | $ 5,978 |
Other Long-Term Liabilities - S
Other Long-Term Liabilities - Schedule of Other Long-Term Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Subclassifications of assets, liabilities and equities [abstract] | ||||
Asset retirement obligations | $ 7,690 | $ 6,908 | $ 6,806 | $ 5,861 |
Lease liabilities | 1,555 | 1,540 | ||
Share-based compensation | 780 | 832 | $ 489 | $ 160 |
Transportation and processing contracts | 87 | 159 | ||
Risk management | 4 | 3 | ||
Other | 73 | 92 | ||
Other liabilities | 10,189 | 9,534 | ||
Less: current portion | 1,503 | 1,373 | ||
Other long-term liabilities | $ 8,686 | $ 8,161 |
Other Long-Term Liabilities - A
Other Long-Term Liabilities - Asset Retirement Obligations (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of other provisions [line items] | |||
Asset retirement obligations settlement period | 60 years | ||
Inflation rate | 2% | 2% | |
Reconciliation Of Changes In Provision For Decommissioning Restoration And Rehabilitation Costs [Roll Forward] | |||
Balance – beginning of year | $ 6,908 | $ 6,806 | $ 5,861 |
Balance – end of year | 7,690 | 6,908 | 6,806 |
Less: current portion | 634 | 495 | 249 |
Non-current asset retirement obligation | 7,056 | 6,413 | 6,557 |
Deferred income tax expense (recovery) | (53) | 139 | (399) |
Deferred income tax expense (recovery) | (53) | 139 | $ (399) |
North Sea | |||
Reconciliation Of Changes In Provision For Decommissioning Restoration And Rehabilitation Costs [Roll Forward] | |||
Balance – beginning of year | 1,011 | ||
Balance – end of year | $ 1,441 | $ 1,011 | |
Provision for decommissioning, restoration and rehabilitation costs | |||
Disclosure of other provisions [line items] | |||
Weighted average discount rate | 5.20% | 5.60% | 4% |
Reconciliation Of Changes In Provision For Decommissioning Restoration And Rehabilitation Costs [Roll Forward] | |||
Liabilities incurred | $ 25 | $ 20 | $ 5 |
Liabilities acquired, net | 0 | 11 | 76 |
Liabilities settled | (509) | (449) | (307) |
Asset retirement obligation accretion | 366 | 281 | 185 |
Revision of cost, inflation and timing estimates | 621 | 897 | 508 |
Impact of regulatory changes | 0 | 982 | 1,208 |
Change in discount rates | 314 | (1,698) | (723) |
Foreign exchange adjustments | $ (35) | $ 58 | $ (7) |
Other Long-Term Liabilities -_2
Other Long-Term Liabilities - Segmented Asset Retirement Obligations (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | $ 7,690 | $ 6,908 | $ 6,806 | $ 5,861 |
North America | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 4,471 | 4,326 | ||
North Sea | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 1,441 | 1,011 | ||
Offshore Africa | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 165 | 143 | ||
Oil Sands Mining and Upgrading | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 1,612 | 1,427 | ||
Midstream and Refining | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | $ 1 | $ 1 |
Other Long-Term Liabilities -_3
Other Long-Term Liabilities - Share-Based Compensation (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reconciliation Of Changes In Liabilities From Share-Based Payment Transactions [Roll Forward] | |||
Balance – beginning of year | $ 832 | $ 489 | $ 160 |
Share-based compensation expense | 491 | 804 | 514 |
Cash payment for stock options surrendered and PSUs vested | (110) | (79) | (48) |
Transferred to common shares | (435) | (387) | (139) |
Other | 2 | 5 | 2 |
Balance – end of year | 780 | 832 | 489 |
Less: current portion | 538 | 559 | 329 |
Non-current liabilities from share-based payment arrangements | 242 | 273 | 160 |
Share-based compensation | 780 | 832 | 489 |
Certain Executives | Performance Share Units | |||
Reconciliation Of Changes In Liabilities From Share-Based Payment Transactions [Roll Forward] | |||
Balance – beginning of year | 127 | 90 | |
Balance – end of year | 96 | 127 | 90 |
Share-based compensation | $ 96 | $ 127 | $ 90 |
Other Long-Term Liabilities - W
Other Long-Term Liabilities - Weighted Average Assumptions Used to Calculate Share-Based Compensation Liability (Details) - Stock options $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 CAD ($) yr $ / shares | Dec. 31, 2022 CAD ($) yr $ / shares | Dec. 31, 2021 CAD ($) yr $ / shares | |
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Fair value | $ 35.93 | $ 32.96 | $ 16.98 |
Share price | $ 86.81 | $ 75.19 | $ 53.45 |
Expected volatility | 30.90% | 35.80% | 35.50% |
Expected dividend yield | 4.60% | 4.50% | 4.40% |
Risk free interest rate | 3.60% | 3.80% | 1.10% |
Expected forfeiture rate | 5.40% | 5% | 4.70% |
Expected stock option life | yr | 4.2 | 4.2 | 4.2 |
Intrinsic value of vested stock options | $ | $ 164 | $ 208 | $ 112 |
Income Taxes - Schedule Of Prov
Income Taxes - Schedule Of Provision For Income Tax (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Current | |||
Other taxes | $ 17 | $ 16 | $ 13 |
Current income tax | 1,879 | 2,906 | 1,848 |
Deferred | |||
Deferred corporate income tax | 267 | 302 | 399 |
Deferred income tax | 53 | (139) | 399 |
Income tax | 1,932 | 2,767 | 2,247 |
North America | |||
Current | |||
Current corporate income tax | 1,853 | 2,789 | 1,841 |
North Sea | |||
Current | |||
Current corporate income tax | (6) | 69 | 7 |
Current PRT - North Sea | (58) | (42) | (34) |
Deferred | |||
Deferred PRT – North Sea | (214) | (441) | 0 |
Offshore Africa | |||
Current | |||
Current corporate income tax | $ 73 | $ 74 | $ 21 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Unused tax losses | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Deductible temporary differences for which no deferred tax asset is recognised | $ 1,000 | |
Unused tax credits | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Deductible temporary differences for which no deferred tax asset is recognised | 950 | |
Ninian Field in the North Sea | North Sea | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Deferred corporate income tax recovery | 118 | $ 528 |
Deferred PRT – North Sea | $ 205 | $ 441 |
Income Taxes - Schedule of Pr_2
Income Taxes - Schedule of Provision For Income Tax Rate Reconciliation (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reconciliation of accounting profit multiplied by applicable tax rates [abstract] | |||
Canadian statutory income tax rate | 23.30% | 23.20% | 23.20% |
Income tax provision at statutory rate | $ 2,364 | $ 3,180 | $ 2,298 |
UK PRT and other taxes | (255) | (467) | (21) |
Impact of UK PRT and other taxes on corporate income tax | 105 | 190 | 11 |
Foreign and domestic tax rate differentials | (104) | (203) | (11) |
Non-taxable portion of capital gains | (35) | 65 | (26) |
Stock options exercised for common shares | 91 | 159 | 98 |
Non-taxable gain on corporate acquisitions | 0 | 0 | (110) |
Revisions arising from prior year tax filings | (174) | (186) | 16 |
Change in unrecognized capital loss carryforward asset | (35) | 65 | (26) |
Other | (25) | (36) | 18 |
Income tax | $ 1,932 | $ 2,767 | $ 2,247 |
Income Taxes - Summary of Major
Income Taxes - Summary of Major Temporary Differences (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | $ 13,763 | $ 13,481 | ||
Deferred income tax assets | (3,580) | (3,367) | ||
Net deferred income tax liability | 10,183 | 10,114 | $ 10,220 | $ 10,144 |
Property, plant and equipment and exploration and evaluation assets | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 12,172 | 11,985 | ||
Lease assets | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 336 | 336 | ||
Investments | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 54 | 56 | ||
Investment in North West Redwater Partnership | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 904 | 903 | ||
Taxable PRT for corporate income tax | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 256 | 176 | ||
Other | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 41 | 25 | ||
Asset retirement obligations | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (2,098) | (1,822) | ||
Lease liabilities | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (356) | (354) | ||
Share-based compensation | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (31) | (33) | ||
Loss carryforwards | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (417) | (652) | ||
Unrealized foreign exchange loss on long-term debt | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (39) | (67) | ||
Deferred PRT | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | $ (639) | $ (439) |
Income Taxes - Summary of Movem
Income Taxes - Summary of Movements in Deferred Tax Assets and Liabilities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | $ 53 | $ (139) | $ 399 |
Property, plant and equipment and exploration and evaluation assets | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 196 | (334) | 184 |
Lease assets | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 1 | (15) | (30) |
Unrealized foreign exchange on long-term debt | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 28 | (81) | 34 |
Unrealized risk management activities | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 0 | (12) | 19 |
Asset retirement obligations | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (292) | (74) | (213) |
Lease liabilities | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (3) | 11 | 25 |
Share-based compensation | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 2 | (11) | (10) |
Loss carryforwards | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 235 | 618 | 202 |
Investments | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (2) | 21 | 21 |
Investment in North West Redwater Partnership | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 1 | 53 | 83 |
Deferred PRT | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 86 | (441) | 0 |
Taxable PRT for corporate income tax | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (214) | 176 | 0 |
Other | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | $ 15 | $ (50) | $ 84 |
Income Taxes - Summary of Net D
Income Taxes - Summary of Net Deferred Income Tax Liability (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reconciliation of changes in deferred tax liability (asset) [abstract] | |||
Balance – beginning of year | $ 10,114 | $ 10,220 | $ 10,144 |
Deferred income tax expense (recovery) | 53 | (139) | 399 |
Deferred income tax expense included in other comprehensive (loss) income | 0 | 0 | 1 |
Foreign exchange adjustments | 16 | 33 | (2) |
Business combinations | 0 | 0 | (322) |
Balance – end of year | $ 10,183 | $ 10,114 | $ 10,220 |
Share Capital - Outstanding Com
Share Capital - Outstanding Common Shares (Details) $ in Millions | 2 Months Ended | 12 Months Ended | ||
Feb. 27, 2024 CAD ($) shares | Dec. 31, 2023 CAD ($) shares | Dec. 31, 2022 CAD ($) shares | Dec. 31, 2021 CAD ($) shares | |
Reconciliation of number of shares outstanding [abstract] | ||||
Balance – beginning of year | $ 39,832 | $ 38,175 | $ 36,945 | |
Issued upon exercise of stock options (in shares) | shares | 9,822,000 | 11,605,000 | ||
Purchase of common shares under Normal Course Issuer Bid (In shares) | shares | (4,000,000) | (40,050,000) | ||
Purchase of common shares under Normal Course Issuer Bid | $ (342) | $ (3,318) | ||
Balance – end of year | 39,832 | $ 38,175 | $ 36,945 | |
Share capital | ||||
Reconciliation of number of shares outstanding [abstract] | ||||
Balance – beginning of year | $ 10,712 | 10,294 | 10,168 | 9,606 |
Issued upon exercise of stock options | 372 | 442 | 707 | |
Previously recognized liability on stock options exercised for common shares | 435 | 387 | 139 | |
Balance – end of year | $ 10,712 | $ 10,294 | 10,168 | |
Ordinary shares | Share capital | ||||
Reconciliation of number of shares outstanding [abstract] | ||||
Balance - beginning of year (in shares) | shares | 1,072,408,000 | 1,102,636,000 | 1,168,369,000 | |
Balance – beginning of year | $ 10,712 | $ 10,294 | $ 10,168 | |
Issued upon exercise of stock options (in shares) | shares | 9,822,000 | 11,605,000 | ||
Issued upon exercise of stock options | $ 372 | $ 442 | ||
Previously recognized liability on stock options exercised for common shares | $ 435 | $ 387 | ||
Purchase of common shares under Normal Course Issuer Bid (In shares) | shares | (40,050,000) | (77,338,000) | ||
Purchase of common shares under Normal Course Issuer Bid | $ (389) | $ (703) | $ (284) | |
Balance - end of year (in shares) | shares | 1,072,408,000 | 1,102,636,000 | 1,168,369,000 | |
Balance – end of year | $ 10,712 | $ 10,294 | $ 10,168 |
Share Capital - Narrative (Deta
Share Capital - Narrative (Details) - CAD ($) $ / shares in Units, $ in Millions | 2 Months Ended | 12 Months Ended | |||||||||
Feb. 28, 2024 | Nov. 01, 2023 | Mar. 01, 2023 | Nov. 02, 2022 | Aug. 03, 2022 | Mar. 02, 2022 | Mar. 01, 2022 | Feb. 27, 2024 | Mar. 12, 2024 | Dec. 31, 2023 | Mar. 08, 2023 | |
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Dividend increase percentage | 5% | 11% | 6% | 13% | 28% | ||||||
Dividend declared (in CAD per share) | $ 1.05 | $ 1 | $ 0.90 | $ 0.85 | $ 1.50 | $ 0.75 | $ 0.5875 | ||||
Dividends paid, ordinary shares (in CAD per share) | $ 1.50 | ||||||||||
Share repurchase term | 12 months | ||||||||||
Shares repurchased and retired (in shares) | 4,000,000 | 40,050,000 | |||||||||
Weighted average price per share of shares repurchased and retired (in CAD per share) | $ 85.54 | $ 82.86 | |||||||||
Purchase of common shares under Normal Course Issuer Bid | $ 342 | $ 3,318 | |||||||||
Normal course issuer bid, percent of issued and outstanding shares | 10% | ||||||||||
Common shares, conversion basis, subject to shareholder approval (in shares) | 2 | ||||||||||
Stock options | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Vesting term (in years) | 5 years | ||||||||||
Shares that may be reserved for issuance as a percentage of common shares outstanding | 7% | ||||||||||
Retained earnings | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Purchase of common shares under Normal Course Issuer Bid | $ 2,929 | ||||||||||
Top of range | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Shares authorized to be repurchased through Normal Course Issuer Bid (in shares) | 92,296,006 | ||||||||||
Top of range | Stock options | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Expiration term | 6 years | ||||||||||
Bottom of range | Stock options | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Expiration term | 5 years |
Share Capital - Stock Option Ac
Share Capital - Stock Option Activity (Details) shares in Thousands | 12 Months Ended | |
Dec. 31, 2023 shares $ / shares | Dec. 31, 2022 shares $ / shares | |
Share Capital, Reserves And Other Equity Interest [Abstract] | ||
Stock options outstanding - beginning of year (in shares) | shares | 31,150 | 38,327 |
Stock options granted (in shares) | shares | 7,024 | 7,547 |
Stock options exercised for common shares (in shares) | shares | (9,822) | (11,605) |
Stock options surrendered for cash settlement (in shares) | shares | (218) | (441) |
Stock options forfeited (in shares) | shares | (1,929) | (2,678) |
Stock options outstanding - end of year (in shares) | shares | 26,205 | 31,150 |
Stock options exercisable (in shares) | shares | 3,672 | 5,522 |
Weighted average exercise price, options outstanding - beginning of year (in CAD per share) | $ / shares | $ 42.37 | $ 35.88 |
Weighted average exercise price, options granted (in CAD per share) | $ / shares | 80.17 | 68.15 |
Weighted average exercise price, options exercised (in CAD per share) | $ / shares | 37.84 | 38.06 |
Weighted average exercise price, options surrendered for cash settlement (in CAD per share) | $ / shares | 38.77 | 38.43 |
Weighted average exercise price, options forfeited (in CAD per share) | $ / shares | 50.86 | 41.43 |
Weighted average exercise price, options outstanding - beginning of year (in CAD per share) | $ / shares | 53.60 | 42.37 |
Weighted average exercise price, options exercisable (in CAD per share) | $ / shares | $ 42.14 | $ 37.60 |
Share Capital - Range of Exerci
Share Capital - Range of Exercise Prices of Stock Options (Details) shares in Thousands | 12 Months Ended | ||
Dec. 31, 2023 shares $ / shares | Dec. 31, 2022 shares $ / shares | Dec. 31, 2021 shares $ / shares | |
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 26,205 | 31,150 | 38,327 |
Weighted average remaining term (years) | 2 years 10 months 13 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 53.60 | $ 42.37 | $ 35.88 |
Stock options exercisable (in shares) | shares | 3,672 | 5,522 | |
Weighted average exercise price, options exercisable (in CAD per share) | $ 42.14 | $ 37.60 | |
$20.76 - $29.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 5,441 | ||
Weighted average remaining term (years) | 2 years 3 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 27.42 | ||
Stock options exercisable (in shares) | shares | 969 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 24.84 | ||
$20.76 - $29.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 20.76 | ||
$20.76 - $29.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 29.99 | ||
$30.00 - $39.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 5,411 | ||
Weighted average remaining term (years) | 1 year 10 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 36.67 | ||
Stock options exercisable (in shares) | shares | 1,227 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 36.56 | ||
$30.00 - $39.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 30 | ||
$30.00 - $39.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 39.99 | ||
$40.00 - $49.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 2,381 | ||
Weighted average remaining term (years) | 2 years 4 months 28 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 40.52 | ||
Stock options exercisable (in shares) | shares | 630 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 40.50 | ||
$40.00 - $49.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 40 | ||
$40.00 - $49.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 49.99 | ||
$50.00 - $59.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 433 | ||
Weighted average remaining term (years) | 3 years 10 months 9 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 54.24 | ||
Stock options exercisable (in shares) | shares | 30 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 54.24 | ||
$50.00 - $59.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 50 | ||
$50.00 - $59.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 59.99 | ||
$60.00 - $69.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 3,837 | ||
Weighted average remaining term (years) | 3 years 5 months 26 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 64.90 | ||
Stock options exercisable (in shares) | shares | 301 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 64.21 | ||
$60.00 - $69.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 60 | ||
$60.00 - $69.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 69.99 | ||
$70.00 - $79.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 7,787 | ||
Weighted average remaining term (years) | 4 years 2 months 4 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 78.48 | ||
Stock options exercisable (in shares) | shares | 515 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 76.35 | ||
$70.00 - $79.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 70 | ||
$70.00 - $79.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 79.99 | ||
$80.00 - $86.06 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 915 | ||
Weighted average remaining term (years) | 5 years 8 months 19 days | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 84.12 | ||
Stock options exercisable (in shares) | shares | 0 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 0 | ||
$80.00 - $86.06 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 80 | ||
$80.00 - $86.06 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 86.06 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Analysis Of Other Comprehensive Income By Item [Abstract] | ||
Derivative financial instruments designated as cash flow hedges | $ 72 | $ 75 |
Foreign currency translation adjustment | 100 | 134 |
Accumulated other comprehensive income | $ 172 | $ 209 |
Capital Disclosures - Narrative
Capital Disclosures - Narrative (Details) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of objectives, policies and processes for managing capital [line items] | ||
Debt to book capitalization | 20% | 22% |
Bottom of range | ||
Disclosure of objectives, policies and processes for managing capital [line items] | ||
Debt to book capitalization, target | 25% | |
Top of range | ||
Disclosure of objectives, policies and processes for managing capital [line items] | ||
Debt to book capitalization, target | 45% | |
Debt to book capitalization ratio | 65% |
Capital Disclosures - Schedule
Capital Disclosures - Schedule of Debt to Book Capitalization Ratio (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Corporate information and statement of IFRS compliance [abstract] | ||||
Long-term debt | $ 10,799 | $ 11,445 | ||
Less: cash and cash equivalents | 877 | 920 | $ 744 | $ 184 |
Long-term debt, net | 9,922 | 10,525 | ||
Total shareholders’ equity | $ 39,832 | $ 38,175 | $ 36,945 | |
Debt to book capitalization | 20% | 22% |
Net Earnings Per Common Share -
Net Earnings Per Common Share - Schedule of Basic and Diluted Net Earnings per Common Share (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Weighted average ordinary shares and adjusted weighted average ordinary shares [abstract] | |||
Weighted average common shares outstanding – basic (thousands of shares) | 1,091,312 | 1,134,960 | 1,181,250 |
Effect of dilutive stock options (thousands of shares) | 10,812 | 14,222 | 5,307 |
Weighted average common shares outstanding – diluted (thousands of shares) | 1,102,124 | 1,149,182 | 1,186,557 |
Net earnings | $ 8,233 | $ 10,937 | $ 7,664 |
Net earnings per common share - basic (in CAD per share) | $ 7.54 | $ 9.64 | $ 6.49 |
Net earnings per common share - diluted (in CAD per share) | $ 7.47 | $ 9.52 | $ 6.46 |
Net Earnings Per Common Share_2
Net Earnings Per Common Share - Narrative (Details) - shares | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Stock options | |||
Earnings per share [line items] | |||
Number of instruments that are antidilutive in period presented (in shares) | 3,230,000 | 2,039,000 | 3,496,000 |
Interest and Other Financing _3
Interest and Other Financing Expense (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Borrowing costs [abstract] | |||
Long-term debt | $ 627 | $ 610 | $ 681 |
Lease liabilities | 64 | 60 | 62 |
Total interest and other financing expense | 691 | 670 | 743 |
Total interest income and other | (55) | (121) | (32) |
Net interest and other financing expense | $ 636 | $ 549 | $ 711 |
Financial Instruments - Estimat
Financial Instruments - Estimated Fair Values of Derivative Financial Instruments Included in Risk Management Asset (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation Of Changes In Derivative Financial Assets (Liabilities), Net [Roll Forward] | ||
Derivative financial asset (liability), net | $ 6 | $ 55 |
Net change in fair value of outstanding derivatives financial instruments recognized in: Risk management activities | 3 | 70 |
Net change in fair value of outstanding derivatives financial instruments recognized in: Foreign exchange | 0 | (119) |
Derivative financial asset, net | 9 | 6 |
Asset (liability), included in current portion of other long-term (liabilities) assets | 8 | 0 |
Asset, included in other long-term assets | $ 1 | $ 6 |
Financial Instruments - Net (Ga
Financial Instruments - Net (Gains) Losses from Risk Management Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Financial Instruments [Abstract] | |||
Net realized risk management (gain) loss | $ (14) | $ (7) | $ 17 |
Net unrealized risk management loss (gain) | 12 | (28) | 19 |
Gains (losses) on change in fair value of derivatives | $ (2) | $ (35) | $ 36 |
Financial Instruments - Carryin
Financial Instruments - Carrying Amounts and Fair Values of Financial Instruments (Details) - Fixed rate long-term debt - Fixed interest rate - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, carrying amount | $ (10,799) | $ (11,445) |
Level 1 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, at fair value | $ (10,795) | $ (10,796) |
Financial Instruments - Carry_2
Financial Instruments - Carrying Amounts and Reconciliation of Derivative Financial Instruments (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 USD ($) MMBTU | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) | |
Disclosure of detailed information about hedging instruments [line items] | ||||
Derivatives held for trading, asset (liability) | $ 9 | $ 6 | ||
Current portion of other long-term assets | 12 | 3 | ||
Current portion of other long-term liabilities | (4) | (3) | ||
Other long-term assets | 1 | 6 | ||
Derivative financial asset (liability), net | 9 | 6 | $ 55 | |
Derivative, volume per day | MMBTU | 50,000 | |||
Derivative, AECO fixed price | $ 1.82 | |||
Natural Gas | ||||
Disclosure of detailed information about hedging instruments [line items] | ||||
Derivatives held for trading, asset (liability) | (3) | 3 | ||
Foreign currency forward contracts | ||||
Disclosure of detailed information about hedging instruments [line items] | ||||
Derivatives held for trading, asset (liability) | $ 12 | $ 3 |
Financial Instruments - Foreign
Financial Instruments - Foreign Currency Exchange Rate Risk Management (Details) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | |
Disclosure of detailed information about hedging instruments [line items] | |||||
Cash proceeds from settlement of cash flow hedge | $ 2 | $ 4 | $ 15 | ||
6.25% due March 15, 2038 (US$1,100 million) | |||||
Disclosure of detailed information about hedging instruments [line items] | |||||
Notional amount | $ 1,100,000,000 | $ 1,100,000,000 | |||
Cross currency swaps | Cash flow hedges | Currency risk | |||||
Disclosure of detailed information about hedging instruments [line items] | |||||
Cash proceeds from settlement of cash flow hedge | $ 158 | ||||
Cross currency swaps | Currency swap contract, term through March 2038 | Cash flow hedges | Currency risk | |||||
Disclosure of detailed information about hedging instruments [line items] | |||||
Nominal amount of hedging instrument | 550,000,000 | ||||
Average foreign exchange rate | 0.0625 | ||||
Foreign currency forward contracts | Currency risk | |||||
Disclosure of detailed information about hedging instruments [line items] | |||||
Notional amount | $ 1,003,000,000 | $ 1,017,000,000 | |||
Derivative, term of contract | 90 days |
Financial Instruments - Financi
Financial Instruments - Financial Instrument Sensitivities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 CAD ($) | |
Interest rate risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Increase interest rate 1% | 1% | 1% | |
Decrease interest rate 1% | 1% | 1% | |
Increase (decrease) to net earnings | $ (5) | $ (4) | |
Increase (decrease) to net earnings | 5 | 4 | |
Increase (decrease) to other comprehensive income | 0 | 0 | |
Increase (decrease) to other comprehensive income | 0 | 0 | |
Currency risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Weakening of the Canadian dollar by US$0.01 | $ 0.01 | ||
Strengthening of the Canadian dollar by US$0.01 | $ 0.01 | ||
Increase (decrease) to net earnings | (128) | (135) | |
Increase (decrease) to net earnings | 125 | 131 | |
Increase (decrease) to other comprehensive income | 0 | 0 | |
Increase (decrease) to other comprehensive income | $ 0 | $ 0 |
Financial Instruments - Counter
Financial Instruments - Counterparty Credit Risk Management (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure of detailed information about financial instruments [line items] | |||
Expected credit loss rate | 1% | 1% | |
Derivative financial asset (liability), net | $ 9 | $ 6 | $ 55 |
Credit risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Derivative financial asset (liability), net | $ 11 | $ 7 |
Financial Instruments - Maturit
Financial Instruments - Maturity Dates for Financial Liabilities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of detailed information about financial instruments [line items] | |||
Accounts payable | $ 1,418 | $ 1,341 | |
Accrued liabilities | 3,534 | 4,209 | |
Long-term debt | 10,799 | 11,445 | |
Other long-term liabilities | 8,686 | 8,161 | |
Interest and other financing expense | 691 | 670 | $ 743 |
Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 10,859 | $ 11,514 | |
Less than 1 year | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 980 | ||
Less than 1 year | Liquidity risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Accounts payable | 1,418 | ||
Accrued liabilities | 3,534 | ||
Other long-term liabilities | 302 | ||
Lease payments included In liablities | 298 | ||
Less than 1 year | Liquidity risk | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 980 | ||
Interest and other financing expense | 582 | ||
1 to less than 2 years | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 1,584 | ||
1 to less than 2 years | Liquidity risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Other long-term liabilities | 184 | ||
Lease payments included In liablities | 184 | ||
1 to less than 2 years | Liquidity risk | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 1,584 | ||
Interest and other financing expense | 518 | ||
2 to less than 5 years | Liquidity risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Other long-term liabilities | 428 | ||
Lease payments included In liablities | 428 | ||
2 to less than 5 years | Liquidity risk | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 2,317 | ||
Interest and other financing expense | 1,257 | ||
Thereafter | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 5,978 | ||
Thereafter | Liquidity risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Other long-term liabilities | 645 | ||
Lease payments included In liablities | 645 | ||
Thereafter | Liquidity risk | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 5,978 | ||
Interest and other financing expense | $ 3,362 |
Commitments and Contingencies_2
Commitments and Contingencies (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 CAD ($) | |
North West Redwater Partnership | |
Disclosure Of Commitments [Line Items] | |
Percent of pro rata share of debt company has committed paying to joint venture, toll payer percent | 25% |
Interest payable included in service toll | $ 3,011 |
Term of commitment to joint venture | 40 years |
2024 | |
Disclosure Of Commitments [Line Items] | |
Product transportation and processing | $ 1,572 |
North West Redwater Partnership service toll | 158 |
Other | 145 |
2024 | Offshore vessels and equipment | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 36 |
2024 | Field equipment and power | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 38 |
2025 | |
Disclosure Of Commitments [Line Items] | |
Product transportation and processing | 1,595 |
North West Redwater Partnership service toll | 157 |
Other | 111 |
2025 | Offshore vessels and equipment | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 0 |
2025 | Field equipment and power | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 25 |
2026 | |
Disclosure Of Commitments [Line Items] | |
Product transportation and processing | 1,408 |
North West Redwater Partnership service toll | 139 |
Other | 112 |
2026 | Offshore vessels and equipment | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 0 |
2026 | Field equipment and power | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 23 |
2027 | |
Disclosure Of Commitments [Line Items] | |
Product transportation and processing | 1,358 |
North West Redwater Partnership service toll | 126 |
Other | 25 |
2027 | Offshore vessels and equipment | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 0 |
2027 | Field equipment and power | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 22 |
2028 | |
Disclosure Of Commitments [Line Items] | |
Product transportation and processing | 1,242 |
North West Redwater Partnership service toll | 130 |
Other | 26 |
2028 | Offshore vessels and equipment | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 0 |
2028 | Field equipment and power | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | 22 |
Thereafter | |
Disclosure Of Commitments [Line Items] | |
Product transportation and processing | 13,380 |
North West Redwater Partnership service toll | 4,985 |
Other | $ 355 |
Commitments for oil and gas transportation, period of agreement | 20 years |
Thereafter | Offshore vessels and equipment | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | $ 0 |
Thereafter | Field equipment and power | |
Disclosure Of Commitments [Line Items] | |
Offshore vessels and equipment, field equipment and power | $ 193 |
Supplemental Disclosure of Ca_3
Supplemental Disclosure of Cash Flow Information - Supplemental Schedule Of Cash Flow Information (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement Of Cash Flows, Additional Disclosures [Abstract] | |||
Accounts receivable | $ 368 | $ (441) | $ (850) |
Inventory | (219) | (266) | (487) |
Prepaids and other | (23) | (20) | 39 |
Accounts payable | 78 | 537 | 80 |
Accrued liabilities | (812) | 896 | 525 |
Current income tax (liabilities) assets | (1,558) | (282) | 1,918 |
Other long-term liabilities | (200) | (196) | (154) |
Net changes in non-cash working capital | (2,366) | 228 | 1,071 |
Operating activities | (2,417) | 79 | 964 |
Investing activities | $ 51 | $ 149 | $ 107 |
Supplemental Disclosure of Ca_4
Supplemental Disclosure of Cash Flow Information - Liabilities Arising From Financing Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure of reconciliation of liabilities arising from financing activities [line items] | |||
Liabilities arising from financing activities, beginning balance | $ 12,985 | $ 16,159 | |
Changes from financing cash flows: | |||
Issue (repayment) of long-term debt | (416) | (4,010) | |
Proceeds on settlement of cross currency swaps | 0 | 69 | $ 0 |
Payment of lease liabilities | (285) | (232) | (209) |
Non-cash changes: | |||
Lease additions | 317 | 182 | |
Changes in foreign exchange and fair value | (247) | 817 | |
Liabilities arising from financing activities, ending balance | 12,354 | 12,985 | 16,159 |
Long-term debt | |||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | |||
Liabilities arising from financing activities, beginning balance | 11,445 | 14,694 | |
Changes from financing cash flows: | |||
Issue (repayment) of long-term debt | (416) | (4,010) | |
Non-cash changes: | |||
Changes in foreign exchange and fair value | (230) | 761 | |
Liabilities arising from financing activities, ending balance | 10,799 | 11,445 | 14,694 |
Cash flow hedges on US dollar debt securities | |||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | |||
Liabilities arising from financing activities, beginning balance | 0 | (119) | |
Changes from financing cash flows: | |||
Proceeds on settlement of cross currency swaps | 69 | ||
Non-cash changes: | |||
Changes in foreign exchange and fair value | 0 | 50 | |
Liabilities arising from financing activities, ending balance | 0 | 0 | (119) |
Lease liabilities | |||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | |||
Liabilities arising from financing activities, beginning balance | 1,540 | 1,584 | |
Changes from financing cash flows: | |||
Payment of lease liabilities | (285) | (232) | |
Non-cash changes: | |||
Lease additions | 317 | 182 | |
Changes in foreign exchange and fair value | (17) | 6 | |
Liabilities arising from financing activities, ending balance | $ 1,555 | $ 1,540 | $ 1,584 |
Segmented Information - Narrati
Segmented Information - Narrative (Details) | 12 Months Ended |
Dec. 31, 2023 segment | |
Operating Segments [Abstract] | |
Number of geographic segments | 3 |
Segmented Information - Operati
Segmented Information - Operating Segments Earnings (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Revenue [abstract] | |||
Product sales | $ 40,835 | $ 49,530 | $ 32,854 |
Less: royalties | (4,867) | (7,232) | (2,797) |
Revenue | 35,968 | 42,298 | 30,057 |
Expenses | |||
Production | 8,480 | 8,712 | 7,152 |
Transportation, blending and feedstock | 9,302 | 9,973 | 6,604 |
Depletion, depreciation and amortization | 6,413 | 7,353 | 5,724 |
Asset retirement obligation accretion | 366 | 281 | 185 |
Risk management activities (commodity derivatives) | 14 | 7 | (17) |
Gain on acquisitions | 0 | 0 | (478) |
Income from North West Redwater Partnership | 0 | 0 | (400) |
Total expenses | 25,803 | 28,594 | 20,146 |
Earnings before taxes | 10,165 | 13,704 | 9,911 |
Administration | 452 | 415 | 366 |
Share-based compensation | 491 | 804 | 514 |
Interest and other financing expense | 636 | 549 | 711 |
Net unrealized risk management loss (gain) | 12 | (28) | 19 |
Foreign exchange (gain) loss | (279) | 738 | (127) |
Gain from investments | (56) | (196) | (141) |
Current income tax expense | 1,879 | 2,906 | 1,848 |
Deferred corporate income tax | 53 | (139) | 399 |
Net earnings | 8,233 | 10,937 | 7,664 |
Accumulated depletion and depreciation | |||
Expenses | |||
Recoverability charge | 436 | 1,620 | |
Total Segments | |||
Revenue [abstract] | |||
Less: royalties | (4,867) | (7,232) | (2,797) |
Revenue | 35,968 | 42,298 | 30,057 |
Expenses | |||
Production | 8,480 | 8,712 | 7,152 |
Transportation, blending and feedstock | 9,302 | 9,973 | 6,604 |
Depletion, depreciation and amortization | 6,413 | 7,353 | 5,724 |
Asset retirement obligation accretion | 366 | 281 | 185 |
Risk management activities (commodity derivatives) | (24) | (18) | (29) |
Gain on acquisitions | 0 | 0 | (478) |
Income from North West Redwater Partnership | 0 | 0 | (400) |
Total expenses | 24,585 | 26,337 | 18,816 |
Earnings before taxes | 11,383 | 15,961 | 11,241 |
Total Segments | Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 960 | 1,285 | 882 |
Total Segments | Crude Oil, Natural Gas Liquids, Natural Gas, Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 40,835 | 49,530 | 32,854 |
North Sea | |||
Expenses | |||
Recoverability charge | 436 | 1,620 | |
Operating segments | North America | |||
Revenue [abstract] | |||
Less: royalties | (2,443) | (3,918) | (1,694) |
Revenue | 17,317 | 21,985 | 15,387 |
Expenses | |||
Production | 3,617 | 3,754 | 2,963 |
Transportation, blending and feedstock | 5,808 | 6,394 | 4,772 |
Depletion, depreciation and amortization | 3,679 | 3,595 | 3,569 |
Asset retirement obligation accretion | 234 | 171 | 101 |
Risk management activities (commodity derivatives) | (24) | (18) | (29) |
Gain on acquisitions | 0 | 0 | (478) |
Income from North West Redwater Partnership | 0 | 0 | 0 |
Total expenses | 13,362 | 13,932 | 10,956 |
Earnings before taxes | 3,955 | 8,053 | 4,431 |
Operating segments | North America | Accumulated depletion and depreciation | |||
Expenses | |||
Recoverability charge | 0 | 0 | |
Operating segments | North America | Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 10 | 217 | 119 |
Operating segments | North America | Crude Oil, Natural Gas Liquids, Natural Gas, Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 19,760 | 25,903 | 17,081 |
Operating segments | North Sea | |||
Revenue [abstract] | |||
Less: royalties | (1) | (1) | (1) |
Revenue | 441 | 635 | 610 |
Expenses | |||
Production | 342 | 437 | 383 |
Transportation, blending and feedstock | 7 | 6 | 7 |
Depletion, depreciation and amortization | 494 | 1,747 | 160 |
Asset retirement obligation accretion | 46 | 33 | 21 |
Risk management activities (commodity derivatives) | 0 | 0 | 0 |
Gain on acquisitions | 0 | 0 | 0 |
Income from North West Redwater Partnership | 0 | 0 | 0 |
Total expenses | 889 | 2,223 | 571 |
Earnings before taxes | (448) | (1,588) | 39 |
Operating segments | North Sea | Accumulated depletion and depreciation | |||
Expenses | |||
Recoverability charge | 436 | 1,620 | |
Operating segments | North Sea | Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 0 | 0 | (1) |
Operating segments | North Sea | Crude Oil, Natural Gas Liquids, Natural Gas, Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 442 | 636 | 611 |
Operating segments | Offshore Africa | |||
Revenue [abstract] | |||
Less: royalties | (57) | (71) | (21) |
Revenue | 580 | 686 | 437 |
Expenses | |||
Production | 141 | 114 | 91 |
Transportation, blending and feedstock | 1 | 1 | 1 |
Depletion, depreciation and amortization | 213 | 173 | 142 |
Asset retirement obligation accretion | 8 | 7 | 6 |
Risk management activities (commodity derivatives) | 0 | 0 | 0 |
Gain on acquisitions | 0 | 0 | 0 |
Income from North West Redwater Partnership | 0 | 0 | 0 |
Total expenses | 363 | 295 | 240 |
Earnings before taxes | 217 | 391 | 197 |
Operating segments | Offshore Africa | Accumulated depletion and depreciation | |||
Expenses | |||
Recoverability charge | 0 | 0 | |
Operating segments | Offshore Africa | Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 9 | 8 | 7 |
Operating segments | Offshore Africa | Crude Oil, Natural Gas Liquids, Natural Gas, Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 637 | 757 | 458 |
Operating segments | Oil Sands Mining and Upgrading | |||
Revenue [abstract] | |||
Less: royalties | (2,366) | (3,242) | (1,081) |
Revenue | 16,300 | 17,711 | 13,025 |
Expenses | |||
Production | 3,989 | 4,076 | 3,414 |
Transportation, blending and feedstock | 2,563 | 2,652 | 1,505 |
Depletion, depreciation and amortization | 2,011 | 1,822 | 1,838 |
Asset retirement obligation accretion | 78 | 70 | 57 |
Risk management activities (commodity derivatives) | 0 | 0 | 0 |
Gain on acquisitions | 0 | 0 | 0 |
Income from North West Redwater Partnership | 0 | 0 | 0 |
Total expenses | 8,641 | 8,620 | 6,814 |
Earnings before taxes | 7,659 | 9,091 | 6,211 |
Operating segments | Oil Sands Mining and Upgrading | Accumulated depletion and depreciation | |||
Expenses | |||
Recoverability charge | 0 | 0 | |
Operating segments | Oil Sands Mining and Upgrading | Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 5 | 149 | 73 |
Operating segments | Oil Sands Mining and Upgrading | Crude Oil, Natural Gas Liquids, Natural Gas, Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 18,666 | 20,953 | 14,106 |
Operating segments | Midstream and Refining | |||
Revenue [abstract] | |||
Less: royalties | 0 | 0 | 0 |
Revenue | 1,002 | 986 | 759 |
Expenses | |||
Production | 332 | 271 | 234 |
Transportation, blending and feedstock | 664 | 691 | 550 |
Depletion, depreciation and amortization | 16 | 16 | 15 |
Asset retirement obligation accretion | 0 | 0 | 0 |
Risk management activities (commodity derivatives) | 0 | 0 | 0 |
Gain on acquisitions | 0 | 0 | 0 |
Income from North West Redwater Partnership | 0 | 0 | (400) |
Total expenses | 1,012 | 978 | 399 |
Earnings before taxes | (10) | 8 | 360 |
Operating segments | Midstream and Refining | Accumulated depletion and depreciation | |||
Expenses | |||
Recoverability charge | 0 | 0 | |
Operating segments | Midstream and Refining | Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 926 | 906 | 681 |
Operating segments | Midstream and Refining | Crude Oil, Natural Gas Liquids, Natural Gas, Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 1,002 | 986 | 759 |
Non-segmented | |||
Expenses | |||
Total expenses | 1,218 | 2,257 | 1,330 |
Administration | 452 | 415 | 366 |
Share-based compensation | 491 | 804 | 514 |
Interest and other financing expense | 636 | 549 | 711 |
Net unrealized risk management loss (gain) | (26) | (53) | 7 |
Foreign exchange (gain) loss | (279) | 738 | (127) |
Gain from investments | (56) | (196) | (141) |
Non-segmented | Accumulated depletion and depreciation | |||
Expenses | |||
Recoverability charge | 0 | 0 | |
Inter-segment elimination and Other | |||
Revenue [abstract] | |||
Less: royalties | 0 | 0 | 0 |
Revenue | 328 | 295 | (161) |
Expenses | |||
Production | 59 | 60 | 67 |
Transportation, blending and feedstock | 259 | 229 | (231) |
Depletion, depreciation and amortization | 0 | 0 | 0 |
Asset retirement obligation accretion | 0 | 0 | 0 |
Risk management activities (commodity derivatives) | 0 | 0 | 0 |
Gain on acquisitions | 0 | 0 | 0 |
Income from North West Redwater Partnership | 0 | 0 | 0 |
Total expenses | 318 | 289 | (164) |
Earnings before taxes | 10 | 6 | 3 |
Inter-segment elimination and Other | Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 10 | 5 | 3 |
Inter-segment elimination and Other | Crude Oil, Natural Gas Liquids, Natural Gas, Other Income And Revenue | |||
Revenue [abstract] | |||
Revenue | 328 | 295 | (161) |
Crude Oil and NGLs | Total Segments | |||
Revenue [abstract] | |||
Product sales | 37,300 | 43,009 | 29,256 |
Crude Oil and NGLs | Operating segments | North America | |||
Revenue [abstract] | |||
Product sales | 17,375 | 20,755 | 14,478 |
Crude Oil and NGLs | Operating segments | North Sea | |||
Revenue [abstract] | |||
Product sales | 435 | 623 | 607 |
Crude Oil and NGLs | Operating segments | Offshore Africa | |||
Revenue [abstract] | |||
Product sales | 577 | 694 | 420 |
Crude Oil and NGLs | Operating segments | Oil Sands Mining and Upgrading | |||
Revenue [abstract] | |||
Product sales | 18,661 | 20,804 | 14,033 |
Crude Oil and NGLs | Operating segments | Midstream and Refining | |||
Revenue [abstract] | |||
Product sales | 76 | 80 | 78 |
Crude Oil and NGLs | Inter-segment elimination and Other | |||
Revenue [abstract] | |||
Product sales | 176 | 53 | (360) |
Natural gas | Total Segments | |||
Revenue [abstract] | |||
Product sales | 2,575 | 5,236 | 2,716 |
Natural gas | Operating segments | North America | |||
Revenue [abstract] | |||
Product sales | 2,375 | 4,931 | 2,484 |
Natural gas | Operating segments | North Sea | |||
Revenue [abstract] | |||
Product sales | 7 | 13 | 5 |
Natural gas | Operating segments | Offshore Africa | |||
Revenue [abstract] | |||
Product sales | 51 | 55 | 31 |
Natural gas | Operating segments | Oil Sands Mining and Upgrading | |||
Revenue [abstract] | |||
Product sales | 0 | 0 | 0 |
Natural gas | Operating segments | Midstream and Refining | |||
Revenue [abstract] | |||
Product sales | 0 | 0 | 0 |
Natural gas | Inter-segment elimination and Other | |||
Revenue [abstract] | |||
Product sales | $ 142 | $ 237 | $ 196 |
Segmented Information - Capital
Segmented Information - Capital Expenditures (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Exploration and evaluation assets | ||
Net expenditures | $ 44 | $ 33 |
Non-cash and fair value changes | (61) | (59) |
Capitalized costs | (17) | (26) |
Property, plant and equipment | ||
Net expenditures | 4,865 | 5,103 |
Non-cash and fair value changes | (29) | (575) |
Capitalized costs | 4,836 | 4,528 |
Net expenditures | 4,909 | 5,136 |
Total non-cash and fair value changes | (90) | (634) |
Total capitalised costs | 4,819 | 4,502 |
Operating segments | Exploration and Production | ||
Property, plant and equipment | ||
Net expenditures | 2,931 | 3,350 |
Non-cash and fair value changes | 222 | 269 |
Capitalized costs | 3,153 | 3,619 |
Operating segments | North America | ||
Exploration and evaluation assets | ||
Net expenditures | 41 | 28 |
Non-cash and fair value changes | (36) | (59) |
Capitalized costs | 5 | (31) |
Property, plant and equipment | ||
Net expenditures | 2,729 | 3,105 |
Non-cash and fair value changes | (321) | 136 |
Capitalized costs | 2,408 | 3,241 |
Operating segments | North Sea | ||
Property, plant and equipment | ||
Net expenditures | 33 | 126 |
Non-cash and fair value changes | 525 | 177 |
Capitalized costs | 558 | 303 |
Operating segments | Offshore Africa | ||
Exploration and evaluation assets | ||
Net expenditures | 3 | 5 |
Non-cash and fair value changes | 0 | 0 |
Capitalized costs | 3 | 5 |
Property, plant and equipment | ||
Net expenditures | 169 | 119 |
Non-cash and fair value changes | 18 | (44) |
Capitalized costs | 187 | 75 |
Operating segments | Oil Sands Mining and Upgrading | ||
Exploration and evaluation assets | ||
Net expenditures | 0 | 0 |
Non-cash and fair value changes | (25) | 0 |
Capitalized costs | (25) | 0 |
Property, plant and equipment | ||
Net expenditures | 1,894 | 1,719 |
Non-cash and fair value changes | (251) | (843) |
Capitalized costs | 1,643 | 876 |
Operating segments | Midstream and Refining | ||
Property, plant and equipment | ||
Net expenditures | 10 | 9 |
Non-cash and fair value changes | 0 | (1) |
Capitalized costs | 10 | 8 |
Head Office | ||
Property, plant and equipment | ||
Net expenditures | 30 | 25 |
Non-cash and fair value changes | 0 | 0 |
Capitalized costs | $ 30 | $ 25 |
Segmented Information - Segment
Segmented Information - Segmented Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of operating segments [line items] | ||
Assets | $ 75,955 | $ 76,142 |
Operating segments | North America | ||
Disclosure of operating segments [line items] | ||
Assets | 30,058 | 31,135 |
Operating segments | North Sea | ||
Disclosure of operating segments [line items] | ||
Assets | 602 | 378 |
Operating segments | Offshore Africa | ||
Disclosure of operating segments [line items] | ||
Assets | 1,380 | 1,322 |
Operating segments | Other | ||
Disclosure of operating segments [line items] | ||
Assets | 32 | 54 |
Operating segments | Oil Sands Mining and Upgrading | ||
Disclosure of operating segments [line items] | ||
Assets | 42,865 | 42,102 |
Operating segments | Midstream and Refining | ||
Disclosure of operating segments [line items] | ||
Assets | 856 | 979 |
Head Office | ||
Disclosure of operating segments [line items] | ||
Assets | $ 162 | $ 172 |
Remuneration of Directors and_3
Remuneration of Directors and Senior Management (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Non-management directors | |||
Disclosure of transactions between related parties [line items] | |||
Fees earned and salary | $ 3 | $ 2 | $ 2 |
Senior management | |||
Disclosure of transactions between related parties [line items] | |||
Fees earned and salary | 2 | 2 | 2 |
Common stock option based awards | 13 | 12 | 10 |
Annual incentive plans | 5 | 5 | 6 |
Long-term incentive plans | 19 | 18 | 19 |
Total | $ 39 | $ 37 | $ 37 |
Supplementary Oil And Gas Inf_3
Supplementary Oil And Gas Information (Unaudited) - Twelve Month Average Benchmark Prices (Details) | 12 Months Ended | |
Dec. 31, 2023 $ / bbl $ / bbl $ / MMBTU $ / MMBTU | Dec. 31, 2022 $ / bbl $ / MMBTU $ / bbl $ / MMBTU | |
USD | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Average foreign exchange rate | 0.7407 | 0.7709 |
Natural Gas | Henry Hub | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per MMBtu | $ / MMBTU | 2.75 | 6.44 |
Natural Gas | AECO | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per MMBtu | $ / MMBTU | 2.79 | 5.59 |
Natural Gas | BC Westcoast Station 2 | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per MMBtu | $ / MMBTU | 2.10 | 4.51 |
WTI | Crude Oil and NGLs | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per bbl | 78.10 | 94.13 |
WCS | Crude Oil and NGLs | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per bbl | 79.95 | 99.4 |
Canadian Light Sweet | Crude Oil and NGLs | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per bbl | 100.93 | 118.9 |
Cromer LSB | Crude Oil and NGLs | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per bbl | 99.48 | 117.76 |
Brent | Crude Oil and NGLs | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per bbl | 82.51 | 97.98 |
Edmonton C5+ | Crude Oil and NGLs | ||
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | ||
Twelve month average benchmark price dollars per bbl | 103.43 | 119.93 |
Supplementary Oil And Gas Inf_4
Supplementary Oil And Gas Information (Unaudited) - Proved and Proved Developed Oil and Natural Gas Liquids, Net of Royalties (Details) - MMBbls | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Sales of reserves in place (in MMbbl) | (1) | |||
Synthetic Crude Oil | North America | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 5,390 | 5,944 | 6,847 | |
Extensions and discoveries (in MMbbl) | 162 | 0 | 0 | |
Improved recovery (in MMbbl) | 28 | 29 | 0 | |
Purchases of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | (141) | (128) | (150) | |
Economic revisions due to prices (in MMbbl) | 333 | (455) | (927) | |
Revisions of prior estimates (in MMbbl) | 68 | 0 | 174 | |
Proved reserves, net, ending balance | 5,840 | 5,390 | 5,944 | |
Net proved developed reserves (in MMbbl) | 5,804 | 5,389 | 5,929 | 6,770 |
Bitumen | North America | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 2,546 | 2,289 | 2,413 | |
Extensions and discoveries (in MMbbl) | 67 | 195 | 101 | |
Improved recovery (in MMbbl) | 9 | 5 | 19 | |
Purchases of reserves in place (in MMbbl) | 0 | 267 | 0 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | (102) | (91) | (103) | |
Economic revisions due to prices (in MMbbl) | 123 | (263) | (296) | |
Revisions of prior estimates (in MMbbl) | 26 | 144 | 155 | |
Proved reserves, net, ending balance | 2,669 | 2,546 | 2,289 | |
Net proved developed reserves (in MMbbl) | 610 | 582 | 584 | 628 |
Crude Oil and NGLs | North America | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 696 | 708 | 525 | |
Extensions and discoveries (in MMbbl) | 51 | 11 | 14 | |
Improved recovery (in MMbbl) | 37 | 21 | 14 | |
Purchases of reserves in place (in MMbbl) | 0 | 21 | 52 | |
Sales of reserves in place (in MMbbl) | (1) | 0 | 0 | |
Production (in MMbbl) | (47) | (45) | (45) | |
Economic revisions due to prices (in MMbbl) | 29 | (73) | 108 | |
Revisions of prior estimates (in MMbbl) | 1 | 54 | 40 | |
Proved reserves, net, ending balance | 767 | 696 | 708 | |
Net proved developed reserves (in MMbbl) | 337 | 359 | 370 | 285 |
Crude Oil and NGLs | North Sea | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 11 | 79 | 87 | |
Extensions and discoveries (in MMbbl) | 0 | 0 | 0 | |
Improved recovery (in MMbbl) | 0 | 0 | 0 | |
Purchases of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | (5) | (5) | (6) | |
Economic revisions due to prices (in MMbbl) | 0 | 1 | 1 | |
Revisions of prior estimates (in MMbbl) | 3 | (64) | (3) | |
Proved reserves, net, ending balance | 9 | 11 | 79 | |
Net proved developed reserves (in MMbbl) | 6 | 5 | 39 | 32 |
Crude Oil and NGLs | Offshore Africa | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 57 | 64 | 71 | |
Extensions and discoveries (in MMbbl) | 0 | 0 | 0 | |
Improved recovery (in MMbbl) | 0 | 0 | 0 | |
Purchases of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | (4) | (5) | (5) | |
Economic revisions due to prices (in MMbbl) | 1 | (2) | (4) | |
Revisions of prior estimates (in MMbbl) | 1 | 0 | 2 | |
Proved reserves, net, ending balance | 54 | 57 | 64 | |
Net proved developed reserves (in MMbbl) | 30 | 34 | 38 | 37 |
Crude Oil, Synthetic Crude Oil, Bitumen, Natural Gas, Natural Gas Liquids | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 8,700 | 9,083 | 9,943 | |
Extensions and discoveries (in MMbbl) | 280 | 205 | 115 | |
Improved recovery (in MMbbl) | 75 | 56 | 33 | |
Purchases of reserves in place (in MMbbl) | 0 | 288 | 52 | |
Sales of reserves in place (in MMbbl) | (1) | 0 | 0 | |
Production (in MMbbl) | (298) | (274) | (309) | |
Economic revisions due to prices (in MMbbl) | 485 | (792) | (1,118) | |
Revisions of prior estimates (in MMbbl) | 98 | 134 | 368 | |
Proved reserves, net, ending balance | 9,339 | 8,700 | 9,083 | |
Net proved developed reserves (in MMbbl) | 6,787 | 6,369 | 6,960 | 7,751 |
Crude Oil, Synthetic Crude Oil, Bitumen, Natural Gas, Natural Gas Liquids | North America | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 8,632 | 8,941 | 9,785 | |
Extensions and discoveries (in MMbbl) | 280 | 205 | 115 | |
Improved recovery (in MMbbl) | 75 | 56 | 33 | |
Purchases of reserves in place (in MMbbl) | 0 | 288 | 52 | |
Sales of reserves in place (in MMbbl) | (1) | 0 | 0 | |
Production (in MMbbl) | (289) | (265) | (297) | |
Economic revisions due to prices (in MMbbl) | 484 | (791) | (1,115) | |
Revisions of prior estimates (in MMbbl) | 94 | 198 | 369 | |
Proved reserves, net, ending balance | 9,276 | 8,632 | 8,941 | |
Net proved developed reserves (in MMbbl) | 6,752 | 6,330 | 6,883 | 7,682 |
Supplementary Oil And Gas Inf_5
Supplementary Oil And Gas Information (Unaudited) - Oil and Natural Gas Liquids Narrative (Details) - MMBbls | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reserve Quantities [Line Items] | |||
Sales of reserves in place (in MMbbl) | 1 | ||
Crude Oil, Synthetic Crude Oil, Bitumen, Natural Gas, Natural Gas Liquids | |||
Reserve Quantities [Line Items] | |||
Change in proved developed and undeveloped reserves, net (in MMbbl) | 639 | (383) | (860) |
Extensions and discoveries (in MMbbl) | 280 | 205 | 115 |
Improved recovery (in MMbbl) | 75 | 56 | 33 |
Sales of reserves in place (in MMbbl) | 1 | 0 | 0 |
Purchases of reserves in place (in MMbbl) | 0 | 288 | 52 |
Production (in MMbbl) | 298 | 274 | 309 |
Economic revisions due to prices (in MMbbl) | 485 | (792) | (1,118) |
Revisions of prior estimates (in MMbbl) | 98 | 134 | 368 |
Supplementary Oil And Gas Inf_6
Supplementary Oil And Gas Information (Unaudited) - Proved and Proved Developed Natural Gas Reserve Quantities (Details) - MMBbls | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Sales of reserves in place (in Bcf) | (1) | |||
Natural Gas | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 12,246 | 11,318 | 7,701 | |
Extensions and discoveries (in Bcf) | 1,185 | 251 | 545 | |
Improved recovery (in Bcf) | 603 | 192 | 161 | |
Purchases of reserves in place (in Bcf) | 0 | 228 | 1,654 | |
Sales of reserves in place (in Bcf) | (6) | 0 | (1) | |
Production (in Bcf) | (755) | (693) | (587) | |
Economic revisions due to prices (in Bcf) | 88 | (575) | 708 | |
Revisions of prior estimates (in Bcf) | 58 | 1,526 | 1,136 | |
Proved reserves, net, ending balance | 13,419 | 12,246 | 11,318 | |
Net proved developed reserves (in Bcf) | 4,040 | 4,975 | 4,492 | 3,144 |
Natural Gas | North America | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 12,217 | 11,285 | 7,655 | |
Extensions and discoveries (in Bcf) | 1,185 | 251 | 545 | |
Improved recovery (in Bcf) | 603 | 192 | 161 | |
Purchases of reserves in place (in Bcf) | 0 | 228 | 1,654 | |
Sales of reserves in place (in Bcf) | (6) | 0 | (1) | |
Production (in Bcf) | (750) | (688) | (581) | |
Economic revisions due to prices (in Bcf) | 87 | (572) | 712 | |
Revisions of prior estimates (in Bcf) | 57 | 1,521 | 1,139 | |
Proved reserves, net, ending balance | 13,393 | 12,217 | 11,285 | |
Net proved developed reserves (in Bcf) | 4,029 | 4,956 | 4,469 | 3,116 |
Natural Gas | North Sea | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 4 | 8 | 12 | |
Extensions and discoveries (in Bcf) | 0 | 0 | 0 | |
Improved recovery (in Bcf) | 0 | 0 | 0 | |
Purchases of reserves in place (in Bcf) | 0 | 0 | 0 | |
Sales of reserves in place (in Bcf) | 0 | 0 | 0 | |
Production (in Bcf) | (1) | (1) | (1) | |
Economic revisions due to prices (in Bcf) | 0 | 0 | 0 | |
Revisions of prior estimates (in Bcf) | (1) | (3) | (3) | |
Proved reserves, net, ending balance | 3 | 4 | 8 | |
Net proved developed reserves (in Bcf) | 1 | 1 | 3 | 6 |
Natural Gas | Offshore Africa | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 25 | 25 | 34 | |
Extensions and discoveries (in Bcf) | 0 | 0 | 0 | |
Improved recovery (in Bcf) | 0 | 0 | 0 | |
Purchases of reserves in place (in Bcf) | 0 | 0 | 0 | |
Sales of reserves in place (in Bcf) | 0 | 0 | 0 | |
Production (in Bcf) | (4) | (4) | (4) | |
Economic revisions due to prices (in Bcf) | 1 | (3) | (4) | |
Revisions of prior estimates (in Bcf) | 1 | 7 | 0 | |
Proved reserves, net, ending balance | 23 | 25 | 25 | |
Net proved developed reserves (in Bcf) | 10 | 19 | 20 | 22 |
Supplementary Oil And Gas Inf_7
Supplementary Oil And Gas Information (Unaudited) - Natural Gas Narrative (Details) - MMBbls | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reserve Quantities [Line Items] | |||
Sales of reserves in place (in Bcf) | 1 | ||
Natural Gas | |||
Reserve Quantities [Line Items] | |||
Change in proved developed and undeveloped reserves, net (in MMbbl) | 1,173 | 928 | 3,617 |
Extensions and discoveries (in MMbbl) | 1,185 | 251 | 545 |
Improved recovery (in MMbbl) | 603 | 192 | 161 |
Sales of reserves in place (in Bcf) | 6 | 0 | 1 |
Purchases of reserves in place (in MMbbl) | 0 | 228 | 1,654 |
Production (in Bcf) | 755 | 693 | 587 |
Economic revisions due to prices (in Bcf) | 88 | (575) | 708 |
Revisions of prior estimates (in Bcf) | 58 | 1,526 | 1,136 |
Supplementary Oil And Gas Inf_8
Supplementary Oil And Gas Information (Unaudited) - Capitalized Costs Related to Crude Oil and Natural Gas Activities (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Proved properties | $ 145,873 | $ 141,397 | $ 136,108 |
Unproved properties | 2,208 | 2,226 | 2,250 |
Capitalized costs, gross | 148,081 | 143,623 | 138,358 |
Net capitalized costs | 66,396 | 66,693 | 68,253 |
Oil and gas assets | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Less: accumulated depletion and depreciation | (81,685) | (76,930) | (70,105) |
North America | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Proved properties | 132,858 | 128,807 | 124,690 |
Unproved properties | 2,108 | 2,128 | 2,159 |
Capitalized costs, gross | 134,966 | 130,935 | 126,849 |
Net capitalized costs | 65,021 | 65,388 | 65,618 |
North America | Oil and gas assets | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Less: accumulated depletion and depreciation | (69,945) | (65,547) | (61,231) |
North Sea | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Proved properties | 8,606 | 8,258 | 7,438 |
Unproved properties | 0 | 0 | 0 |
Capitalized costs, gross | 8,606 | 8,258 | 7,438 |
Net capitalized costs | 224 | 152 | 1,487 |
North Sea | Oil and gas assets | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Less: accumulated depletion and depreciation | (8,382) | (8,106) | (5,951) |
Offshore Africa | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Proved properties | 4,409 | 4,332 | 3,980 |
Unproved properties | 100 | 98 | 91 |
Capitalized costs, gross | 4,509 | 4,430 | 4,071 |
Net capitalized costs | 1,151 | 1,153 | 1,148 |
Offshore Africa | Oil and gas assets | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Less: accumulated depletion and depreciation | $ (3,358) | $ (3,277) | $ (2,923) |
Supplementary Oil And Gas Inf_9
Supplementary Oil And Gas Information (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Proved | $ 0 | $ 524 | $ 1,371 |
Unproved | 0 | 0 | 26 |
Exploration | 46 | 45 | 12 |
Development | 5,784 | 4,766 | 4,557 |
Costs incurred | 5,830 | 5,335 | 5,966 |
North America | |||
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Proved | 0 | 524 | 1,371 |
Unproved | 0 | 0 | 26 |
Exploration | 43 | 40 | 4 |
Development | 5,039 | 4,387 | 4,301 |
Costs incurred | 5,082 | 4,951 | 5,702 |
North Sea | |||
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Proved | 0 | 0 | 0 |
Unproved | 0 | 0 | 0 |
Exploration | 0 | 0 | 0 |
Development | 558 | 304 | 208 |
Costs incurred | 558 | 304 | 208 |
Offshore Africa | |||
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Proved | 0 | 0 | 0 |
Unproved | 0 | 0 | 0 |
Exploration | 3 | 5 | 8 |
Development | 187 | 75 | 48 |
Costs incurred | $ 190 | $ 80 | $ 56 |
Supplementary Oil And Gas In_10
Supplementary Oil And Gas Information (Unaudited) - Results of Operations from Crude Oil and Natural Gas Producing Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Supplementary Oil & Gas Information [Line Items] | |||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | $ 35,968 | $ 42,298 | $ 30,057 |
Production | (8,480) | (8,712) | (7,152) |
Transportation | (9,302) | (9,973) | (6,604) |
Depletion, depreciation and amortization | (6,413) | (7,353) | (5,724) |
Asset retirement obligation accretion | (366) | (281) | (185) |
Income tax | (1,879) | (2,906) | (1,848) |
Oil And Gas | |||
Supplementary Oil & Gas Information [Line Items] | |||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 27,796 | 33,020 | 24,160 |
Production | (8,089) | (8,381) | (6,851) |
Transportation | (1,558) | (1,431) | (1,184) |
Depletion, depreciation and amortization | (6,397) | (7,337) | (5,709) |
Asset retirement obligation accretion | (366) | (281) | (185) |
Petroleum revenue tax | 273 | 483 | 33 |
Income tax | (2,684) | (3,552) | (2,396) |
Results of operations | 8,975 | 12,521 | 7,868 |
North America | Oil And Gas | |||
Supplementary Oil & Gas Information [Line Items] | |||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 26,773 | 31,698 | 23,111 |
Production | (7,606) | (7,830) | (6,377) |
Transportation | (1,550) | (1,424) | (1,176) |
Depletion, depreciation and amortization | (5,690) | (5,417) | (5,407) |
Asset retirement obligation accretion | (312) | (241) | (158) |
Petroleum revenue tax | 0 | 0 | 0 |
Income tax | (2,700) | (3,896) | (2,317) |
Results of operations | 8,915 | 12,890 | 7,676 |
North Sea | Oil And Gas | |||
Supplementary Oil & Gas Information [Line Items] | |||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 442 | 635 | 611 |
Production | (342) | (437) | (383) |
Transportation | (7) | (6) | (7) |
Depletion, depreciation and amortization | (494) | (1,747) | (160) |
Asset retirement obligation accretion | (46) | (33) | (21) |
Petroleum revenue tax | 273 | 483 | 33 |
Income tax | 70 | 442 | (29) |
Results of operations | (104) | (663) | 44 |
Offshore Africa | Oil And Gas | |||
Supplementary Oil & Gas Information [Line Items] | |||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 581 | 687 | 438 |
Production | (141) | (114) | (91) |
Transportation | (1) | (1) | (1) |
Depletion, depreciation and amortization | (213) | (173) | (142) |
Asset retirement obligation accretion | (8) | (7) | (6) |
Petroleum revenue tax | 0 | 0 | 0 |
Income tax | (54) | (98) | (50) |
Results of operations | $ 164 | $ 294 | $ 148 |
Supplementary Oil And Gas In_11
Supplementary Oil And Gas Information (Unaudited) - Future Net Cash Flows Relating to Proved Crude Oil and Natural Gas Reserves (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 870,755 | $ 995,482 | $ 692,495 | |
Future production costs | (279,014) | (305,959) | (244,036) | |
Future development costs and asset retirement obligations | (90,415) | (86,658) | (80,374) | |
Future income taxes | (113,057) | (137,288) | (83,144) | |
Future net cash flows | 388,269 | 465,577 | 284,941 | |
10% annual discount for timing of future cash flows | (279,533) | (328,579) | (202,157) | |
Standardized measure of future net cash flows | 108,736 | 136,998 | 82,784 | $ 27,511 |
North America | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 863,544 | 986,672 | 679,123 | |
Future production costs | (276,498) | (303,270) | (238,144) | |
Future development costs and asset retirement obligations | (86,615) | (83,803) | (77,375) | |
Future income taxes | (113,516) | (136,905) | (81,860) | |
Future net cash flows | 386,915 | 462,694 | 281,744 | |
10% annual discount for timing of future cash flows | (278,814) | (327,333) | (201,227) | |
Standardized measure of future net cash flows | 108,101 | 135,361 | 80,517 | |
North Sea | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 1,067 | 1,506 | 7,791 | |
Future production costs | (636) | (691) | (4,074) | |
Future development costs and asset retirement obligations | (1,873) | (1,416) | (1,857) | |
Future income taxes | 967 | 517 | (719) | |
Future net cash flows | (475) | (84) | 1,141 | |
10% annual discount for timing of future cash flows | 168 | 84 | (142) | |
Standardized measure of future net cash flows | (307) | 0 | 999 | |
Offshore Africa | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 6,144 | 7,304 | 5,581 | |
Future production costs | (1,880) | (1,998) | (1,818) | |
Future development costs and asset retirement obligations | (1,927) | (1,439) | (1,142) | |
Future income taxes | (508) | (900) | (565) | |
Future net cash flows | 1,829 | 2,967 | 2,056 | |
10% annual discount for timing of future cash flows | (887) | (1,330) | (788) | |
Standardized measure of future net cash flows | $ 942 | $ 1,637 | $ 1,268 |
Supplementary Oil And Gas In_12
Supplementary Oil And Gas Information (Unaudited) - Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 1 [Roll Forward] | |||
Sales of crude oil and natural gas produced, net of production costs | $ (18,174) | $ (23,242) | $ (16,149) |
Net changes in sales prices and production costs | (47,145) | 79,291 | 74,558 |
Extensions, discoveries and improved recovery | 8,196 | 6,198 | 2,948 |
Changes in estimated future development costs | (1,511) | (3,640) | (2,773) |
Purchases of proved reserves in place | 0 | 5,745 | 4,010 |
Sales of proved reserves in place | (47) | 0 | (1) |
Revisions of previous reserve estimates | 6,647 | (9,956) | (186) |
Accretion of discount | 17,769 | 10,712 | 3,460 |
Changes in production timing and other | (2,831) | 5,463 | 6,638 |
Net change in income taxes | 8,834 | (16,357) | (17,232) |
Net change | (28,262) | 54,214 | 55,273 |
Balance - beginning of year | 136,998 | 82,784 | 27,511 |
Balance - end of year | $ 108,736 | $ 136,998 | $ 82,784 |