DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION | 12 Months Ended |
Dec. 31, 2018shares | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | CANADIAN NATURAL RESOURCES LTD |
Entity Central Index Key | 0001017413 |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2018 |
Document Fiscal Year Focus | 2018 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Emerging Growth Company | false |
Entity Common Stock, Shares Outstanding (in shares) | 1,201,885,667 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 101 | $ 137 |
Accounts receivable | 1,148 | 2,397 |
Current income taxes receivable | 0 | 322 |
Inventory | 955 | 894 |
Prepaids and other | 176 | 175 |
Investments | 524 | 893 |
Current portion of other long-term assets | 116 | 79 |
Current assets | 3,020 | 4,897 |
Non-current assets | ||
Exploration and evaluation assets | 2,637 | 2,632 |
Property, plant and equipment | 64,559 | 65,170 |
Other long-term assets | 1,343 | 1,168 |
Assets | 71,559 | 73,867 |
Current liabilities | ||
Accounts payable | 779 | 775 |
Accrued liabilities | 2,356 | 2,597 |
Current income taxes payable | 151 | 0 |
Current portion of long-term debt | 1,141 | 1,877 |
Current portion of other long-term liabilities | 335 | 1,012 |
Current liabilities | 4,762 | 6,261 |
Non-current liabilities | ||
Long-term debt | 19,482 | 20,581 |
Other long-term liabilities | 3,890 | 4,397 |
Deferred income taxes | 11,451 | 10,975 |
Liabilities | 39,585 | 42,214 |
SHAREHOLDERS’ EQUITY | ||
Share capital | 9,323 | 9,109 |
Retained earnings | 22,529 | 22,612 |
Accumulated other comprehensive income (loss) | 122 | (68) |
Shareholders' equity | 31,974 | 31,653 |
Liabilities and shareholders' equity | $ 71,559 | $ 73,867 |
CONSOLIDATED STATEMENTS OF EARN
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) - CAD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||
Profit or loss [abstract] | |||||
Product sales | $ 22,282 | $ 18,360 | [1] | $ 12,002 | [1] |
Less: royalties | (1,255) | (1,018) | (575) | ||
Revenue | 21,027 | 17,342 | 11,427 | ||
Expenses | |||||
Production | 6,464 | 5,675 | [1] | 4,184 | [1] |
Transportation, blending and feedstock | 4,189 | 3,529 | [1] | 2,822 | [1] |
Depletion, depreciation and amortization | 5,161 | 5,186 | 4,858 | ||
Administration | 325 | 319 | 345 | ||
Share-based compensation | (146) | 134 | 355 | ||
Asset retirement obligation accretion | 186 | 164 | 142 | ||
Interest and other financing expense | 739 | 631 | 383 | ||
Risk management activities | (134) | 35 | 33 | ||
Foreign exchange loss (gain) | 827 | (787) | (55) | ||
Gain on acquisition, disposition and revaluation of properties | (452) | (379) | (250) | ||
Loss (gain) from investments | 346 | (38) | (327) | ||
Total expenses | 17,505 | 14,469 | 12,490 | ||
Earnings (loss) before taxes | 3,522 | 2,873 | (1,063) | ||
Current income tax expense (recovery) | 374 | (164) | (618) | ||
Deferred income tax expense (recovery) | 557 | 640 | (241) | ||
Net earnings (loss) | $ 2,591 | $ 2,397 | $ (204) | ||
Net earnings (loss) per common share | |||||
Basic earnings (loss) per share (in CAD per share) | $ 2.13 | $ 2.04 | $ (0.19) | ||
Diluted earnings (loss) per share (in CAD per share) | $ 2.12 | $ 2.03 | $ (0.19) | ||
[1] | In connection with adoption of IFRS 15 on January 1, 2018, the Company has reclassified certain comparative amounts in a manner consistent with the presentation adopted for the year ended December 31, 2018 (see note 2). |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of comprehensive income [abstract] | |||
Net earnings (loss) | $ 2,591 | $ 2,397 | $ (204) |
Net change in derivative financial instruments designated as cash flow hedges | |||
Unrealized income (loss), net of taxes of $nil (2017 – $9 million, 2016 – $3 million) | 5 | 53 | (18) |
Reclassification to net earnings (loss), net of taxes of $6 million (2017 – $5 million, 2016 – $2 million) | (39) | (33) | (13) |
Net change in derivative financial instruments designated as cash flow hedges | (34) | 20 | (31) |
Foreign currency translation adjustment | |||
Translation of net investment | 224 | (158) | 26 |
Other comprehensive income (loss), net of taxes | 190 | (138) | (5) |
Comprehensive income (loss) | $ 2,781 | $ 2,259 | $ (209) |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of comprehensive income [abstract] | |||
Unrealized income (loss), tax | $ 0 | $ 9 | $ 3 |
Reclassification to net earnings (loss), tax | $ 6 | $ 5 | $ 2 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD ($) $ in Millions | Total | AOSP | Share capital | Retained earnings | Accumulated other comprehensive income (loss) | |
Balance – beginning of year at Dec. 31, 2015 | $ 4,541 | $ 22,765 | $ 75 | |||
Issued for the acquisition of AOSP and other assets | [1] | 0 | ||||
Issued upon exercise of stock options | 559 | |||||
Previously recognized liability on stock options exercised for common shares | 117 | |||||
Purchase of common shares under Normal Course Issuer Bid | 0 | 0 | ||||
Return of capital on PrairieSky Royalty Ltd. share distribution | (546) | |||||
Net earnings (loss) | $ (204) | (204) | ||||
Dividends on common shares | (1,035) | |||||
Other comprehensive income (loss), net of taxes | (5) | (5) | ||||
Balance – end of year at Dec. 31, 2016 | 26,267 | 4,671 | 21,526 | 70 | ||
Issued for the acquisition of AOSP and other assets | [1] | 3,818 | ||||
Issued upon exercise of stock options | 466 | |||||
Previously recognized liability on stock options exercised for common shares | 154 | |||||
Purchase of common shares under Normal Course Issuer Bid | 0 | 0 | ||||
Return of capital on PrairieSky Royalty Ltd. share distribution | 0 | |||||
Net earnings (loss) | 2,397 | 2,397 | ||||
Dividends on common shares | (1,311) | |||||
Other comprehensive income (loss), net of taxes | (138) | (138) | ||||
Balance – end of year at Dec. 31, 2017 | 31,653 | 9,109 | 22,612 | (68) | ||
Non-cash share considerations issued on the acquisition of AOSP and other assets | $ 3,818 | |||||
Issued for the acquisition of AOSP and other assets | [1] | 0 | ||||
Issued upon exercise of stock options | 332 | |||||
Previously recognized liability on stock options exercised for common shares | 120 | |||||
Purchase of common shares under Normal Course Issuer Bid | 1,282 | (238) | (1,044) | |||
Return of capital on PrairieSky Royalty Ltd. share distribution | 0 | |||||
Net earnings (loss) | 2,591 | 2,591 | ||||
Dividends on common shares | (1,630) | |||||
Other comprehensive income (loss), net of taxes | 190 | 190 | ||||
Balance – end of year at Dec. 31, 2018 | $ 31,974 | $ 9,323 | $ 22,529 | $ 122 | ||
[1] | During 2017, in connection with the acquisition of direct and indirect interests in the Athabasca Oil Sands Project ("AOSP") and other assets, the Company issued non-cash share consideration of $3,818 million. See note 8. |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Operating activities | ||||
Net earnings (loss) | $ 2,591 | $ 2,397 | $ (204) | |
Non-cash items | ||||
Depletion, depreciation and amortization | 5,161 | 5,186 | 4,858 | |
Share-based compensation | (146) | 134 | 355 | |
Asset retirement obligation accretion | 186 | 164 | 142 | |
Unrealized risk management (gain) loss | (35) | 37 | 25 | |
Unrealized foreign exchange loss (gain) | 706 | (821) | (93) | |
Realized foreign exchange loss on repayment of US dollar securities | 146 | 0 | 0 | |
Gain on acquisition, disposition and revaluation of properties | (452) | (379) | (250) | |
Loss (gain) from investments | 374 | (11) | (299) | |
Deferred income tax expense (recovery) | 557 | 640 | (241) | |
Other | (23) | (110) | (32) | |
Abandonment expenditures | (290) | (274) | (267) | |
Net change in non-cash working capital | 1,346 | 299 | (542) | |
Cash flows from operating activities | 10,121 | 7,262 | 3,452 | |
Financing activities | ||||
(Repayment) issue of bank credit facilities and commercial paper, net | (1,595) | 2,222 | 342 | |
Issue of medium-term notes, net | 0 | 1,791 | 998 | |
(Repayment) issue of US dollar debt securities, net | (1,236) | 2,733 | (834) | |
Issue of common shares on exercise of stock options | 332 | 466 | 559 | |
Purchase of common shares under Normal Course Issuer Bid | (1,282) | 0 | 0 | |
Dividends on common shares | (1,562) | (1,252) | (758) | |
Cash flows (used in) from financing activities | (5,343) | 5,960 | 307 | |
Investing activities | ||||
Net (expenditures) proceeds on exploration and evaluation assets | (266) | (124) | 6 | |
Net expenditures on property, plant and equipment | [1] | (4,175) | (4,574) | (3,803) |
Acquisition of AOSP and other assets, net of cash acquired | [2] | 0 | (8,630) | 0 |
Investment in other long-term assets | (28) | (87) | (99) | |
Net change in non-cash working capital | (345) | 313 | 85 | |
Cash flows used in investing activities | (4,814) | (13,102) | (3,811) | |
(Decrease) increase in cash and cash equivalents | (36) | 120 | (52) | |
Cash and cash equivalents – beginning of year | 137 | 17 | 69 | |
Cash and cash equivalents – end of year | 101 | 137 | 17 | |
Interest paid, net | 911 | 725 | 617 | |
Income taxes received | $ (225) | (792) | (444) | |
Disposal of Cold Lake Pipeline | Investment in Inter Pipeline Ltd. | ||||
Investing activities | ||||
Non-cash share consideration received | $ 190 | |||
AOSP | ||||
Investing activities | ||||
Other working capital | 291 | |||
Fair value of share considerations issued | $ 3,818 | |||
[1] | Net expenditures on property, plant and equipment in 2016 exclude non-cash share consideration of $190 million received from Inter Pipeline Ltd. ("Inter Pipeline") on the disposition of the Company's interest in the Cold Lake Pipeline | |||
[2] | The acquisition of AOSP in 2017 includes net working capital of $291 million and excludes non-cash share consideration of $3,818 million. See note 8. |
ACCOUNTING POLICIES
ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2018 | |
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, Gabon, 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 AOSP. Within Western Canada, the Company maintains certain midstream activities that include pipeline operations, an electricity co-generation system and an investment in the North West Redwater Partnership ("Redwater Partnership"), a general partnership formed 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. 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) SEGMENTED INFORMATION 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. (C) CASH AND CASH EQUIVALENTS Cash comprises cash on hand and demand deposits. Other investments (term deposits and certificates of deposit) with an original term to maturity at purchase of three months or less are reported as cash equivalents in the consolidated balance sheets. (D) INVENTORY Inventory is primarily comprised of product inventory and materials and supplies 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. 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 is determined by reference to current market prices. (E) 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. (F) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Assets under construction are not depleted or depreciated until available for their intended use. The capitalized value of a finance lease is included in property, plant and equipment. 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 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, 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. 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 18 years. Midstream and Head Office The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream and head office assets. Midstream 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 maintenance turnarounds are capitalized and depreciated over the period to the next major maintenance turnaround. All other 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 is written down to its recoverable amount 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 impairment losses 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 impairment loss been recognized for the asset in prior periods. A reversal of impairment 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. (G) 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. (H) OVERBURDEN REMOVAL COSTS Overburden removal costs incurred during the initial development of a mine at Horizon and AOSP are capitalized to property, plant and equipment. Overburden removal costs incurred during the production of a mine are included in the cost of inventory, unless the overburden removal activity has resulted in a probable inflow of future economic benefits to the Company, in which case the costs are capitalized to property, plant and equipment. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from the overburden removal activity. (I) CAPITALIZED BORROWING COSTS Borrowing costs attributable to the acquisition, construction or production of qualifying assets are capitalized to the cost of those assets until such time as the assets are substantially available for their intended use. Qualifying assets are comprised of those significant assets that require a period greater than one year to be available for their intended use. All other borrowing costs are recognized in net earnings. (J) LEASES Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. Operating lease payments are recognized in net earnings over the lease term. The Company adopted IFRS 16 on January 1, 2019 (see note 3). (K) 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 industry 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. (L) 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”). The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. The assets and liabilities of subsidiaries that have a functional currency different from that of the Company are translated into Canadian dollars at the closing rate at the date of the balance sheets, and revenue and expenses are translated at the average rate for the period. Cumulative foreign currency translation adjustments are recognized in other comprehensive income. When the Company disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings. Transactions and balances Foreign currency transactions are translated into the functional currency of the Company and its subsidiaries and partnerships using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at balance sheet date exchange rates of monetary assets and liabilities denominated in currencies other than the functional currency are recognized in net earnings. (M) 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. The Company continues to report revenue for the years ended December 31, 2017 and 2016 in accordance with the Company's previous accounting policy for revenue and cost of goods sold as follows: Revenue from the sale of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. (N) PRODUCTION SHARING CONTRACTS Production generated from Côte d’Ivoire and Gabon 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. (O) 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. Income taxes are recognized in net earnings or other comprehensive income, consistent with the items to which they relate. (P) 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 re-measured 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 Company grants Performance Share Units ("PSUs") to certain executive employees. The PSUs are subject to certain performance conditions and vest three years from original grant date. The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term assets . (Q) 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. The Company continues to report impairment of financial assets for the years ended December 31, 2017 and 2016 in accordance with the Company's previous accounting policy for impairment of financial assets as follows: At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, an impairment loss is recognized. Impairment losses on financial assets carried at amortized cost are calculated as the difference between the amortized cost of the financial asset and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. Impairment losses on financial assets carried at amortized cost 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. (R) 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. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain of its long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. Changes in the fair value of interest rate swap contracts designated as fair value hedges and corresponding changes in the fair value of the hedged long-term debt are recognized in interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are recognized in risk management activities in net earnings. Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized in the consolidated balance sheets and the related long-term debt hedged is no longer revalued for subsequent changes in fair value due to interest rates changes. The fair value adjustment due to interest rates on the long-term debt at the date of termination of the interest rate swap is amortized to interest expense over the remaining term of the long-term debt. 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 initi |
CHANGES IN ACCOUNTING POLICIES
CHANGES IN ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2018 | |
Corporate Information And Statement Of IFRS Compliance [Abstract] | |
CHANGES IN ACCOUNTING POLICIES | CHANGES IN ACCOUNTING POLICIES IFRS 15 "Revenue from Contracts with Customers" In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” to provide guidance on the recognition of revenue and cash flows arising from an entity’s contracts with customers, and related disclosures. The new standard replaces several existing standards related to recognition of revenue and states that revenue should be recognized as performance obligations related to the goods or services delivered are settled. IFRS 15 also provides revenue accounting guidance for contract modifications and multiple-element contracts and prescribes additional disclosure requirements. The Company adopted IFRS 15 on January 1, 2018 using the retrospective with cumulative effect method. There were no changes to reported net earnings or retained earnings as a result of adopting IFRS 15. Under the standard, the Company is required to provide additional disclosure of disaggregated revenue by major product type. In connection with adoption of the standard, the Company has reclassified certain comparative amounts in a manner consistent with the presentation adopted for the year ended December 31, 2018 (see note 22). Upon adoption of IFRS 15, the Company applied the practical expedient such that contracts that were completed in the comparative periods have not been restated. Applying this expedient had no impact to the revenue recognized under the previous revenue accounting standard as all performance obligations had been met and the consideration had been determined. IFRS 9 "Financial Instruments" Effective January 1, 2014, the Company adopted the version of IFRS 9 “Financial Instruments” issued November 2013. In July 2014, the IASB issued amendments to IFRS 9 to include accounting guidance to assess and recognize impairment losses on financial assets based on an expected loss model. The Company retrospectively adopted the amendments to IFRS 9 on January 1, 2018 and elected to apply the limited exemption in IFRS 9 relating to transition for impairment. Accordingly, provisions for impairment have not been restated in the comparative periods. Adoption of the amendment did not have a significant impact on the Company’s previous accounting for impairment of financial assets. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED In October 2018, the IASB issued amendments to IFRS 3 "Definition of a Business" that narrowed and clarified the definition of a business. The amendments also permit a simplified assessment of whether an acquired set of activities and assets is a group of assets rather than a business. The amendments are effective January 1, 2020 with earlier adoption permitted. The amendments apply to business combinations after the date of adoption. The Company is assessing the impact of these amendments on its consolidated financial statements. In October 2018, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" and IAS 8 "Accounting Policies, Changes in Accounting Estimates and Errors". The amendments make minor changes to the definition of the term "material" and align the definition across all IFRS Standards. Materiality is used in making judgments related to the preparation of financial statements. The amendments are effective January 1, 2020 with earlier adoption permitted. The Company is assessing the impact of these amendments on its consolidated financial statements. In October 2017, the IASB issued amendments to IAS 28 "Investments in Associates and Joint Ventures" to clarify that the impairment provisions in IFRS 9 apply to financial instruments in an associate or joint venture that are not accounted for using the equity method, including long-term assets that form part of the net investment in the associate or joint venture. The amendments are effective January 1, 2019 with earlier adoption permitted. The amendments are required to be adopted retrospectively. The Company has determined that these amendments have no significant impact on its consolidated financial statements. In June 2017, the IASB issued IFRIC 23 "Uncertainty over Income Tax Treatments". The interpretation provides guidance on how to reflect the effects of uncertainty in accounting for income taxes where IAS 12 is unclear. The interpretation is effective January 1, 2019. The Company has determined that this interpretation has no significant impact on its consolidated financial statements. IFRS 16 "Leases" In January 2016, the IASB issued IFRS 16 “Leases”, which provides guidance on accounting for leases. The new standard replaces IAS 17 “Leases” and related interpretations. IFRS 16 eliminates the distinction between operating leases and financing leases for lessees and requires balance sheet recognition for all leases. Certain short-term (less than 12 months) and low-value leases (as defined in the standard) are exempt from the requirements, and may continue to be treated as an expense. Leases to explore for or use crude oil, natural gas, minerals and similar non-regenerative resources are exempt from the standard. The Company will adopt IFRS 16 on January 1, 2019 using the retrospective with cumulative effect method with no impact to opening retained earnings at the date of adoption. In accordance with the transitional provisions in the standard, balances reported in the comparative periods will not be restated. On initial adoption, the Company intends to use the following practical expedients under the standard. Certain expedients are on a lease-by-lease basis and others are applicable by class of underlying assets: • the use of a single discount rate to a portfolio of leases with reasonably similar characteristics; • leases with a remaining lease term of less than twelve months as at January 1, 2019 will be treated as short- term leases; and • exclusion of indirect costs for the measurement of lease assets at the date of initial application. The Company does not intend to apply any practical expedients pertaining to grandfathering of leases assessed under the previous standard. On adoption of IFRS 16, the Company will recognize lease assets and liabilities at the present value of the remaining lease payments, discounted using the Company’s applicable borrowing rate on January 1, 2019. The Company expects to report additional lease assets and corresponding liabilities of between $1.5 billion and $1.6 billion . The Company continues to finalize its accounting for leases in accordance with IFRS 16, and the above estimates are subject to change based on finalization of the Company's review of its lease arrangements. In the statement of earnings, depletion, depreciation and amortization expense and interest expense will increase, with corresponding decreases in production, transportation and administration expenses. The Company does not expect to report a material impact on net earnings. Under the new standard, the Company will report cash outflows for repayment of the principal portion of the lease liability as cash flows from financing activities. The interest portion of the lease payments will continue to be classified as cash flows from operating activities. Where the Company, acting as the operator, signs a lease on behalf of a joint operation and assumes the legal liability for that lease, the Company will recognize 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 will be recognized in the consolidated statements of earnings. |
ACCOUNTING STANDARDS ISSUED BUT
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED | 12 Months Ended |
Dec. 31, 2018 | |
Corporate Information And Statement Of IFRS Compliance [Abstract] | |
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED | CHANGES IN ACCOUNTING POLICIES IFRS 15 "Revenue from Contracts with Customers" In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” to provide guidance on the recognition of revenue and cash flows arising from an entity’s contracts with customers, and related disclosures. The new standard replaces several existing standards related to recognition of revenue and states that revenue should be recognized as performance obligations related to the goods or services delivered are settled. IFRS 15 also provides revenue accounting guidance for contract modifications and multiple-element contracts and prescribes additional disclosure requirements. The Company adopted IFRS 15 on January 1, 2018 using the retrospective with cumulative effect method. There were no changes to reported net earnings or retained earnings as a result of adopting IFRS 15. Under the standard, the Company is required to provide additional disclosure of disaggregated revenue by major product type. In connection with adoption of the standard, the Company has reclassified certain comparative amounts in a manner consistent with the presentation adopted for the year ended December 31, 2018 (see note 22). Upon adoption of IFRS 15, the Company applied the practical expedient such that contracts that were completed in the comparative periods have not been restated. Applying this expedient had no impact to the revenue recognized under the previous revenue accounting standard as all performance obligations had been met and the consideration had been determined. IFRS 9 "Financial Instruments" Effective January 1, 2014, the Company adopted the version of IFRS 9 “Financial Instruments” issued November 2013. In July 2014, the IASB issued amendments to IFRS 9 to include accounting guidance to assess and recognize impairment losses on financial assets based on an expected loss model. The Company retrospectively adopted the amendments to IFRS 9 on January 1, 2018 and elected to apply the limited exemption in IFRS 9 relating to transition for impairment. Accordingly, provisions for impairment have not been restated in the comparative periods. Adoption of the amendment did not have a significant impact on the Company’s previous accounting for impairment of financial assets. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED In October 2018, the IASB issued amendments to IFRS 3 "Definition of a Business" that narrowed and clarified the definition of a business. The amendments also permit a simplified assessment of whether an acquired set of activities and assets is a group of assets rather than a business. The amendments are effective January 1, 2020 with earlier adoption permitted. The amendments apply to business combinations after the date of adoption. The Company is assessing the impact of these amendments on its consolidated financial statements. In October 2018, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" and IAS 8 "Accounting Policies, Changes in Accounting Estimates and Errors". The amendments make minor changes to the definition of the term "material" and align the definition across all IFRS Standards. Materiality is used in making judgments related to the preparation of financial statements. The amendments are effective January 1, 2020 with earlier adoption permitted. The Company is assessing the impact of these amendments on its consolidated financial statements. In October 2017, the IASB issued amendments to IAS 28 "Investments in Associates and Joint Ventures" to clarify that the impairment provisions in IFRS 9 apply to financial instruments in an associate or joint venture that are not accounted for using the equity method, including long-term assets that form part of the net investment in the associate or joint venture. The amendments are effective January 1, 2019 with earlier adoption permitted. The amendments are required to be adopted retrospectively. The Company has determined that these amendments have no significant impact on its consolidated financial statements. In June 2017, the IASB issued IFRIC 23 "Uncertainty over Income Tax Treatments". The interpretation provides guidance on how to reflect the effects of uncertainty in accounting for income taxes where IAS 12 is unclear. The interpretation is effective January 1, 2019. The Company has determined that this interpretation has no significant impact on its consolidated financial statements. IFRS 16 "Leases" In January 2016, the IASB issued IFRS 16 “Leases”, which provides guidance on accounting for leases. The new standard replaces IAS 17 “Leases” and related interpretations. IFRS 16 eliminates the distinction between operating leases and financing leases for lessees and requires balance sheet recognition for all leases. Certain short-term (less than 12 months) and low-value leases (as defined in the standard) are exempt from the requirements, and may continue to be treated as an expense. Leases to explore for or use crude oil, natural gas, minerals and similar non-regenerative resources are exempt from the standard. The Company will adopt IFRS 16 on January 1, 2019 using the retrospective with cumulative effect method with no impact to opening retained earnings at the date of adoption. In accordance with the transitional provisions in the standard, balances reported in the comparative periods will not be restated. On initial adoption, the Company intends to use the following practical expedients under the standard. Certain expedients are on a lease-by-lease basis and others are applicable by class of underlying assets: • the use of a single discount rate to a portfolio of leases with reasonably similar characteristics; • leases with a remaining lease term of less than twelve months as at January 1, 2019 will be treated as short- term leases; and • exclusion of indirect costs for the measurement of lease assets at the date of initial application. The Company does not intend to apply any practical expedients pertaining to grandfathering of leases assessed under the previous standard. On adoption of IFRS 16, the Company will recognize lease assets and liabilities at the present value of the remaining lease payments, discounted using the Company’s applicable borrowing rate on January 1, 2019. The Company expects to report additional lease assets and corresponding liabilities of between $1.5 billion and $1.6 billion . The Company continues to finalize its accounting for leases in accordance with IFRS 16, and the above estimates are subject to change based on finalization of the Company's review of its lease arrangements. In the statement of earnings, depletion, depreciation and amortization expense and interest expense will increase, with corresponding decreases in production, transportation and administration expenses. The Company does not expect to report a material impact on net earnings. Under the new standard, the Company will report cash outflows for repayment of the principal portion of the lease liability as cash flows from financing activities. The interest portion of the lease payments will continue to be classified as cash flows from operating activities. Where the Company, acting as the operator, signs a lease on behalf of a joint operation and assumes the legal liability for that lease, the Company will recognize 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 will be recognized in the consolidated statements of earnings. |
CRITICAL ACCOUNTING ESTIMATES A
CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS | 12 Months Ended |
Dec. 31, 2018 | |
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 engineering data, 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. 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, and changes in the date of abandonment due to changes in reserves life. 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 asset’s 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) 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, 2018 | |
Inventories [Abstract] | |
INVENTORY | INVENTORY 2018 2017 Product inventory $ 297 $ 285 Materials and supplies 658 609 $ 955 $ 894 The Company recorded a write-down of its product inventory of $13 million from cost to net realizable value as at December 31, 2018 ( 2017 - $33 million ). |
EXPLORATION AND EVALUATION ASSE
EXPLORATION AND EVALUATION ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
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, 2016 $ 2,306 $ — $ 76 $ — $ 2,382 Additions 144 — 15 — 159 Acquisition of AOSP and other assets (note 8) 31 — — 259 290 Transfers to property, plant and equipment (198 ) — — — (198 ) Disposals/derecognitions (1 ) — — — (1 ) At December 31, 2017 2,282 — 91 259 2,632 Additions 245 — 35 222 502 Transfers to property, plant and equipment (175 ) — — (222 ) (397 ) Disposals/derecognitions and other (4 ) — (89 ) (7 ) (100 ) At December 31, 2018 $ 2,348 $ — $ 37 $ 252 $ 2,637 During the year ended December 31, 2018, the Company acquired a number of exploration and evaluation properties in the Oil Sands Mining and Upgrading and North America Exploration and Production segments. In the Oil Sands Mining and Upgrading segment, the Company acquired the Joslyn oil sands project including exploration and evaluation assets of $222 million and associated asset retirement obligations of $4 million . Total consideration of $218 million was comprised of $100 million cash on closing with the remaining balance paid equally over each of the next five years. In the fourth quarter of 2018, following integration of the acquired assets into the Horizon mine plan and determination of proved crude oil reserves, the exploration and evaluation assets were transferred to property, plant and equipment. The above amounts are estimates, and may be subject to change based on the receipt of new information. In the North America Exploration and Production segment, the Company acquired Laricina Energy Ltd., including exploration and evaluation assets of $118 million and property, plant and equipment of $44 million . In addition, the Company also acquired cash of $24 million and deferred income tax assets of $168 million and assumed net working capital liabilities of $18 million , asset retirement obligations of $17 million and notes payable of $48 million . Total purchase consideration was $46 million , resulting in a pre-tax gain of $225 million on the acquisition, representing the excess of the fair value of the net assets acquired compared to total purchase consideration. The Company settled the notes payable immediately following the completion of the acquisition. The transaction was accounted for using the acquisition method of accounting. The above amounts are estimates, and may be subject to change based on the receipt of new information. The Company also completed two additional farm-out agreements in the Offshore Africa segment to dispose of a combined 30% interest in its exploration right in South Africa, comprised of exploration and evaluation assets of $89 million , including a recovery of $14 million of past incurred costs, for net proceeds of $105 million ( US$79 million ), resulting in a pre-tax gain of $16 million ( $12 million after-tax). The Company retains a 20% working interest in the exploration right following the completion of these farm-out agreements. Under the terms of the various agreements, in the event of a commercial crude oil discovery on the exploration right and conversion to a production right, additional cash payments of between US$623 million and US$645 million will be made to the Company. In the event of a commercial natural gas discovery on the exploration right and conversion to a production right, additional cash payments of between US$126 million and US$132 million will be made to the Company . During 2017, the Company also disposed of a number of North America exploration and evaluation assets with a net book value of $1 million for consideration of $36 million , resulting in a pre-tax gain on sale of properties of $35 million . |
PROPERTY, PLANT AND EQUIPMENT
PROPERTY, PLANT AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2018 | |
Property, plant and equipment [abstract] | |
PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT Exploration and Production Oil Sands Mining and Upgrading Midstream Head Office Total North America North Sea Offshore Africa Cost At December 31, 2016 $ 61,647 $ 7,380 $ 5,132 $ 27,038 $ 234 $ 395 $ 101,826 Additions (1) 3,003 255 101 1,660 194 19 5,232 Acquisition of AOSP and other assets (note 8) 349 — — 13,832 — — 14,181 Transfers from E&E assets 198 — — — — — 198 Disposals/derecognitions (381 ) — — (446 ) — — (827 ) Foreign exchange adjustments and other — (509 ) (352 ) — — — (861 ) At December 31, 2017 64,816 7,126 4,881 42,084 428 414 119,749 Additions (2) 2,428 237 212 1,050 13 21 3,961 Transfers from E&E assets 175 — — 222 — — 397 Disposals/derecognitions (412 ) (703 ) (70 ) (209 ) — — (1,394 ) Foreign exchange adjustments and other — 661 448 — — — 1,109 At December 31, 2018 $ 67,007 $ 7,321 $ 5,471 $ 43,147 $ 441 $ 435 $ 123,822 Accumulated depletion and depreciation At December 31, 2016 $ 38,311 $ 5,584 $ 3,797 $ 2,828 $ 115 $ 281 $ 50,916 Expense 3,220 509 205 1,220 9 23 5,186 Disposals/derecognitions (381 ) — — (446 ) — — (827 ) Foreign exchange adjustments and other 1 (440 ) (283 ) 26 — — (696 ) At December 31, 2017 41,151 5,653 3,719 3,628 124 304 54,579 Expense 3,111 257 201 1,557 14 21 5,161 Disposals/derecognitions (393 ) (703 ) (70 ) (209 ) — — (1,375 ) Foreign exchange adjustments and other 12 528 353 5 — — 898 At December 31, 2018 $ 43,881 $ 5,735 $ 4,203 $ 4,981 $ 138 $ 325 $ 59,263 Net book value - at December 31, 2018 $ 23,126 $ 1,586 $ 1,268 $ 38,166 $ 303 $ 110 $ 64,559 - at December 31, 2017 $ 23,665 $ 1,473 $ 1,162 $ 38,456 $ 304 $ 110 $ 65,170 (1) Additions in Midstream include a pre-tax revaluation gain of $114 million of a previously held joint interest in certain pipeline system assets. (2) Additions in North Sea include a pre-tax revaluation gain of $19 million relating to acquisitions of its previously held interest. Project costs not subject to depletion and depreciation 2018 2017 Kirby Thermal Oil Sands – North $ 1,424 $ 944 During the year ended December 31, 2018 , the Company acquired a number of producing crude oil and natural gas properties in the North America and North Sea Exploration and Production segments. These transactions were accounted for 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 total purchase consideration. In North America Exploration and Production, excluding the impact of acquisitions disclosed in note 6, the Company acquired property, plant and equipment for net cash consideration paid of $170 million and assumed associated asset retirement obligations of $13 million . No net deferred income tax liabilities were recognized. The Company recognized a pre-tax gain of $47 million on the transactions. In connection with the acquisition of the remaining interest in certain operations in the North Sea Exploration and Production segment, the Company acquired $108 million of property, plant and equipment, for net proceeds received of $73 million . The Company also acquired net working capital of $7 million , assumed associated asset retirement obligations of $41 million and recognized net deferred income tax liabilities of $27 million . The Company recognized a pre-tax gain of $120 million on the acquisition and a pre-tax revaluation gain of $19 million relating to its previously held interest. During the fourth quarter of 2018, the Gabonese Republic agreed to cessation of production from the Company’s Olowi field, as well as the terms of termination of the Olowi Production Sharing Contract and the return of the permit area back to the Gabonese Republic, including the associated asset retirement obligations of $69 million . The transaction resulted in a pre-tax gain on disposition of property of $20 million ( $14 million after-tax). During 2017, the Company acquired a number of other producing crude oil and natural gas properties in the North America Exploration and Production segment, including exploration and evaluation assets of $27 million ( 2016 - $ nil ), for net cash consideration of $1,013 million ( 2016 – $159 million ). These transactions were accounted for using the acquisition method of accounting. In connection with these acquisitions, the Company assumed associated asset retirement obligations of $63 million ( 2016 – $30 million ). No net deferred income tax liabilities were recognized on these acquisitions (2016 - $nil ). In connection with the acquisition of pipeline system assets in the Midstream segment in 2017, the Company recognized a pre-tax revaluatio n gain o f $114 million ( $83 million after-tax) related to a previously held joint interest in the pipeline. As at December 31, 2018 , the Company assessed the recoverability of its property, plant and equipment and its exploration and evaluation assets, and determined the carrying amounts to be recoverable. The Company capitalizes construction period interest for qualifying assets based on costs incurred and the Company’s cost of borrowing. Interest capitalization to a qualifying asset ceases once the asset is substantially available for its intended use. During 2018 , pre-tax interest of $69 million ( 2017 – $ 82 million ; 2016 – $233 million ) was capitalized to property, plant and equipment using a weighted average capitalization rate of 3.9% ( 2017 – 3.8% ; 2016 – 3.9% ). |
ACQUISITION OF INTERESTS IN THE
ACQUISITION OF INTERESTS IN THE ATHABASCA OIL SANDS PROJECT AND OTHER ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations1 [Abstract] | |
ACQUISITION OF INTERESTS IN THE ATHABASCA OIL SANDS PROJECT AND OTHER ASSETS | ACQUISITION OF INTERESTS IN THE ATHABASCA OIL SANDS PROJECT AND OTHER ASSETS On May 31, 2017, the Company completed the acquisition of a direct and indirect 70% interest in AOSP from Shell Canada Limited and certain subsidiaries (“Shell”) and an affiliate of Marathon Oil Corporation (“Marathon"), including a 70% interest in the mining and extraction operations north of Fort McMurray, Alberta, 70% of the Scotford Upgrader and Quest Carbon Capture and Storage ("CCS") project, and a 100% working interest in the Peace River thermal in situ operations and Cliffdale heavy oil field, as well as other oil sands leases. The Company also assumed certain pipeline and other commitments (see note 20). The Company consolidates its direct and indirect interest in the assets, liabilities, revenue and expenses of AOSP and other assets in proportion to the Company’s interests. Total purchase consideration of $12,541 million was comprised of cash payments of $8,217 million , approximately 97.6 million common shares of the Company issued to Shell with a fair value of approximately $3,818 million , and deferred purchase consideration of $506 million (US $375 million ) paid to Marathon in March 2018. The fair value of the Company's common shares was determined using the market price of the shares as at the acquisition date. In connection with the acquisition of AOSP and other assets, the Company arranged acquisition financing of $1.8 billion of medium-term notes in Canada, US$3 billion of long-term notes in the United States and a $3 billion non-revolving term loan facility (see note 11). The acquisition has been accounted for as a business combination using the acquisition method of accounting. The allocation of the purchase price was based on management's best estimates of the fair value of the assets and liabilities acquired as at the acquisition date. The following provides a summary of the net assets acquired and (liabilities) assumed relating to the acquisition: Cash $ 93 Other working capital 291 Property, plant and equipment 14,181 Exploration and evaluation assets 290 Asset retirement obligations (721 ) Other long-term liabilities (73 ) Deferred income taxes (1,287 ) Net assets acquired $ 12,774 Total purchase consideration 12,541 Gain on acquisition before transaction costs $ 233 For the year ended December 31, 2017 , the Company recognized a gain of $230 million , net of transaction costs of $3 million , representing the excess of the fair value of the net assets acquired compared to total purchase consideration. |
INVESTMENTS
INVESTMENTS | 12 Months Ended |
Dec. 31, 2018 | |
Financial Instruments [Abstract] | |
INVESTMENTS | INVESTMENTS As at December 31, 2018 and 2017 , the Company had the following investments: 2018 2017 Investment in PrairieSky Royalty Ltd. $ 400 $ 726 Investment in Inter Pipeline Ltd. 124 167 $ 524 $ 893 Investment in PrairieSky Royalty Ltd. The Company’s investment of 22.6 million common shares does not constitute significant influence, and is accounted for at fair value through profit or loss, remeasured at each reporting date. As at December 31, 2018 , the Company’s investment in PrairieSky Ltd. ("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 loss (gain) from the investment in PrairieSky was comprised as follows: 2018 2017 2016 Fair value loss (gain) from PrairieSky $ 326 $ (3 ) $ (292 ) Dividend income from PrairieSky (17 ) (17 ) (27 ) $ 309 $ (20 ) $ (319 ) Investment in Inter Pipeline Ltd. During 2016, as partial consideration for the disposal of the Company's interest in the Cold Lake Pipeline, the Company received non-cash share consideration of $190 million , comprised of approximately 6.4 million common shares of Inter Pipeline at $29.57 per common share determined as of the closing date. Inter Pipeline is in the business of petroleum transportation, natural gas liquids processing, and bulk liquid storage in Western Canada and Europe. The Company's investment of 6.4 million common shares of Inter Pipeline does not constitute significant influence, and is accounted for at fair value through profit or loss, remeasured at each reporting date. As at December 31, 2018 , the Company's investment in Inter Pipeline was classified as a current asset. The loss (gain) from the investment in Inter Pipeline was comprised as follows: 2018 2017 2016 Fair value loss from Inter Pipeline $ 43 $ 23 $ — Dividend income from Inter Pipeline (11 ) (10 ) (1 ) $ 32 $ 13 $ (1 ) |
OTHER LONG-TERM ASSETS
OTHER LONG-TERM ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
Subclassifications of assets, liabilities and equities [abstract] | |
OTHER LONG-TERM ASSETS | OTHER LONG-TERM ASSETS 2018 2017 Investment in North West Redwater Partnership $ 287 $ 292 North West Redwater Partnership subordinated debt (1) 591 510 Risk management (note 19) 373 204 Other 208 241 1,459 1,247 Less: current portion 116 79 $ 1,343 $ 1,168 (1) Includes accrued interest. Investment in North West Redwater Partnership The Company's 50% interest in Redwater Partnership is accounted for using the equity method based on Redwater Partnership’s voting and decision-making structure and legal form. Redwater Partnership has entered into agreements to construct and operate a 50,000 barrel per day bitumen upgrader and refinery (the "Project") under processing agreements that target to process 12,500 barrels per day of bitumen feedstock for the Company and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, under a 30 year fee-for-service tolling agreement. The facility capital cost ("FCC") budget for the Project is currently estimated to be $9,700 million . The Project is currently in the commissioning phase. During 2013 , the Company and APMC agreed, each with a 50% interest, to provide subordinated debt, bearing interest at prime plus 6% , as required for Project costs to reflect an agreed debt to equity ratio of 80/20. To December 31, 2018 , each party has provided $439 million of subordinated debt, together with accrued interest thereon of $152 million , for a Company total of $591 million . Any additional subordinated debt financing is not expected to be significant. Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service toll, currently consisting of interest and fees, with principal repayments beginning in 2020 (see note 20). The Company is unconditionally obligated to pay this portion of the cost of service toll over the 30 -year tolling period. As at December 31, 2018, the Company had recognized $62 million in prepaid service tolls. As at December 31, 2018 , Redwater Partnership had borrowings of $2,333 million under its secured $3,500 million syndicated credit facility, maturing June 2018. During the first quarter of 2018, Redwater Partnership extended $2,000 million of the $3,500 million revolving syndicated credit facility to June 2021. The remaining $1,500 million was extended on a fully drawn non-revolving basis maturing February 2020. During 2017 , Redwater Partnership issued $750 million of 2.80% series J senior secured bonds due June 2027 and $750 million of 3.65% series K senior secured bonds due June 2035 . The assets, liabilities, partners’ equity and equity loss (income) related to Redwater Partnership and the Company’s 50% interest at December 31, 2018 and 2017 were comprised as follows: 2018 2017 Redwater Partnership Company Redwater Partnership Company Current assets $ 210 $ 105 $ 330 $ 165 Non-current assets $ 11,250 $ 5,625 $ 10,540 $ 5,270 Current liabilities $ 352 $ 176 $ 2,476 $ 1,238 Non-current liabilities $ 10,534 $ 5,267 $ 7,810 $ 3,905 Partners’ equity $ 574 $ 287 $ 584 $ 292 Equity loss (income) $ 10 $ 5 $ (62 ) $ (31 ) |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2018 | |
Financial Instruments [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT 2018 2017 Canadian dollar denominated debt, unsecured Bank credit facilities $ 831 $ 3,544 Medium-term notes 3.05% debentures due June 19, 2019 500 500 2.60% debentures due December 3, 2019 500 500 2.05% debentures due June 1, 2020 900 900 2.89% debentures due August 14, 2020 1,000 1,000 3.31% debentures due February 11, 2022 1,000 1,000 3.55% debentures due June 3, 2024 500 500 3.42% debentures due December 1, 2026 600 600 4.85% debentures due May 30, 2047 300 300 6,131 8,844 US dollar denominated debt, unsecured Bank credit facilities (December 31, 2018 - US$2,954 million; 4,031 2,300 Commercial paper (December 31, 2018 - US$104 million; December 31, 2017 - US$500 million) 141 625 US dollar debt securities 1.75% due January 15, 2018 (US$600 million) — 751 5.90% due February 1, 2018 (US$400 million) — 501 3.45% due November 15, 2021 (US$500 million) 682 625 2.95% due January 15, 2023 (US$1,000 million) 1,364 1,252 3.80% due April 15, 2024 (US$500 million) 682 625 3.90% due February 1, 2025 (US$600 million) 819 751 3.85% due June 1, 2027 (US$1,250 million) 1,706 1,566 7.20% due January 15, 2032 (US$400 million) 546 501 6.45% due June 30, 2033 (US$350 million) 478 438 5.85% due February 1, 2035 (US$350 million) 478 438 6.50% due February 15, 2037 (US$450 million) 614 563 6.25% due March 15, 2038 (US$1,100 million) 1,501 1,377 6.75% due February 1, 2039 (US$400 million) 546 501 4.95% due June 1, 2047 (US$750 million) 1,023 939 14,611 13,753 Long-term debt before transaction costs and original issue discounts, net 20,742 22,597 Less: original issue discounts, net (1) 17 18 transaction costs (1) (2) 102 121 20,623 22,458 Less: current portion of commercial paper 141 625 current portion of other long-term debt (1) (2) 1,000 1,252 $ 19,482 $ 20,581 (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, 2018 , the Company had in place revolving bank credit facilities of $4,976 million of which $4,723 million was available for use. Additionally, the Company had in place fully drawn term credit facilities of $4,750 million . Details of these facilities are described below. This excludes certain other dedicated credit facilities supporting letters of credit. • a $100 million demand credit facility; • a $ 1,800 million non-revolving term credit facility maturing May 2020 ; • a $2,200 million non-revolving term credit facility maturing October 2020 ; • a $750 million non-revolving term credit facility maturing February 2021 ; • a $ 2,425 million revolving syndicated credit facility with $330 million maturing in June 2019 and $2,095 million maturing June 2021 ; • a $ 2,425 million revolving syndicated credit facility maturing June 2022 ; and • a £15 million demand credit facility related to the Company’s North Sea operations. During 2018 , the Company extended the $2,425 million revolving syndicated credit facility originally due June 2020 to June 2022 . Each of the $2,425 million revolving facilities is extendible annually at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal is repayable on the maturity date. Borrowings under these facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate. During 2018 , the Company repaid and cancelled $1,200 million of the $3,000 million non-revolving term credit facility ( third quarter of 2018 – $1,050 million ; first quarter of 2018 – $150 million ) scheduled to mature in May 2020 . The required annual amortization of 5% of the original balance is now satisfied. Borrowings under the term loan facility may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate. As at December 31, 2018 , the $1,800 million facility was fully drawn. During 2018, the Company extended the $2,200 million non-revolving credit facility originally due October 2019 to October 2020 . Borrowings under the $2,200 million non-revolving credit facility may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate. As at December 31, 2018 , the $2,200 million facility was fully drawn. During 2018 , the Company repaid and cancelled the $125 million non-revolving term credit facility scheduled to mature in February 2019 . The Company also extended the $750 million non-revolving term credit facility originally due February 2019 to February 2021 . Borrowings under the $750 million non-revolving credit facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances, US dollar bankers' acceptances, LIBOR, US base rate or Canadian prime rate. As at December 31, 2018 , the $750 million facility was fully drawn. 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 bank credit facilities for amounts outstanding under this program. The Company’s weighted average interest rate on bank credit facilities and commercial paper outstanding as at December 31, 2018 was 2.6% ( December 31, 2017 – 2.2% ), and on total long-term debt outstanding for the year ended December 31, 2018 was 3.9% ( December 31, 2017 – 3.8% ). As at December 31, 2018 , letters of credit and guarantees aggregating to $450 million were outstanding. Medium-Term Notes During 2017 , the Company issued $900 million of 2.05% medium-term notes due June 2020 , $600 million of 3.42% medium-term notes due December 2026 and $300 million of 4.85% medium-term notes due May 2047 . Proceeds from the securities were used to finance the acquisition of AOSP and other assets. In July 2017 , the Company filed a new 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 2019 . 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. US Dollar Debt Securities During 2018 , the Company repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes. During 2017 , the Company repaid US$1,100 million of 5.70% notes, and issued US$1,000 million of 2.95% notes due January 2023 , US$1,250 million of 3.85% notes due June 2027 and US$750 million of 4.95% notes due June 2047 . Proceeds from the debt securities were used to finance the acquisition of AOSP and other assets. In July 2017 , the Company filed a new 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 2019 . 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. Scheduled Debt Repayments Scheduled debt repayments are as follows: Year Repayment 2019 $ 1,141 2020 $ 5,996 2021 $ 1,444 2022 $ 1,003 2023 $ 1,365 Thereafter $ 9,793 |
OTHER LONG-TERM LIABILITIES
OTHER LONG-TERM LIABILITIES | 12 Months Ended |
Dec. 31, 2018 | |
Subclassifications of assets, liabilities and equities [abstract] | |
OTHER LONG-TERM LIABILITIES | OTHER LONG-TERM LIABILITIES 2018 2017 Asset retirement obligations $ 3,886 $ 4,327 Share-based compensation 124 414 Risk management (note 19) 17 103 Deferred purchase consideration (1) (2) 118 469 Other 80 96 4,225 5,409 Less: current portion 335 1,012 $ 3,890 $ 4,397 (1) Includes $118 million of deferred purchase consideration at December 31, 2018, payable in annual installments of $25 million over the next five years. (2) Includes $469 million ( US$375 million ) of deferred purchase consideration at December 31, 2017, paid to Marathon in March 2018. 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 have been discounted using a weighted average discount rate of 5.0% ( 2017 – 4.7% ; 2016 – 5.2% ) and inflation rates of up to 2% (December 31, 2017 - up to 2% ). Reconciliations of the discounted asset retirement obligations were as follows: 2018 2017 2016 Balance – beginning of year $ 4,327 $ 3,243 $ 2,950 Liabilities incurred 19 12 3 Liabilities acquired, net 6 784 30 Liabilities settled (290 ) (274 ) (267 ) Asset retirement obligation accretion 186 164 142 Revision of cost, inflation rates and timing estimates (111 ) (40 ) (68 ) Change in discount rate (334 ) 509 493 Foreign exchange adjustments 83 (71 ) (40 ) Balance – end of year 3,886 4,327 3,243 Less: current portion 186 92 95 $ 3,700 $ 4,235 $ 3,148 Segmented Asset Retirement Obligations 2018 2017 Exploration and Production North America $ 1,665 $ 1,840 North Sea 707 755 Offshore Africa 134 245 Oil Sands Mining and Upgrading 1,379 1,486 Midstream 1 1 $ 3,886 $ 4,327 Share-Based Compensation As 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, a liability for potential cash settlements is recognized. The current portion represents the maximum amount of the liability payable within the next twelve month period if all vested stock options are surrendered for cash settlement. 2018 2017 2016 Balance – beginning of year $ 414 $ 426 $ 128 Share-based compensation (recovery) expense (146 ) 134 355 Cash payment for stock options surrendered (5 ) (6 ) (7 ) Transferred to common shares (120 ) (154 ) (117 ) (Recovered from) charged to Oil Sands Mining and Upgrading, net (19 ) 14 67 Balance – end of year 124 414 426 Less: current portion 92 348 368 $ 32 $ 66 $ 58 Included within share-based compensation liability as at December 31, 2018 was $13 million ( 2017 – $5 million ; 2016 – $nil ) related to performance share units 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: 2018 2017 2016 Fair value $ 3.33 $ 11.82 $ 11.41 Share price $ 32.94 $ 44.92 $ 42.79 Expected volatility 27.4% 27.1% 30.7% Expected dividend yield 4.1% 2.5% 2.3% Risk free interest rate 1.9% 1.8% 0.9% Expected forfeiture rate 4.2% 5.0% 5.0% Expected stock option life (1) 4.4 years 4.5 years 4.6 years (1) At original time of grant. The intrinsic value of vested stock options at December 31, 2018 was $27 million ( 2017 – $195 million ; 2016 – $191 million ). |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2018 | |
Income Taxes [Abstract] | |
INCOME TAXES | INCOME TAXES The provision for income tax was as follows: Expense (recovery) 2018 2017 2016 Current corporate income tax – North America $ 312 $ (145 ) $ (377 ) Current corporate income tax – North Sea 28 57 (74 ) Current corporate income tax – Offshore Africa 54 45 22 Current PRT (1) – North Sea (29 ) (132 ) (198 ) Other taxes 9 11 9 Current income tax 374 (164 ) (618 ) Deferred corporate income tax 540 586 (106 ) Deferred PRT (1) – North Sea 17 54 (135 ) Deferred income tax 557 640 (241 ) Income tax $ 931 $ 476 $ (859 ) (1) Petroleum Revenue Tax. 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 (loss) before taxes. The reasons for the difference are as follows: 2018 2017 2016 Canadian statutory income tax rate 27.0% 27.0% 27.0% Income tax provision at statutory rate $ 951 $ 776 $ (287 ) Effect on income taxes of: UK PRT and other taxes (3 ) (67 ) (324 ) Impact of deductible UK PRT and other taxes on corporate income tax 3 28 131 Foreign and domestic tax rate differentials 6 (43 ) (54 ) Non-taxable portion of capital gains/losses 142 (86 ) (80 ) Stock options exercised for common shares (41 ) 33 94 Income tax rate and other legislative changes — 10 (107 ) Non-taxable gain on corporate acquisitions (119 ) (63 ) — Revisions arising from prior year tax filings (136 ) (3 ) (120 ) Change in unrecognized capital loss carryforward asset 142 (86 ) (80 ) Other (14 ) (23 ) (32 ) Income tax expense (recovery) $ 931 $ 476 $ (859 ) The following table summarizes the temporary differences that give rise to the net deferred income tax liability: 2018 2017 Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets $ 12,885 $ 12,484 Unrealized risk management activities 33 20 PRT deduction for corporate income tax 1 7 Investments 46 96 Investment in North West Redwater Partnership 414 252 Other 174 — 13,553 12,859 Deferred income tax assets Asset retirement obligations (1,142 ) (1,264 ) Loss carryforwards (855 ) (523 ) Unrealized foreign exchange loss on long-term debt (104 ) (29 ) Deferred PRT (1 ) (18 ) Other — (50 ) (2,102 ) (1,884 ) Net deferred income tax liability $ 11,451 $ 10,975 Movements in deferred tax assets and liabilities recognized in net earnings (loss) during the year were as follows: 2018 2017 2016 Property, plant and equipment and exploration and evaluation assets $ 281 $ 541 $ 37 Timing of partnership items — — (261 ) Unrealized foreign exchange (gain) loss on long-term debt (75 ) 120 63 Unrealized risk management activities 18 (46 ) (44 ) Asset retirement obligations 175 (88 ) (20 ) Loss carryforwards (61 ) 48 (221 ) Investments (50 ) (2 ) 38 Investment in North West Redwater Partnership 162 30 81 Deferred PRT 17 54 (135 ) PRT deduction for corporate income tax (7 ) (21 ) 61 Other 97 4 160 $ 557 $ 640 $ (241 ) The following table summarizes the movements of the net deferred income tax liability during the year: 2018 2017 2016 Balance – beginning of year $ 10,975 $ 9,073 $ 9,344 Deferred income tax expense (recovery) 557 640 (241 ) Deferred income tax (recovery) expense included in other comprehensive income (6 ) 4 (5 ) Foreign exchange adjustments 41 (29 ) (25 ) Business combinations (note 6,7,8) (116 ) 1,287 — Balance – end of year $ 11,451 $ 10,975 $ 9,073 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. During 2017, the British Columbia government enacted legislation that increased the provincial corporate income tax rate from 11% to 12% effective January 1, 2018. As a result of this income tax rate increase, the Company's deferred corporate income tax liability was increased by $10 million . During 2016 , the UK government enacted legislation to reduce the supplementary charge on oil and gas profits from 20% to 10% effective January 1, 2016 , resulting in a decrease in the Company's deferred corporate income tax liability of $107 million . In addition, the UK government also enacted legislation to reduce the PRT rate from 35% to 0% effective January 1, 2016 . Allowable abandonment expenditures eligible for carryback to 2015 and prior taxation years for PRT purposes are still recoverable at a PRT rate of 50% . As a result of these tax changes, the Company’s deferred PRT liability was reduced by $228 million and the deferred corporate income tax liability was increased by $114 million . 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. 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 $750 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, 2018 | |
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. 2018 2017 Issued Common shares Number of shares (thousands) Amount Number of shares Amount Balance – beginning of year 1,222,769 $ 9,109 1,110,952 $ 4,671 Issued for the acquisition of AOSP and other assets (note 8) — — 97,561 3,818 Issued upon exercise of stock options 9,975 332 14,256 466 Previously recognized liability on stock options exercised for common shares — 120 — 154 Purchase of common shares under Normal Course Issuer Bid (30,858 ) (238 ) — — Balance – end of year 1,201,886 $ 9,323 1,222,769 $ 9,109 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. Dividend Policy 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 March 6, 2019, the Board of Directors declared a quarterly dividend of $0.375 per common share, an increase from the previous quarterly dividend of $0.335 per common share. The dividend is payable on April 1, 2019. On February 28, 2018, the Board of Directors declared a quarterly dividend of $0.335 per common share, an increase from the previous quarterly dividend of $0.275 per common share. The dividend is payable on April 1, 2018. On March 1, 2017 , the Board of Directors declared a quarterly dividend of $0.275 per common share, beginning with the dividend payable on April 1, 2017 . On November 2, 2016 , the Board of Directors declared a quarterly dividend of $0.25 per common share, beginning with the dividend payable on January 1, 2017 . On March 2, 2016 , the Board of Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2016 . Normal Course Issuer Bid On May 16, 2018, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange, alternative Canadian trading platforms, and the New York Stock Exchange, up to 61,454,856 common shares, over a 12 -month period commencing May 23, 2018 and ending May 22, 2019. The Company's Normal Course Issuer Bid announced in March 2017 expired on May 22, 2018. For the year ended December 31, 2018 , the Company purchased 30,857,727 common shares at a weighted average price of $41.56 per common share for a total cost of $1,282 million . Retained earnings were reduced by $1,044 million , representing the excess of the purchase price of common shares over their average carrying value. During 2017 and 2016, the Company did not purchase any common shares for cancellation. Subsequent to December 31, 2018 , the Company purchased 4,340,000 common shares at a weighted average price of $35.86 per common share for a total cost of $156 million . 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 to six years to expiry and vest over a five -year period. The exercise price of each stock option granted is determined at the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the grant. Each stock option granted provides the holder the choice to purchase one common share of the Company at the stated exercise price or receive a cash payment equal to the difference between the stated exercise price and the market price of the Company’s common shares on the date of surrender of the stock option. The Option Plan is a "rolling 9% " plan, whereby the aggregate number of common shares that may be reserved for issuance under the plan shall not exceed 9% of the common shares outstanding from time to time. The following table summarizes information relating to stock options outstanding at December 31, 2018 and 2017 : 2018 2017 Stock options (thousands) Weighted average exercise price Stock options (thousands) Weighted Outstanding – beginning of year 56,036 $ 36.67 58,299 $ 34.22 Granted 4,256 $ 43.75 16,052 $ 42.07 Surrendered for cash settlement (392 ) $ 33.46 (626 ) $ 33.18 Exercised for common shares (9,975 ) $ 33.28 (14,256 ) $ 32.66 Forfeited (3,240 ) $ 38.76 (3,433 ) $ 37.53 Outstanding – end of year 46,685 $ 37.92 56,036 $ 36.67 Exercisable – end of year 19,436 $ 36.03 18,282 $ 34.25 The range of exercise prices of stock options outstanding and exercisable at December 31, 2018 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 $22.90 - $24.99 3,120 2.04 $ 22.90 1,515 $ 22.90 $25.00 - $29.99 5,112 2.02 $ 28.86 2,453 $ 28.87 $30.00 - $34.99 6,013 0.83 $ 33.27 4,831 $ 33.43 $35.00 - $39.99 11,304 2.72 $ 37.46 4,131 $ 35.91 $40.00 - $44.99 17,107 3.23 $ 43.59 5,664 $ 43.60 $45.00 - $46.74 4,029 4.06 $ 45.20 842 $ 45.08 46,685 2.66 $ 37.92 19,436 $ 36.03 |
ACCUMULATED OTHER COMPREHENSIVE
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | 12 Months Ended |
Dec. 31, 2018 | |
Analysis Of Other Comprehensive Income By Item [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The components of accumulated other comprehensive income (loss), net of taxes, were as follows: 2018 2017 Derivative financial instruments designated as cash flow hedges $ 13 $ 47 Foreign currency translation adjustment 109 (115 ) $ 122 $ (68 ) |
CAPITAL DISCLOSURES
CAPITAL DISCLOSURES | 12 Months Ended |
Dec. 31, 2018 | |
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 to 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 arithmetic ratio of net current and long-term debt divided by the sum of the carrying value of shareholders’ equity plus net current and long-term debt. The Company’s internal targeted range for its debt to book capitalization ratio is 25% to 45% . This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may be below the low end of the targeted range when cash flow from operating activities is greater than current investment activities. At December 31, 2018 , the ratio was within the target range at 39% . 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. 2018 2017 Long-term debt, net (1) $ 20,522 $ 22,321 Total shareholders’ equity $ 31,974 $ 31,653 Debt to book capitalization 39% 41% (1) Includes the current portion of long-term debt, net of cash and cash equivalents. 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, 2018, the Company was in compliance with this covenant. |
NET EARNINGS (LOSS) PER COMMON
NET EARNINGS (LOSS) PER COMMON SHARE | 12 Months Ended |
Dec. 31, 2018 | |
Earnings per share [abstract] | |
NET EARNINGS (LOSS) PER COMMON SHARE | NET EARNINGS (LOSS) PER COMMON SHARE 2018 2017 2016 Weighted average common shares outstanding – basic (thousands of shares) 1,218,798 1,175,094 1,100,471 Effect of dilutive stock options (thousands of shares) 4,960 7,729 — Weighted average common shares outstanding – diluted (thousands of shares) 1,223,758 1,182,823 1,100,471 Net earnings (loss) $ 2,591 $ 2,397 $ (204 ) Net earnings (loss) per common share – basic $ 2.13 $ 2.04 $ (0.19 ) – diluted $ 2.12 $ 2.03 $ (0.19 ) In 2018 , the Company excluded 23,458,000 potentially anti-dilutive stock options from the calculation of diluted earnings per common share (year ended December 31, 2017 - 17,547,000 ). |
INTEREST AND OTHER FINANCING EX
INTEREST AND OTHER FINANCING EXPENSE | 12 Months Ended |
Dec. 31, 2018 | |
Borrowing costs [abstract] | |
INTEREST AND OTHER FINANCING EXPENSE | INTEREST AND OTHER FINANCING EXPENSE 2018 2017 2016 Interest and other financing expense: Long-term debt $ 867 $ 810 $ 664 Less: amounts capitalized on qualifying assets 69 82 233 Total interest and other financing expense 798 728 431 Total interest income (59 ) (97 ) (48 ) Net interest and other financing expense $ 739 $ 631 $ 383 |
FINANCIAL INSTRUMENTS
FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2018 | |
Financial Instruments [Abstract] | |
FINANCIAL INSTRUMENTS | FINANCIAL INSTRUMENTS The carrying amounts of the Company’s financial instruments by category were as follows: 2018 Asset (liability) Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost Total Accounts receivable $ 1,148 $ — $ — $ — $ 1,148 Investments — 524 — — 524 Other long-term assets 591 12 361 — 964 Accounts payable — — — (779 ) (779 ) Accrued liabilities — — — (2,356 ) (2,356 ) Other long-term liabilities (1) — (17 ) — (118 ) (135 ) Long-term debt (2) — — — (20,623 ) (20,623 ) $ 1,739 $ 519 $ 361 $ (23,876 ) $ (21,257 ) 2017 Asset (liability) Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost Total Accounts receivable $ 2,397 $ — $ — $ — $ 2,397 Investments — 893 — — 893 Other long-term assets 510 — 204 — 714 Accounts payable — — — (775 ) (775 ) Accrued liabilities — — — (2,597 ) (2,597 ) Other long-term liabilities (3) — (38 ) (65 ) (469 ) (572 ) Long-term debt (2) — — — (22,458 ) (22,458 ) $ 2,907 $ 855 $ 139 $ (26,299 ) $ (22,398 ) (1) Includes $ 118 million of deferred purchase consideration payable over the next five years. (2) Includes the current portion of long-term debt. (3) Includes $469 million ( US$375 million ) of deferred purchase consideration which was paid to Marathon in March 2018. The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt. The fair values of the Company’s investments, recurring other long-term assets (liabilities) and fixed rate long-term debt are outlined below: 2018 Carrying amount Fair value Asset (liability) (1) (2) Level 1 Level 2 Level 3 (4) (5) Investments (3) $ 524 $ 524 $ — $ — Other long-term assets $ 964 $ — $ 373 $ 591 Other long-term liabilities $ (135 ) $ — $ (17 ) $ (118 ) Fixed rate long-term debt (6) (7) $ (15,620 ) $ (15,952 ) $ — $ — 2017 Carrying amount Fair value Asset (liability) (1) (2) Level 1 Level 2 Level 3 (5) Investments (3) $ 893 $ 893 $ — $ — Other long-term assets $ 714 $ — $ 204 $ 510 Other long-term liabilities $ (103 ) $ — $ (103 ) $ — Fixed rate long-term debt (6) (7) $ (15,989 ) $ (17,259 ) $ — $ — (1) Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and purchase consideration paid to Marathon in March 2018). (2) There were no transfers between Level 1, 2 and 3 financial instruments. (3) The fair values of the investments are based on quoted market prices. (4) The fair value of the deferred purchase consideration is based on the present value of future cash payments. (5) The fair value of Redwater Partnership subordinated debt is based on the present value of future cash receipts. (6) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (7) 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) 2018 2017 Derivatives held for trading Foreign currency forward contracts $ 8 $ (38 ) Crude oil WCS (1) differential swaps (17 ) — Natural gas AECO basis swaps 1 — Natural gas AECO fixed price swaps 3 — Cash flow hedges Foreign currency forward contracts 70 (71 ) Cross currency swaps 291 210 $ 356 $ 101 Included within: Current portion of other long-term assets $ 92 $ — Current portion of other long-term liabilities (17 ) (103 ) Other long-term assets 281 204 $ 356 $ 101 (1) Western Canadian Select. During 2018 , the Company recognized a gain of $2 million ( 2017 – gain of $5 million , 2016 – gain of $7 million ) related to ineffectiveness arising from cash flow hedges. The estimated fair value of derivative financial instruments in Level 2 at each measurement date have been determined based on appropriate internal valuation methodologies and/or third party indications. Level 2 fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows and discount rates. In determining these assumptions, the Company primarily relied on external, readily-observable quoted market inputs as applicable, including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and United States foreign exchange rates, discounted to present value as appropriate . The resulting fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction and these differences may be material. The changes in estimated fair values of derivative financial instruments included in the risk management asset were recognized in the financial statements as follows: Asset (liability) 2018 2017 Balance – beginning of year $ 101 $ 489 Net change in fair value of outstanding derivative financial instruments recognized in: Risk management activities 35 (37 ) Foreign exchange 260 (375 ) Other comprehensive (loss) income (40 ) 24 Balance – end of year 356 101 Less: current portion 75 (103 ) $ 281 $ 204 Net (gain) loss from risk management activities for the years ended December 31 were as follows: 2018 2017 2016 Net realized risk management (gain) loss $ (99 ) $ (2 ) $ 8 Net unrealized risk management (gain) loss (35 ) 37 25 $ (134 ) $ 35 $ 33 Financial Risk Factors 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. At December 31, 2018 , the Company had the following derivative financial instruments outstanding to manage its commodity price risk: Remaining term Volume Weighted average price Index Crude Oil WCS differential swaps Jan 2019 - Mar 2019 28,000 bbl/d US $ 17.65 WCS WCS differential swaps Jan 2019 - Sep 2019 8,000 bbl/d US $ 23.57 WCS Natural Gas AECO basis swaps Jan 2019 - Mar 2019 10,000 MMbtu/d US $ 1.39 AECO AECO fixed price swaps Jan 2019 - Mar 2019 30,000 GJ/d $ 2.30 AECO AECO fixed price swaps (1) Apr 2019 - Oct 2019 10,000 GJ/d $ 1.30 AECO (1) As at March 6, 2019, the Company has hedged an additional 105,000 GJ/d of currently forecasted natural gas volumes using AECO fixed price swaps, at a weighted average price of $1.32/GJ, for April to October 2019. The Company's outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month. Interest rate risk management The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. Interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At December 31, 2018 , the Company had no interest rate swap contracts outstanding. Foreign currency exchange rate risk management The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-term debt and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. At December 31, 2018 the Company had the following cross currency swap contracts outstanding: Remaining term Amount Exchange rate (US$/C$) Interest rate (US$) Interest rate (C$) Cross currency Swaps Jan 2019 — Nov 2021 US$500 1.022 3.45 % 3.96 % Jan 2019 — Mar 2038 US$550 1.170 6.25 % 5.76 % All cross currency swap derivative financial instruments were designated as hedges at December 31, 2018 and were classified as cash flow hedges. In addition to the cross currency swap contracts noted above, at December 31, 2018 the Company had US$3,506 million of foreign currency forward contracts outstanding, with terms of up to 90 days, including US$3,058 million designated as cash flow hedges. Financial instrument sensitivities The following table summarizes the annualized sensitivities of the Company’s 2018 net earnings and other comprehensive income (loss) to changes in the fair value of financial instruments outstanding as at December 31, 2018 , resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those sensitivities 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. 2018 2017 Increase (decrease) to net earnings Increase (decrease) to other comprehensive income Increase (decrease) to net earnings (Increase) decrease to other comprehensive loss Commodity price risk (1) Increase WCS differential US$1.00/bbl $ (5 ) $ — $ — $ — Decrease WCS differential US$1.00/bbl $ 5 $ — $ — $ — Increase AECO $0.10/Mcf (2) $ (1 ) $ — $ — $ — Decrease AECO $0.10/Mcf (2) $ 1 $ — $ — $ — Interest rate risk Increase interest rate 1% $ (33 ) $ (21 ) $ (42 ) $ (16 ) Decrease interest rate 1% $ 33 $ 25 $ 42 $ 19 Foreign currency exchange rate risk Increase exchange rate by US$0.01 $ (114 ) $ — $ (105 ) $ — Decrease exchange rate by US$0.01 $ 113 $ — $ 101 $ — (1) Based on the Company's contracted AECO basis swap volumes at December 31, 2018, a movement of US$0.10 /Mcf would not have a significant impact on net earnings or other comprehensive income. (2) Movements in AECO are based on the Company's contracted AECO fixed price swap volumes at December 31, 2018. 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, 2018 , 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. 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. At December 31, 2018 , the Company had net risk management assets of $361 million with specific counterparties related to derivative financial instruments ( December 31, 2017 – $187 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 $ 779 $ — $ — $ — Accrued liabilities $ 2,356 $ — $ — $ — Other long-term liabilities $ 42 $ 24 $ 69 $ — Long-term debt (1) (2) $ 1,141 $ 5,996 $ 3,812 $ 9,793 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. (2) In addition to the financial liabilities disclosed above, estimated interest and other financing payments related to long-term debt are as follows: less than one year, $836 million ; one to less than two years, $755 million ; two to less than five years, $1,668 million ; and thereafter, $5,327 million . Interest payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2018 . |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2018 | |
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES The Company has committed to certain payments as follows: 2019 2020 2021 2022 2023 Thereafter Product transportation and pipeline $ 692 $ 664 $ 620 $ 516 $ 381 $ 3,991 North West Redwater Partnership service toll (1) $ 86 $ 126 $ 157 $ 158 $ 157 $ 2,858 Offshore equipment operating leases $ 94 $ 73 $ 75 $ 8 $ — $ — Office leases $ 42 $ 42 $ 39 $ 31 $ 32 $ 89 Other $ 85 $ 35 $ 32 $ 32 $ 31 $ 424 (1) Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service toll, which currently consists of interest and fees, with principal repayments beginning in 2020. Included in the service toll is $1,301 million of interest payable over the 30 year tolling period. See 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, 2018 | |
Statement Of Cash Flows, Additional Disclosures [Abstract] | |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION 2018 2017 2016 Changes in non-cash working capital Accounts receivable $ 1,233 $ (977 ) $ (142 ) Current income tax assets (liabilities) 471 527 (165 ) Inventory (74 ) 81 (79 ) Prepaids and other (3 ) (28 ) 14 Accounts payable (7 ) 175 31 Accrued liabilities (268 ) 365 (116 ) Other long-term liabilities (1) (2) (351 ) 469 — Net changes in non-cash working capital $ 1,001 $ 612 $ (457 ) Relating to: Operating activities $ 1,346 $ 299 $ (542 ) Investing activities (345 ) 313 85 $ 1,001 $ 612 $ (457 ) 2018 2017 2016 Expenditures on exploration and evaluation assets $ 282 $ 159 $ 29 Net proceeds on sale of exploration and evaluation assets (16 ) (35 ) (35 ) Net expenditures (proceeds) on exploration and evaluation assets $ 266 $ 124 $ (6 ) Expenditures on property, plant and equipment $ 4,175 $ 4,574 $ 4,152 Net proceeds on sale of property, plant and equipment (3) — — (349 ) Net expenditures on property, plant and equipment $ 4,175 $ 4,574 $ 3,803 (1) Included in other long-term liabilities at December 31, 2018 is $118 million of deferred purchase consideration payable over the next five years. (2) Included in other long-term liabilities at December 31, 2017 is $469 million ( US$375 million ) of deferred purchase consideration paid to Marathon. (3) Net expenditures on property, plant and equipment in 2016 exclude non-cash share consideration of $190 million received from Inter Pipeline on the disposition of the Company's interest in the Cold Lake Pipeline. The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended December 31, 2018 and 2017: Long-term debt Cash flow hedges on US dollar debt securities Liabilities from financing activities At December 31, 2016 $ 16,805 $ (485 ) $ 16,320 Changes from financing cash flows: Issue of long-term debt, net (1) 6,622 — 6,622 Settlement of hedge instruments, net — 124 124 Changes in foreign exchange and fair value (2) (969 ) 222 (747 ) At December 31, 2017 $ 22,458 $ (139 ) $ 22,319 Changes from financing cash flows: Repayment of long-term debt, net (1) (2,831 ) — (2,831 ) Changes in foreign exchange and fair value (2) 996 (222 ) 774 At December 31, 2018 $ 20,623 $ (361 ) $ 20,262 (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 and the amortization of original issue discounts and premiums and directly attributable transaction costs. |
SEGMENTED INFORMATION
SEGMENTED INFORMATION | 12 Months Ended |
Dec. 31, 2018 | |
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 activities include the Company’s pipeline operations, an electricity co-generation system and Redwater Partnership. 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. North America North Sea Offshore Africa (millions of Canadian dollars) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Segmented product sales Crude oil and NGLs $ 7,254 $ 7,655 $ 5,933 $ 753 $ 666 $ 478 $ 628 $ 579 $ 532 Natural gas 1,256 1,506 1,276 140 118 92 70 53 71 Total segmented product sales 8,510 9,161 7,209 893 784 570 698 632 603 Less: royalties (723 ) (809 ) (524 ) (2 ) (1 ) (1 ) (51 ) (41 ) (26 ) Segmented revenue 7,787 8,352 6,685 891 783 569 647 591 577 Segmented expenses Production 2,405 2,362 2,186 405 400 403 208 226 200 Transportation, blending and feedstock 2,587 2,291 1,941 22 31 48 2 1 2 Depletion, depreciation and amortization 3,132 3,243 3,465 257 509 458 201 205 262 Asset retirement obligation accretion 87 80 66 29 27 35 9 9 12 Realized risk management (commodity derivatives) (10 ) (45 ) 6 — — — — — — Gain on acquisition, disposition and revaluation of properties (277 ) (35 ) (32 ) (139 ) — — (36 ) — — Equity loss (gain) from investments — — — — — — — — — Total segmented expenses 7,924 7,896 7,632 574 967 944 384 441 476 Segmented earnings (loss) before the following $ (137 ) $ 456 $ (947 ) $ 317 $ (184 ) $ (375 ) $ 263 $ 150 $ 101 Non–segmented expenses Administration Share-based compensation Interest and other financing expense Risk management activities (other) Foreign exchange loss (gain) Loss (gain) from investments Total non–segmented expenses Earnings (loss) before taxes Current income tax expense (recovery) Deferred income tax expense (recovery) Net earnings (loss) Inter-segment elimination and Other includes internal transportation and electricity charges. Production, processing and other purchasing and selling activities that are not included in the above segments are also reported in the segmented information as Inter-segment eliminations and Other. In connection with the adoption of IFRS 15 on January 1, 2018 (see note 2), the Company has reclassified certain comparative figures for product sales, production expense and transportation, blending and feedstock expense for the years ended December 31, 2017 and 2016 in a manner consistent with the presentation adopted for the year ended December 31, 2018. Operating segments are reported in a manner consistent with the internal reporting provided to the Company’s chief operating decision makers. Oil Sands Mining and Upgrading Midstream Inter–segment elimination and Other Total 2018 2017 2016 2018 2017 2016 2018 2017 2016 2018 2017 2016 $ 11,521 $ 7,072 $ 2,657 $ 102 $ 102 $ 114 $ 410 $ 448 $ 682 $ 20,668 $ 16,522 $ 10,396 — — — — — — 148 161 167 1,614 1,838 1,606 11,521 7,072 2,657 102 102 114 558 609 849 22,282 18,360 12,002 (479 ) (167 ) (24 ) — — — — — — (1,255 ) (1,018 ) (575 ) 11,042 6,905 2,633 102 102 114 558 609 849 21,027 17,342 11,427 3,367 2,600 1,292 21 16 25 58 71 78 6,464 5,675 4,184 1,087 679 80 — — — 491 527 751 4,189 3,529 2,822 1,557 1,220 662 14 9 11 — — — 5,161 5,186 4,858 61 48 29 — — — — — — 186 164 142 — — — — — — — — — (10 ) (45 ) 6 — (230 ) — — (114 ) (218 ) — — — (452 ) (379 ) (250 ) — — — 5 (31 ) (7 ) — — — 5 (31 ) (7 ) 6,072 4,317 2,063 40 (120 ) (189 ) 549 598 829 15,543 14,099 11,755 $ 4,970 $ 2,588 $ 570 $ 62 $ 222 $ 303 $ 9 $ 11 $ 20 $ 5,484 $ 3,243 $ (328 ) 325 319 345 (146 ) 134 355 739 631 383 (124 ) 80 27 827 (787 ) (55 ) 341 (7 ) (320 ) 1,962 370 735 3,522 2,873 (1,063 ) 374 (164 ) (618 ) 557 640 (241 ) $ 2,591 $ 2,397 $ (204 ) Capital Expenditures (1) 2018 2017 Net expenditures Non-cash and fair value changes Capitalized costs Net expenditures (2) Non-cash and fair value changes (2) Capitalized costs Exploration and evaluation assets Exploration and Production North America (3) $ 118 $ (52 ) $ 66 $ 160 $ (184 ) $ (24 ) North Sea — — — — — — Offshore Africa (4) (54 ) — (54 ) 15 — 15 Oil Sands Mining and Upgrading 218 (225 ) (7 ) 142 117 259 $ 282 $ (277 ) $ 5 $ 317 $ (67 ) $ 250 Property, plant and equipment Exploration and Production North America $ 2,553 $ (362 ) $ 2,191 $ 2,815 $ 354 $ 3,169 North Sea 131 (597 ) (466 ) 160 95 255 Offshore Africa 228 (86 ) 142 89 12 101 2,912 (1,045 ) 1,867 3,064 461 3,525 Oil Sands Mining and Upgrading (5) 1,229 (166 ) 1,063 9,592 5,454 15,046 Midstream (6) 13 — 13 80 114 194 Head office 21 — 21 19 — 19 $ 4,175 $ (1,211 ) $ 2,964 $ 12,755 $ 6,029 $ 18,784 (1) This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments. (2) Net expenditures on exploration and evaluation assets and property, plant and equipment for the year ended December 31, 2017 exclude non-cash share consideration of $3,818 million issued on the acquisition of AOSP and other assets. This non-cash consideration is included in non-cash and other fair value changes. (3) The above noted figures for 2017 exclude the impact of a pre-tax cash gain of $35 million on the disposition of certain exploration and evaluation assets. (4) The above noted figures for 2018 exclude the impact of a pre-tax cash gain of $16 million on the disposition of certain exploration and evaluation assets. (5) Net expenditures for Oil Sands Mining and Upgrading include capitalized interest and share-based compensation. (6) Included in 2017 is the impact of a pre-tax non-cash revaluation gain of $114 million ( $83 million after-tax) related to a previously held joint interest in a pipeline system. Segmented Assets 2018 2017 Exploration and Production North America $ 27,199 $ 28,705 North Sea 1,699 1,854 Offshore Africa 1,471 1,331 Other 33 29 Oil Sands Mining and Upgrading 39,634 40,559 Midstream 1,413 1,279 Head office 110 110 $ 71,559 $ 73,867 |
REMUNERATION OF DIRECTORS AND S
REMUNERATION OF DIRECTORS AND SENIOR MANAGEMENT | 12 Months Ended |
Dec. 31, 2018 | |
Related Party [Abstract] | |
REMUNERATION OF DIRECTORS AND SENIOR MANAGEMENT | REMUNERATION OF DIRECTORS AND SENIOR MANAGEMENT Remuneration of Non-Management Directors 2018 2017 2016 Fees earned $ 2 $ 3 $ 2 Remuneration of Senior Management (1) 2018 2017 2016 Salary $ 2 $ 3 $ 3 Common stock option based awards 8 10 9 Annual incentive plans 4 5 5 Long-term incentive plans 15 17 15 $ 29 $ 35 $ 32 (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 & GAS INFORMA
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Disclosure Of Supplementary Oil And Gas Information Explanatory | Supplementary Oil & Gas Information for the Fiscal Year Ended December 31, 2018 (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, 2018, 2017, 2016, and 2015 the Company filed its reserves information under National Instrument 51-101 – "Standards of Disclosure of Oil and Gas Activities" ("NI 51-101"), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission ("SEC") requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards can be material. For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2018, 2017, 2016, and 2015 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 2018 reserves for SEC requirements. Crude Oil and NGLs Natural Gas WTI Cushing Oklahoma WCS Canadian Light Sweet Cromer LSB North Sea Brent Edmonton C5+ Henry Hub Louisiana AECO BC Westcoast Station 2 (US$/bbl) (C$/bbl) (C$/bbl) (C$/bbl) (US$/bbl) (C$/bbl) (US$/MMBtu) (C$/MMBtu) (C$/MMBtu) 65.55 53.67 70.32 75.54 72.09 80.65 3.02 1.46 1.25 A foreign exchange rate of US$1.00 /C$1.2821 was used in the 2018 evaluation, determined on the same basis as the 12-month average price. Net Proved Crude Oil and Natural Gas Reserves The Company retains Independent Qualified Reserves Evaluators to evaluate and review the Company's proved crude oil, bitumen, synthetic crude oil ("SCO"), natural gas, and natural gas liquids ("NGLs") reserves. • For the years ended December 31, 2018, 2017, 2016,and 2015, the reports by GLJ Petroleum Consultants Ltd. covered 100% of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules, effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals. • For the years ended December 31, 2018, 2017, 2016 and 2015, 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, 2018 , 2017 , 2016 , and 2015 : North America Crude Oil and NGLs (MMbbl) Synthetic Crude Oil Bitumen (1) Crude Oil & NGLs North America Total North Sea Offshore Africa Total Net Proved Reserves Reserves, December 31, 2015 2,283 1,263 471 4,017 119 73 4,209 Extensions and discoveries — 46 15 61 — — 61 Improved recovery — 5 14 19 1 2 22 Purchases of reserves in place — 3 15 18 — — 18 Sales of reserves in place — — — — — — — Production (45 ) (71 ) (43 ) (159 ) (9 ) (8 ) (176 ) Economic revisions due to prices 108 23 (19 ) 112 (10 ) 1 103 Revisions of prior estimates 196 32 51 279 (8 ) 6 277 Reserves, December 31, 2016 2,542 1,301 504 4,347 93 74 4,514 Extensions and discoveries — 28 17 45 — — 45 Improved recovery — 7 19 26 1 — 27 Purchases of reserves in place 2,232 37 67 2,336 — — 2,336 Sales of reserves in place — — — — — — — Production (100 ) (70 ) (44 ) (214 ) (9 ) (6 ) (229 ) Economic revisions due to prices — 18 17 35 18 1 54 Revisions of prior estimates 282 44 14 340 4 — 344 Reserves, December 31, 2017 4,956 1,365 594 6,915 107 69 7,091 Extensions and discoveries 744 151 17 912 — — 912 Improved recovery — 10 50 60 1 3 64 Purchases of reserves in place — 2 7 9 7 — 16 Sales of reserves in place — (4 ) — (4 ) — — (4 ) Production (148 ) (64 ) (47 ) (259 ) (9 ) (6 ) (274 ) Economic revisions due to prices — (45 ) (18 ) (63 ) 11 1 (51 ) Revisions of prior estimates 109 54 1 164 (3 ) 4 165 Reserves, December 31, 2018 5,661 1,469 604 7,734 114 71 7,919 Net proved developed reserves December 31, 2015 2,194 411 341 2,946 3 41 2,990 December 31, 2016 2,527 384 353 3,264 12 31 3,307 December 31, 2017 4,967 410 399 5,776 28 21 5,825 December 31, 2018 5,661 461 378 6,500 37 34 6,571 (1) 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. 2018 total proved Crude Oil and NGLs reserves increased by 828 MMbbl primarily due to the following: • Extensions and discoveries: Increase of 912 MMbbl primarily due to the addition of the Horizon South Pit to the Horizon oil sands mining and upgrading Project ("Horizon") (SCO), future thermal (Bitumen) well pad additions at Primrose and extension drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties. • Improved recovery: Increase of 64 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen), thermal (Bitumen), Crude Oil and natural gas (NGLs) properties as well as thermal (Bitumen) improved recovery additions. • Purchases of reserves in place: Increase of 16 MMbbl primarily due property acquisitions in North America and North Sea core areas. • Sale of reserves in place: Decrease of 4 MMbbl from the primary heavy crude oil (Bitumen) area. • Production: Decrease of 274 MMbbl. • Economic revisions due to prices: Decrease of 51 MMbbl primarily due to increased royalties at thermal (Bitumen) and Pelican Lake (Crude Oil) projects resulting from higher prices and uneconomic reserves at several North America natural gas (NGLs) core areas, partially offset by improved reserve life economics at the North Sea. • Revisions of prior estimates: Increase of 165 MMbbl primarily due to geological model changes and improved mine/extraction/upgrading performance at the oil sands mining and upgrading projects (SCO) and improved recoveries at Primrose (Bitumen). 2017 total proved Crude Oil and NGLs reserves increased by 2,577 MMbbl primarily due to the following: • Extensions and discoveries: Increase of 45 MMbbl primarily due to future thermal (Bitumen) well pad additions at Primrose and extension drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties. • Improved recovery: Increase of 27 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties. • Purchases of reserves in place: Increase of 2,336 MMbbl primarily due to acquisitions of the Athabasca Oil Sands Project (SCO), Peace River thermal and Cliffdale primary heavy crude oil properties (Bitumen) and at Pelican Lake (Crude Oil). • Production: Decrease of 229 MMbbl. • Economic revisions due to prices: Increase of 54 MMbbl primarily due to improved reserves life economics at several North America Bitumen and Crude Oil core areas. • Revisions of prior estimates: Increase of 344 MMbbl primarily due to Horizon (SCO) revising the stratigraphic well density used to define proved reserves quantities and increasing the Horizon (SCO) total-volume-to-bitumen-in-place-ratio, partially offset by Horizon (SCO) adopting a low fines mine plan. Additionally, there were overall positive revisions at several North America Bitumen and Crude Oil core areas including improved recoveries at Primrose (Bitumen). 2016 total proved Crude Oil and NGLs reserves increased by 305 MMbbl primarily due to the following: • Extensions and discoveries: Increase of 61 MMbbl primarily due to future thermal (Bitumen) well pad additions at Primrose and extension drilling/future offset additions at various primary heavy crude oil (Bitumen) and Crude Oil properties. • Improved recovery: Increase of 22 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen) and Crude Oil properties. • Purchases of reserves in place: Increase of 18 MMbbl due to various property acquisitions in several North America core areas. • Production: Decrease of 176 MMbbl. • Economic revisions due to prices: Increase of 103 MMbbl primarily due to reduced royalties at Horizon (SCO), thermal (Bitumen) and Pelican Lake (Crude Oil) projects, partially offset by the loss of uneconomic reserves at several North America Bitumen and Crude Oil core areas. • Revisions of prior estimates: Increase of 277 MMbbl primarily due to Horizon (SCO) revising the stratigraphic well density used to define proved reserves quantities. Additionally, there were overall positive revisions at several North America Bitumen and Crude Oil core areas. Natural Gas (Bcf) North America North Sea Offshore Africa Total Net Proved Reserves Reserves, December 31, 2015 4,523 38 21 4,582 Extensions and discoveries 176 — — 176 Improved recovery 166 — 3 169 Purchases of reserves in place 85 — — 85 Sales of reserves in place (5 ) — — (5 ) Production (571 ) (14 ) (11 ) (596 ) Economic revisions due to prices (572 ) (10 ) 1 (581 ) Revisions of prior estimates 792 11 11 814 Reserves, December 31, 2016 4,594 25 25 4,644 Extensions and discoveries 261 — — 261 Improved recovery 179 — — 179 Purchases of reserves in place 106 — — 106 Sales of reserves in place — — — — Production (558 ) (14 ) (7 ) (579 ) Economic revisions due to prices 403 5 (1 ) 407 Revisions of prior estimates 214 9 (1 ) 222 Reserves, December 31, 2017 5,199 25 16 5,240 Extensions and discoveries 90 — — 90 Improved recovery 414 — — 414 Purchases of reserves in place 67 — — 67 Sales of reserves in place (3 ) — — (3 ) Production (523 ) (11 ) (8 ) (542 ) Economic revisions due to prices (746 ) — (2 ) (748 ) Revisions of prior estimates (192 ) 13 15 (164 ) Reserves, December 31, 2018 4,306 27 21 4,354 Net proved developed reserves December 31, 2015 2,883 26 15 2,924 December 31, 2016 2,805 18 18 2,841 December 31, 2017 3,081 22 9 3,112 December 31, 2018 2,382 23 12 2,417 2018 total proved Natural Gas reserves decreased by 886 Bcf primarily due to the following: • Extensions and discoveries: Increase of 90 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia. • Improved recovery: Increase of 414 Bcf primarily due to infill drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia. • Purchases of reserves in place: Increase of 67 Bcf primarily due to property acquisitions in several North America core areas. • Sale of reserves in place: Decrease of 3 Bcf. • Production: Decrease of 542 Bcf. • Economic revisions due to prices: Decrease of 748 Bcf due to uneconomic reserves at several North America Natural Gas core areas. • Revisions of prior estimates: Decrease of 164 Bcf primarily due to the removal of future extension and infill undeveloped reserves at several North America properties as a result of revised Company development plans. 2017 total proved Natural Gas reserves increased by 596 Bcf primarily due to the following: • Extensions and discoveries: Increase of 261 Bcf primarily due to extension drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia. • Improved recovery: Increase of 179 Bcf primarily due to infill drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia. • Purchases of reserves in place: Increase of 106 Bcf primarily due to property acquisitions in several North America core areas. • Production: Decrease of 579 Bcf. • Economic revisions due to prices: Increase of 407 Bcf due to improved reserves life economics at several North America Natural Gas core areas. • Revisions of prior estimates: Increase of 222 Bcf primarily due to overall positive revisions at several North America core areas triggered by production optimizations and reduced production costs. 2016 total proved Natural Gas reserves increased by 62 Bcf primarily due to the following: • Extensions and discoveries: Increase of 176 Bcf primarily due to extension drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia. • Improved recovery: Increase of 169 Bcf primarily due to infill drilling/future offset additions in the Montney and Spirit River formations of northwest Alberta and northeast British Columbia. • Purchases of reserves in place: Increase of 85 Bcf primarily due to various property acquisitions in several North America core areas. • Production: Decrease of 596 Bcf. • Economic revisions due to prices: Decrease of 581 Bcf due to the loss of uneconomic reserves at several North America areas. • Revisions of prior estimates: Increase of 814 Bcf primarily due to overall positive revisions at several North America core areas triggered by production optimizations and reduced production costs. Capitalized Costs Related to Crude Oil and Natural Gas Activities 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 110,154 $ 7,321 $ 5,471 $ 122,946 Unproved properties 2,600 — 37 2,637 112,754 7,321 5,508 125,583 Less: accumulated depletion and depreciation (48,862 ) (5,735 ) (4,203 ) (58,800 ) Net capitalized costs $ 63,892 $ 1,586 $ 1,305 $ 66,783 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 106,900 $ 7,126 $ 4,881 $ 118,907 Unproved properties 2,541 — 91 2,632 109,441 7,126 4,972 121,539 Less: accumulated depletion and depreciation (44,779 ) (5,653 ) (3,719 ) (54,151 ) Net capitalized costs $ 64,662 $ 1,473 $ 1,253 $ 67,388 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 88,685 $ 7,380 $ 5,132 $ 101,197 Unproved properties 2,306 — 76 2,382 90,991 7,380 5,208 103,579 Less: accumulated depletion and depreciation (41,139 ) (5,584 ) (3,797 ) (50,520 ) Net capitalized costs $ 49,852 $ 1,796 $ 1,411 $ 53,059 Costs Incurred in Crude Oil and Natural Gas Activities 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 214 $ 127 $ — $ 341 Unproved 340 — (89 ) 251 Exploration 116 — 35 151 Development 3,245 110 212 3,567 Costs incurred $ 3,915 $ 237 $ 158 $ 4,310 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 15,091 $ — $ — $ 15,091 Unproved 321 — — 321 Exploration 112 — 15 127 Development 3,753 255 101 4,109 Costs incurred $ 19,277 $ 255 $ 116 $ 19,648 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 50 $ — $ — $ 50 Unproved — — — — Exploration 17 — 9 26 Development 4,125 186 116 4,427 Costs incurred $ 4,192 $ 186 $ 125 $ 4,503 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, 2018, 2017, and 2016 are summarized in the following tables: 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 16,065 $ 891 $ 647 $ 17,603 Production (5,772 ) (405 ) (208 ) (6,385 ) Transportation (929 ) (22 ) (2 ) (953 ) Depletion, depreciation and amortization (4,689 ) (257 ) (201 ) (5,147 ) Asset retirement obligation accretion (148 ) (29 ) (9 ) (186 ) Petroleum revenue tax — 12 — 12 Income tax (1,223 ) (76 ) (51 ) (1,350 ) Results of operations $ 3,304 $ 114 $ 176 $ 3,594 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 13,083 $ 784 $ 578 $ 14,445 Production (4,962 ) (400 ) (226 ) (5,588 ) Transportation (790 ) (31 ) (1 ) (822 ) Depletion, depreciation and amortization (4,463 ) (509 ) (205 ) (5,177 ) Asset retirement obligation accretion (128 ) (27 ) (9 ) (164 ) Petroleum revenue tax — 78 — 78 Income tax (740 ) 42 (28 ) (726 ) Results of operations $ 2,000 $ (63 ) $ 109 $ 2,046 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 7,791 $ 565 $ 577 $ 8,933 Production (3,478 ) (403 ) (200 ) (4,081 ) Transportation (623 ) (48 ) (2 ) (673 ) Depletion, depreciation and amortization (4,127 ) (458 ) (262 ) (4,847 ) Asset retirement obligation accretion (95 ) (35 ) (12 ) (142 ) Petroleum revenue tax — 333 — 333 Income tax 143 18 (22 ) 139 Results of operations $ (389 ) $ (28 ) $ 79 $ (338 ) 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": 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 500,557 $ 12,002 $ 6,447 $ 519,006 Future production costs (193,387 ) (5,148 ) (2,284 ) (200,819 ) Future development costs and asset retirement obligations (63,202 ) (2,909 ) (1,099 ) (67,210 ) Future income taxes (60,526 ) (1,484 ) (626 ) (62,636 ) Future net cash flows 183,442 2,461 2,438 188,341 10% annual discount for timing of future cash flows (126,699 ) (545 ) (771 ) (128,015 ) Standardized measure of future net cash flows $ 56,743 $ 1,916 $ 1,667 $ 60,326 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 413,180 $ 8,740 $ 4,786 $ 426,706 Future production costs (198,304 ) (4,168 ) (1,876 ) (204,348 ) Future development costs and asset retirement obligations (61,169 ) (2,853 ) (1,258 ) (65,280 ) Future income taxes (35,645 ) (595 ) (248 ) (36,488 ) Future net cash flows 118,062 1,124 1,404 120,590 10% annual discount for timing of future cash flows (73,171 ) (59 ) (455 ) (73,685 ) Standardized measure of future net cash flows $ 44,891 $ 1,065 $ 949 $ 46,905 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 206,729 $ 5,999 $ 4,129 $ 216,857 Future production costs (92,070 ) (3,284 ) (1,659 ) (97,013 ) Future development costs and asset retirement obligations (42,167 ) (3,249 ) (1,234 ) (46,650 ) Future income taxes (15,396 ) 280 (125 ) (15,241 ) Future net cash flows 57,096 (254 ) 1,111 57,953 10% annual discount for timing of future cash flows (33,590 ) 271 (319 ) (33,638 ) Standardized measure of future net cash flows $ 23,506 $ 17 $ 792 $ 24,315 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) 2018 2017 2016 Sales of crude oil and natural gas produced, net of production costs $ (10,229 ) $ (8,013 ) $ (4,159 ) Net changes in sales prices and production costs 20,386 7,466 (7,305 ) Extensions, discoveries and improved recovery 2,807 481 700 Changes in estimated future development costs (698 ) (5,548 ) 1,750 Purchases of proved reserves in place 396 25,782 352 Sales of proved reserves in place (55 ) — (2 ) Revisions of previous reserve estimates 2,711 4,245 3,668 Accretion of discount 6,119 3,075 3,527 Changes in production timing and other (955 ) (662 ) (2,137 ) Net change in income taxes (7,061 ) (4,236 ) 385 Net change 13,421 22,590 (3,221 ) Balance - beginning of year 46,905 24,315 27,536 Balance - end of year $ 60,326 $ 46,905 $ 24,315 |
ACCOUNTING POLICIES (Policies)
ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
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. |
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. 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. |
Segmented information | SEGMENTED INFORMATION 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. |
Cash and cash equivalents | CASH AND CASH EQUIVALENTS Cash comprises cash on hand and demand deposits. Other investments (term deposits and certificates of deposit) with an original term to maturity at purchase of three months or less are reported as cash equivalents in the consolidated balance sheets. |
Inventory | INVENTORY Inventory is primarily comprised of product inventory and materials and supplies 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. 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 is determined by reference to current market prices. |
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 impairment provisions. Assets under construction are not depleted or depreciated until available for their intended use. The capitalized value of a finance lease is included in property, plant and equipment. 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 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, 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. 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 18 years. Midstream and Head Office The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream and head office assets. Midstream 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 maintenance turnarounds are capitalized and depreciated over the period to the next major maintenance turnaround. All other 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 is written down to its recoverable amount 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 impairment losses 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 impairment loss been recognized for the asset in prior periods. A reversal of impairment 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. |
Overburden removal costs | OVERBURDEN REMOVAL COSTS Overburden removal costs incurred during the initial development of a mine at Horizon and AOSP are capitalized to property, plant and equipment. Overburden removal costs incurred during the production of a mine are included in the cost of inventory, unless the overburden removal activity has resulted in a probable inflow of future economic benefits to the Company, in which case the costs are capitalized to property, plant and equipment. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from the overburden removal activity. |
Capitalized borrowing costs | CAPITALIZED BORROWING COSTS Borrowing costs attributable to the acquisition, construction or production of qualifying assets are capitalized to the cost of those assets until such time as the assets are substantially available for their intended use. Qualifying assets are comprised of those significant assets that require a period greater than one year to be available for their intended use. All other borrowing costs are recognized in net earnings. |
Leases | LEASES Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. Operating lease payments are recognized in net earnings over the lease term. |
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 industry 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”). The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. The assets and liabilities of subsidiaries that have a functional currency different from that of the Company are translated into Canadian dollars at the closing rate at the date of the balance sheets, and revenue and expenses are translated at the average rate for the period. Cumulative foreign currency translation adjustments are recognized in other comprehensive income. When the Company disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings. Transactions and balances Foreign currency transactions are translated into the functional currency of the Company and its subsidiaries and partnerships using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at balance sheet date exchange rates of monetary assets and liabilities denominated in currencies other than the functional currency 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. 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. The Company continues to report revenue for the years ended December 31, 2017 and 2016 in accordance with the Company's previous accounting policy for revenue and cost of goods sold as follows: Revenue from the sale of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. |
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 and Gabon 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. Income taxes are recognized in net earnings or other comprehensive income, consistent with the items to which they relate. |
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 re-measured 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 Company grants Performance Share Units ("PSUs") to certain executive employees. The PSUs are subject to certain performance conditions and vest three years from original grant date. 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. The Company continues to report impairment of financial assets for the years ended December 31, 2017 and 2016 in accordance with the Company's previous accounting policy for impairment of financial assets as follows: At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, an impairment loss is recognized. Impairment losses on financial assets carried at amortized cost are calculated as the difference between the amortized cost of the financial asset and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. Impairment losses on financial assets carried at amortized cost 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. |
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. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain of its long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. Changes in the fair value of interest rate swap contracts designated as fair value hedges and corresponding changes in the fair value of the hedged long-term debt are recognized in interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are recognized in risk management activities in net earnings. Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized in the consolidated balance sheets and the related long-term debt hedged is no longer revalued for subsequent changes in fair value due to interest rates changes. The fair value adjustment due to interest rates on the long-term debt at the date of termination of the interest rate swap is amortized to interest expense over the remaining term of the long-term debt. 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. Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded at fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related to the host contract, except when the host contract is an asset. |
Comprehensive income | COMPREHENSIVE INCOME Comprehensive income is comprised of the Company’s net earnings and other comprehensive income. Other comprehensive income includes the effective portion of changes in the fair value of derivative financial instruments designated as cash flow hedges and foreign currency translation gains and losses arising from the net investment in foreign operations that do not have a Canadian dollar functional currency. Other comprehensive income is shown net of related income taxes. |
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. |
Dividends | DIVIDENDS Dividends on common shares are recognized in the Company’s financial statements in the period in which the dividends are declared by the Board of Directors. |
Accounting standards issued but not yet applied | ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED In October 2018, the IASB issued amendments to IFRS 3 "Definition of a Business" that narrowed and clarified the definition of a business. The amendments also permit a simplified assessment of whether an acquired set of activities and assets is a group of assets rather than a business. The amendments are effective January 1, 2020 with earlier adoption permitted. The amendments apply to business combinations after the date of adoption. The Company is assessing the impact of these amendments on its consolidated financial statements. In October 2018, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" and IAS 8 "Accounting Policies, Changes in Accounting Estimates and Errors". The amendments make minor changes to the definition of the term "material" and align the definition across all IFRS Standards. Materiality is used in making judgments related to the preparation of financial statements. The amendments are effective January 1, 2020 with earlier adoption permitted. The Company is assessing the impact of these amendments on its consolidated financial statements. In October 2017, the IASB issued amendments to IAS 28 "Investments in Associates and Joint Ventures" to clarify that the impairment provisions in IFRS 9 apply to financial instruments in an associate or joint venture that are not accounted for using the equity method, including long-term assets that form part of the net investment in the associate or joint venture. The amendments are effective January 1, 2019 with earlier adoption permitted. The amendments are required to be adopted retrospectively. The Company has determined that these amendments have no significant impact on its consolidated financial statements. In June 2017, the IASB issued IFRIC 23 "Uncertainty over Income Tax Treatments". The interpretation provides guidance on how to reflect the effects of uncertainty in accounting for income taxes where IAS 12 is unclear. The interpretation is effective January 1, 2019. The Company has determined that this interpretation has no significant impact on its consolidated financial statements. IFRS 16 "Leases" In January 2016, the IASB issued IFRS 16 “Leases”, which provides guidance on accounting for leases. The new standard replaces IAS 17 “Leases” and related interpretations. IFRS 16 eliminates the distinction between operating leases and financing leases for lessees and requires balance sheet recognition for all leases. Certain short-term (less than 12 months) and low-value leases (as defined in the standard) are exempt from the requirements, and may continue to be treated as an expense. Leases to explore for or use crude oil, natural gas, minerals and similar non-regenerative resources are exempt from the standard. The Company will adopt IFRS 16 on January 1, 2019 using the retrospective with cumulative effect method with no impact to opening retained earnings at the date of adoption. In accordance with the transitional provisions in the standard, balances reported in the comparative periods will not be restated. On initial adoption, the Company intends to use the following practical expedients under the standard. Certain expedients are on a lease-by-lease basis and others are applicable by class of underlying assets: • the use of a single discount rate to a portfolio of leases with reasonably similar characteristics; • leases with a remaining lease term of less than twelve months as at January 1, 2019 will be treated as short- term leases; and • exclusion of indirect costs for the measurement of lease assets at the date of initial application. The Company does not intend to apply any practical expedients pertaining to grandfathering of leases assessed under the previous standard. On adoption of IFRS 16, the Company will recognize lease assets and liabilities at the present value of the remaining lease payments, discounted using the Company’s applicable borrowing rate on January 1, 2019. The Company expects to report additional lease assets and corresponding liabilities of between $1.5 billion and $1.6 billion . The Company continues to finalize its accounting for leases in accordance with IFRS 16, and the above estimates are subject to change based on finalization of the Company's review of its lease arrangements. In the statement of earnings, depletion, depreciation and amortization expense and interest expense will increase, with corresponding decreases in production, transportation and administration expenses. The Company does not expect to report a material impact on net earnings. Under the new standard, the Company will report cash outflows for repayment of the principal portion of the lease liability as cash flows from financing activities. The interest portion of the lease payments will continue to be classified as cash flows from operating activities. Where the Company, acting as the operator, signs a lease on behalf of a joint operation and assumes the legal liability for that lease, the Company will recognize 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 will be recognized in the consolidated statements of earnings. |
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 engineering data, 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. 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, and changes in the date of abandonment due to changes in reserves life. 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 asset’s 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) 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, 2018 | |
Inventories [Abstract] | |
Schedule of Inventory | 2018 2017 Product inventory $ 297 $ 285 Materials and supplies 658 609 $ 955 $ 894 |
EXPLORATION AND EVALUATION AS_2
EXPLORATION AND EVALUATION ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2016 $ 2,306 $ — $ 76 $ — $ 2,382 Additions 144 — 15 — 159 Acquisition of AOSP and other assets (note 8) 31 — — 259 290 Transfers to property, plant and equipment (198 ) — — — (198 ) Disposals/derecognitions (1 ) — — — (1 ) At December 31, 2017 2,282 — 91 259 2,632 Additions 245 — 35 222 502 Transfers to property, plant and equipment (175 ) — — (222 ) (397 ) Disposals/derecognitions and other (4 ) — (89 ) (7 ) (100 ) At December 31, 2018 $ 2,348 $ — $ 37 $ 252 $ 2,637 |
PROPERTY, PLANT AND EQUIPMENT (
PROPERTY, PLANT AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, plant and equipment [abstract] | |
Detailed information about property, plant and equipment | Exploration and Production Oil Sands Mining and Upgrading Midstream Head Office Total North America North Sea Offshore Africa Cost At December 31, 2016 $ 61,647 $ 7,380 $ 5,132 $ 27,038 $ 234 $ 395 $ 101,826 Additions (1) 3,003 255 101 1,660 194 19 5,232 Acquisition of AOSP and other assets (note 8) 349 — — 13,832 — — 14,181 Transfers from E&E assets 198 — — — — — 198 Disposals/derecognitions (381 ) — — (446 ) — — (827 ) Foreign exchange adjustments and other — (509 ) (352 ) — — — (861 ) At December 31, 2017 64,816 7,126 4,881 42,084 428 414 119,749 Additions (2) 2,428 237 212 1,050 13 21 3,961 Transfers from E&E assets 175 — — 222 — — 397 Disposals/derecognitions (412 ) (703 ) (70 ) (209 ) — — (1,394 ) Foreign exchange adjustments and other — 661 448 — — — 1,109 At December 31, 2018 $ 67,007 $ 7,321 $ 5,471 $ 43,147 $ 441 $ 435 $ 123,822 Accumulated depletion and depreciation At December 31, 2016 $ 38,311 $ 5,584 $ 3,797 $ 2,828 $ 115 $ 281 $ 50,916 Expense 3,220 509 205 1,220 9 23 5,186 Disposals/derecognitions (381 ) — — (446 ) — — (827 ) Foreign exchange adjustments and other 1 (440 ) (283 ) 26 — — (696 ) At December 31, 2017 41,151 5,653 3,719 3,628 124 304 54,579 Expense 3,111 257 201 1,557 14 21 5,161 Disposals/derecognitions (393 ) (703 ) (70 ) (209 ) — — (1,375 ) Foreign exchange adjustments and other 12 528 353 5 — — 898 At December 31, 2018 $ 43,881 $ 5,735 $ 4,203 $ 4,981 $ 138 $ 325 $ 59,263 Net book value - at December 31, 2018 $ 23,126 $ 1,586 $ 1,268 $ 38,166 $ 303 $ 110 $ 64,559 - at December 31, 2017 $ 23,665 $ 1,473 $ 1,162 $ 38,456 $ 304 $ 110 $ 65,170 (1) Additions in Midstream include a pre-tax revaluation gain of $114 million of a previously held joint interest in certain pipeline system assets. (2) Additions in North Sea include a pre-tax revaluation gain of $19 million relating to acquisitions of its previously held interest. Project costs not subject to depletion and depreciation 2018 2017 Kirby Thermal Oil Sands – North $ 1,424 $ 944 |
ACQUISITION OF INTERESTS IN T_2
ACQUISITION OF INTERESTS IN THE ATHABASCA OIL SANDS PROJECT AND OTHER ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations1 [Abstract] | |
Summary of net assets acquired and liabilities assumed | The following provides a summary of the net assets acquired and (liabilities) assumed relating to the acquisition: Cash $ 93 Other working capital 291 Property, plant and equipment 14,181 Exploration and evaluation assets 290 Asset retirement obligations (721 ) Other long-term liabilities (73 ) Deferred income taxes (1,287 ) Net assets acquired $ 12,774 Total purchase consideration 12,541 Gain on acquisition before transaction costs $ 233 |
INVESTMENTS (Tables)
INVESTMENTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Financial Instruments [Abstract] | |
Summary of investments | The loss (gain) from the investment in PrairieSky was comprised as follows: 2018 2017 2016 Fair value loss (gain) from PrairieSky $ 326 $ (3 ) $ (292 ) Dividend income from PrairieSky (17 ) (17 ) (27 ) $ 309 $ (20 ) $ (319 ) The loss (gain) from the investment in Inter Pipeline was comprised as follows: 2018 2017 2016 Fair value loss from Inter Pipeline $ 43 $ 23 $ — Dividend income from Inter Pipeline (11 ) (10 ) (1 ) $ 32 $ 13 $ (1 ) As at December 31, 2018 and 2017 , the Company had the following investments: 2018 2017 Investment in PrairieSky Royalty Ltd. $ 400 $ 726 Investment in Inter Pipeline Ltd. 124 167 $ 524 $ 893 |
OTHER LONG-TERM ASSETS (Tables)
OTHER LONG-TERM ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Subclassifications of assets, liabilities and equities [abstract] | |
Disclosure of other long-term assets | 2018 2017 Investment in North West Redwater Partnership $ 287 $ 292 North West Redwater Partnership subordinated debt (1) 591 510 Risk management (note 19) 373 204 Other 208 241 1,459 1,247 Less: current portion 116 79 $ 1,343 $ 1,168 (1) Includes accrued interest. |
Summary of assets, liabilities, partners' equity and equity (income) loss related to joint venture | The assets, liabilities, partners’ equity and equity loss (income) related to Redwater Partnership and the Company’s 50% interest at December 31, 2018 and 2017 were comprised as follows: 2018 2017 Redwater Partnership Company Redwater Partnership Company Current assets $ 210 $ 105 $ 330 $ 165 Non-current assets $ 11,250 $ 5,625 $ 10,540 $ 5,270 Current liabilities $ 352 $ 176 $ 2,476 $ 1,238 Non-current liabilities $ 10,534 $ 5,267 $ 7,810 $ 3,905 Partners’ equity $ 574 $ 287 $ 584 $ 292 Equity loss (income) $ 10 $ 5 $ (62 ) $ (31 ) |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Financial Instruments [Abstract] | |
Summary of long-term debt | 2018 2017 Canadian dollar denominated debt, unsecured Bank credit facilities $ 831 $ 3,544 Medium-term notes 3.05% debentures due June 19, 2019 500 500 2.60% debentures due December 3, 2019 500 500 2.05% debentures due June 1, 2020 900 900 2.89% debentures due August 14, 2020 1,000 1,000 3.31% debentures due February 11, 2022 1,000 1,000 3.55% debentures due June 3, 2024 500 500 3.42% debentures due December 1, 2026 600 600 4.85% debentures due May 30, 2047 300 300 6,131 8,844 US dollar denominated debt, unsecured Bank credit facilities (December 31, 2018 - US$2,954 million; 4,031 2,300 Commercial paper (December 31, 2018 - US$104 million; December 31, 2017 - US$500 million) 141 625 US dollar debt securities 1.75% due January 15, 2018 (US$600 million) — 751 5.90% due February 1, 2018 (US$400 million) — 501 3.45% due November 15, 2021 (US$500 million) 682 625 2.95% due January 15, 2023 (US$1,000 million) 1,364 1,252 3.80% due April 15, 2024 (US$500 million) 682 625 3.90% due February 1, 2025 (US$600 million) 819 751 3.85% due June 1, 2027 (US$1,250 million) 1,706 1,566 7.20% due January 15, 2032 (US$400 million) 546 501 6.45% due June 30, 2033 (US$350 million) 478 438 5.85% due February 1, 2035 (US$350 million) 478 438 6.50% due February 15, 2037 (US$450 million) 614 563 6.25% due March 15, 2038 (US$1,100 million) 1,501 1,377 6.75% due February 1, 2039 (US$400 million) 546 501 4.95% due June 1, 2047 (US$750 million) 1,023 939 14,611 13,753 Long-term debt before transaction costs and original issue discounts, net 20,742 22,597 Less: original issue discounts, net (1) 17 18 transaction costs (1) (2) 102 121 20,623 22,458 Less: current portion of commercial paper 141 625 current portion of other long-term debt (1) (2) 1,000 1,252 $ 19,482 $ 20,581 (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 2019 $ 1,141 2020 $ 5,996 2021 $ 1,444 2022 $ 1,003 2023 $ 1,365 Thereafter $ 9,793 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 $ 779 $ — $ — $ — Accrued liabilities $ 2,356 $ — $ — $ — Other long-term liabilities $ 42 $ 24 $ 69 $ — Long-term debt (1) (2) $ 1,141 $ 5,996 $ 3,812 $ 9,793 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. (2) In addition to the financial liabilities disclosed above, estimated interest and other financing payments related to long-term debt are as follows: less than one year, $836 million ; one to less than two years, $755 million ; two to less than five years, $1,668 million ; and thereafter, $5,327 million . Interest payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2018 . |
OTHER LONG-TERM LIABILITIES (Ta
OTHER LONG-TERM LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Subclassifications of assets, liabilities and equities [abstract] | |
Disclosure of other long-term liabilities | 2018 2017 Asset retirement obligations $ 3,886 $ 4,327 Share-based compensation 124 414 Risk management (note 19) 17 103 Deferred purchase consideration (1) (2) 118 469 Other 80 96 4,225 5,409 Less: current portion 335 1,012 $ 3,890 $ 4,397 (1) Includes $118 million of deferred purchase consideration at December 31, 2018, payable in annual installments of $25 million over the next five years. (2) Includes $469 million ( US$375 million ) of deferred purchase consideration at December 31, 2017, paid to Marathon in March 2018. |
Summary of asset retirement obligations | Reconciliations of the discounted asset retirement obligations were as follows: 2018 2017 2016 Balance – beginning of year $ 4,327 $ 3,243 $ 2,950 Liabilities incurred 19 12 3 Liabilities acquired, net 6 784 30 Liabilities settled (290 ) (274 ) (267 ) Asset retirement obligation accretion 186 164 142 Revision of cost, inflation rates and timing estimates (111 ) (40 ) (68 ) Change in discount rate (334 ) 509 493 Foreign exchange adjustments 83 (71 ) (40 ) Balance – end of year 3,886 4,327 3,243 Less: current portion 186 92 95 $ 3,700 $ 4,235 $ 3,148 Segmented Asset Retirement Obligations 2018 2017 Exploration and Production North America $ 1,665 $ 1,840 North Sea 707 755 Offshore Africa 134 245 Oil Sands Mining and Upgrading 1,379 1,486 Midstream 1 1 $ 3,886 $ 4,327 |
Summary of share-based compensation liability | 2018 2017 2016 Balance – beginning of year $ 414 $ 426 $ 128 Share-based compensation (recovery) expense (146 ) 134 355 Cash payment for stock options surrendered (5 ) (6 ) (7 ) Transferred to common shares (120 ) (154 ) (117 ) (Recovered from) charged to Oil Sands Mining and Upgrading, net (19 ) 14 67 Balance – end of year 124 414 426 Less: current portion 92 348 368 $ 32 $ 66 $ 58 |
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: 2018 2017 2016 Fair value $ 3.33 $ 11.82 $ 11.41 Share price $ 32.94 $ 44.92 $ 42.79 Expected volatility 27.4% 27.1% 30.7% Expected dividend yield 4.1% 2.5% 2.3% Risk free interest rate 1.9% 1.8% 0.9% Expected forfeiture rate 4.2% 5.0% 5.0% Expected stock option life (1) 4.4 years 4.5 years 4.6 years (1) At original time of grant. |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Taxes [Abstract] | |
Schedule of provision for income tax | The provision for income tax was as follows: Expense (recovery) 2018 2017 2016 Current corporate income tax – North America $ 312 $ (145 ) $ (377 ) Current corporate income tax – North Sea 28 57 (74 ) Current corporate income tax – Offshore Africa 54 45 22 Current PRT (1) – North Sea (29 ) (132 ) (198 ) Other taxes 9 11 9 Current income tax 374 (164 ) (618 ) Deferred corporate income tax 540 586 (106 ) Deferred PRT (1) – North Sea 17 54 (135 ) Deferred income tax 557 640 (241 ) Income tax $ 931 $ 476 $ (859 ) (1) 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 (loss) before taxes. The reasons for the difference are as follows: 2018 2017 2016 Canadian statutory income tax rate 27.0% 27.0% 27.0% Income tax provision at statutory rate $ 951 $ 776 $ (287 ) Effect on income taxes of: UK PRT and other taxes (3 ) (67 ) (324 ) Impact of deductible UK PRT and other taxes on corporate income tax 3 28 131 Foreign and domestic tax rate differentials 6 (43 ) (54 ) Non-taxable portion of capital gains/losses 142 (86 ) (80 ) Stock options exercised for common shares (41 ) 33 94 Income tax rate and other legislative changes — 10 (107 ) Non-taxable gain on corporate acquisitions (119 ) (63 ) — Revisions arising from prior year tax filings (136 ) (3 ) (120 ) Change in unrecognized capital loss carryforward asset 142 (86 ) (80 ) Other (14 ) (23 ) (32 ) Income tax expense (recovery) $ 931 $ 476 $ (859 ) |
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: 2018 2017 Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets $ 12,885 $ 12,484 Unrealized risk management activities 33 20 PRT deduction for corporate income tax 1 7 Investments 46 96 Investment in North West Redwater Partnership 414 252 Other 174 — 13,553 12,859 Deferred income tax assets Asset retirement obligations (1,142 ) (1,264 ) Loss carryforwards (855 ) (523 ) Unrealized foreign exchange loss on long-term debt (104 ) (29 ) Deferred PRT (1 ) (18 ) Other — (50 ) (2,102 ) (1,884 ) Net deferred income tax liability $ 11,451 $ 10,975 The following table summarizes the movements of the net deferred income tax liability during the year: 2018 2017 2016 Balance – beginning of year $ 10,975 $ 9,073 $ 9,344 Deferred income tax expense (recovery) 557 640 (241 ) Deferred income tax (recovery) expense included in other comprehensive income (6 ) 4 (5 ) Foreign exchange adjustments 41 (29 ) (25 ) Business combinations (note 6,7,8) (116 ) 1,287 — Balance – end of year $ 11,451 $ 10,975 $ 9,073 Movements in deferred tax assets and liabilities recognized in net earnings (loss) during the year were as follows: 2018 2017 2016 Property, plant and equipment and exploration and evaluation assets $ 281 $ 541 $ 37 Timing of partnership items — — (261 ) Unrealized foreign exchange (gain) loss on long-term debt (75 ) 120 63 Unrealized risk management activities 18 (46 ) (44 ) Asset retirement obligations 175 (88 ) (20 ) Loss carryforwards (61 ) 48 (221 ) Investments (50 ) (2 ) 38 Investment in North West Redwater Partnership 162 30 81 Deferred PRT 17 54 (135 ) PRT deduction for corporate income tax (7 ) (21 ) 61 Other 97 4 160 $ 557 $ 640 $ (241 ) |
SHARE CAPITAL (Tables)
SHARE CAPITAL (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Share Capital, Reserves And Other Equity Interest [Abstract] | |
Summary of outstanding common stock | 2018 2017 Issued Common shares Number of shares (thousands) Amount Number of shares Amount Balance – beginning of year 1,222,769 $ 9,109 1,110,952 $ 4,671 Issued for the acquisition of AOSP and other assets (note 8) — — 97,561 3,818 Issued upon exercise of stock options 9,975 332 14,256 466 Previously recognized liability on stock options exercised for common shares — 120 — 154 Purchase of common shares under Normal Course Issuer Bid (30,858 ) (238 ) — — Balance – end of year 1,201,886 $ 9,323 1,222,769 $ 9,109 |
Summary of stock option activity | The following table summarizes information relating to stock options outstanding at December 31, 2018 and 2017 : 2018 2017 Stock options (thousands) Weighted average exercise price Stock options (thousands) Weighted Outstanding – beginning of year 56,036 $ 36.67 58,299 $ 34.22 Granted 4,256 $ 43.75 16,052 $ 42.07 Surrendered for cash settlement (392 ) $ 33.46 (626 ) $ 33.18 Exercised for common shares (9,975 ) $ 33.28 (14,256 ) $ 32.66 Forfeited (3,240 ) $ 38.76 (3,433 ) $ 37.53 Outstanding – end of year 46,685 $ 37.92 56,036 $ 36.67 Exercisable – end of year 19,436 $ 36.03 18,282 $ 34.25 |
Summary of range of exercise prices of stock options outstanding | The range of exercise prices of stock options outstanding and exercisable at December 31, 2018 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 $22.90 - $24.99 3,120 2.04 $ 22.90 1,515 $ 22.90 $25.00 - $29.99 5,112 2.02 $ 28.86 2,453 $ 28.87 $30.00 - $34.99 6,013 0.83 $ 33.27 4,831 $ 33.43 $35.00 - $39.99 11,304 2.72 $ 37.46 4,131 $ 35.91 $40.00 - $44.99 17,107 3.23 $ 43.59 5,664 $ 43.60 $45.00 - $46.74 4,029 4.06 $ 45.20 842 $ 45.08 46,685 2.66 $ 37.92 19,436 $ 36.03 |
ACCUMULATED OTHER COMPREHENSI_2
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Analysis Of Other Comprehensive Income By Item [Abstract] | |
Components of Accumulated Other Comprehensive Income (Loss), Net of Taxes | The components of accumulated other comprehensive income (loss), net of taxes, were as follows: 2018 2017 Derivative financial instruments designated as cash flow hedges $ 13 $ 47 Foreign currency translation adjustment 109 (115 ) $ 122 $ (68 ) |
CAPITAL DISCLOSURES (Tables)
CAPITAL DISCLOSURES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Corporate Information And Statement Of IFRS Compliance [Abstract] | |
Disclosure of detailed information about capital | 2018 2017 Long-term debt, net (1) $ 20,522 $ 22,321 Total shareholders’ equity $ 31,974 $ 31,653 Debt to book capitalization 39% 41% (1) Includes the current portion of long-term debt, net of cash and cash equivalents. |
NET EARNINGS (LOSS) PER COMMO_2
NET EARNINGS (LOSS) PER COMMON SHARE (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings per share [abstract] | |
Net earnings (loss) per common share | 2018 2017 2016 Weighted average common shares outstanding – basic (thousands of shares) 1,218,798 1,175,094 1,100,471 Effect of dilutive stock options (thousands of shares) 4,960 7,729 — Weighted average common shares outstanding – diluted (thousands of shares) 1,223,758 1,182,823 1,100,471 Net earnings (loss) $ 2,591 $ 2,397 $ (204 ) Net earnings (loss) per common share – basic $ 2.13 $ 2.04 $ (0.19 ) – diluted $ 2.12 $ 2.03 $ (0.19 ) |
INTEREST AND OTHER FINANCING _2
INTEREST AND OTHER FINANCING EXPENSE (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Borrowing costs [abstract] | |
Disclosure of interest and other financing expense | 2018 2017 2016 Interest and other financing expense: Long-term debt $ 867 $ 810 $ 664 Less: amounts capitalized on qualifying assets 69 82 233 Total interest and other financing expense 798 728 431 Total interest income (59 ) (97 ) (48 ) Net interest and other financing expense $ 739 $ 631 $ 383 |
FINANCIAL INSTRUMENTS (Tables)
FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Financial Instruments [Abstract] | |
Schedule of financial assets | The carrying amounts of the Company’s financial instruments by category were as follows: 2018 Asset (liability) Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost Total Accounts receivable $ 1,148 $ — $ — $ — $ 1,148 Investments — 524 — — 524 Other long-term assets 591 12 361 — 964 Accounts payable — — — (779 ) (779 ) Accrued liabilities — — — (2,356 ) (2,356 ) Other long-term liabilities (1) — (17 ) — (118 ) (135 ) Long-term debt (2) — — — (20,623 ) (20,623 ) $ 1,739 $ 519 $ 361 $ (23,876 ) $ (21,257 ) 2017 Asset (liability) Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost Total Accounts receivable $ 2,397 $ — $ — $ — $ 2,397 Investments — 893 — — 893 Other long-term assets 510 — 204 — 714 Accounts payable — — — (775 ) (775 ) Accrued liabilities — — — (2,597 ) (2,597 ) Other long-term liabilities (3) — (38 ) (65 ) (469 ) (572 ) Long-term debt (2) — — — (22,458 ) (22,458 ) $ 2,907 $ 855 $ 139 $ (26,299 ) $ (22,398 ) (1) Includes $ 118 million of deferred purchase consideration payable over the next five years. (2) Includes the current portion of long-term debt. The fair values of the Company’s investments, recurring other long-term assets (liabilities) and fixed rate long-term debt are outlined below: 2018 Carrying amount Fair value Asset (liability) (1) (2) Level 1 Level 2 Level 3 (4) (5) Investments (3) $ 524 $ 524 $ — $ — Other long-term assets $ 964 $ — $ 373 $ 591 Other long-term liabilities $ (135 ) $ — $ (17 ) $ (118 ) Fixed rate long-term debt (6) (7) $ (15,620 ) $ (15,952 ) $ — $ — 2017 Carrying amount Fair value Asset (liability) (1) (2) Level 1 Level 2 Level 3 (5) Investments (3) $ 893 $ 893 $ — $ — Other long-term assets $ 714 $ — $ 204 $ 510 Other long-term liabilities $ (103 ) $ — $ (103 ) $ — Fixed rate long-term debt (6) (7) $ (15,989 ) $ (17,259 ) $ — $ — (1) Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and purchase consideration paid to Marathon in March 2018). (2) There were no transfers between Level 1, 2 and 3 financial instruments. (3) The fair values of the investments are based on quoted market prices. (4) The fair value of the deferred purchase consideration is based on the present value of future cash payments. (5) The fair value of Redwater Partnership subordinated debt is based on the present value of future cash receipts. (6) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (7) Includes the current portion of fixed rate long-term debt. |
Schedule of financial liabilities | The fair values of the Company’s investments, recurring other long-term assets (liabilities) and fixed rate long-term debt are outlined below: 2018 Carrying amount Fair value Asset (liability) (1) (2) Level 1 Level 2 Level 3 (4) (5) Investments (3) $ 524 $ 524 $ — $ — Other long-term assets $ 964 $ — $ 373 $ 591 Other long-term liabilities $ (135 ) $ — $ (17 ) $ (118 ) Fixed rate long-term debt (6) (7) $ (15,620 ) $ (15,952 ) $ — $ — 2017 Carrying amount Fair value Asset (liability) (1) (2) Level 1 Level 2 Level 3 (5) Investments (3) $ 893 $ 893 $ — $ — Other long-term assets $ 714 $ — $ 204 $ 510 Other long-term liabilities $ (103 ) $ — $ (103 ) $ — Fixed rate long-term debt (6) (7) $ (15,989 ) $ (17,259 ) $ — $ — (1) Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and purchase consideration paid to Marathon in March 2018). (2) There were no transfers between Level 1, 2 and 3 financial instruments. (3) The fair values of the investments are based on quoted market prices. (4) The fair value of the deferred purchase consideration is based on the present value of future cash payments. (5) The fair value of Redwater Partnership subordinated debt is based on the present value of future cash receipts. (6) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (7) Includes the current portion of fixed rate long-term debt. The carrying amounts of the Company’s financial instruments by category were as follows: 2018 Asset (liability) Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost Total Accounts receivable $ 1,148 $ — $ — $ — $ 1,148 Investments — 524 — — 524 Other long-term assets 591 12 361 — 964 Accounts payable — — — (779 ) (779 ) Accrued liabilities — — — (2,356 ) (2,356 ) Other long-term liabilities (1) — (17 ) — (118 ) (135 ) Long-term debt (2) — — — (20,623 ) (20,623 ) $ 1,739 $ 519 $ 361 $ (23,876 ) $ (21,257 ) 2017 Asset (liability) Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost Total Accounts receivable $ 2,397 $ — $ — $ — $ 2,397 Investments — 893 — — 893 Other long-term assets 510 — 204 — 714 Accounts payable — — — (775 ) (775 ) Accrued liabilities — — — (2,597 ) (2,597 ) Other long-term liabilities (3) — (38 ) (65 ) (469 ) (572 ) Long-term debt (2) — — — (22,458 ) (22,458 ) $ 2,907 $ 855 $ 139 $ (26,299 ) $ (22,398 ) (1) Includes $ 118 million of deferred purchase consideration payable over the next five years. (2) Includes the current portion of long-term debt. |
Schedule of information about financial instruments | Net (gain) loss from risk management activities for the years ended December 31 were as follows: 2018 2017 2016 Net realized risk management (gain) loss $ (99 ) $ (2 ) $ 8 Net unrealized risk management (gain) loss (35 ) 37 25 $ (134 ) $ 35 $ 33 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) 2018 2017 Derivatives held for trading Foreign currency forward contracts $ 8 $ (38 ) Crude oil WCS (1) differential swaps (17 ) — Natural gas AECO basis swaps 1 — Natural gas AECO fixed price swaps 3 — Cash flow hedges Foreign currency forward contracts 70 (71 ) Cross currency swaps 291 210 $ 356 $ 101 Included within: Current portion of other long-term assets $ 92 $ — Current portion of other long-term liabilities (17 ) (103 ) Other long-term assets 281 204 $ 356 $ 101 (1) Western Canadian Select The changes in estimated fair values of derivative financial instruments included in the risk management asset were recognized in the financial statements as follows: Asset (liability) 2018 2017 Balance – beginning of year $ 101 $ 489 Net change in fair value of outstanding derivative financial instruments recognized in: Risk management activities 35 (37 ) Foreign exchange 260 (375 ) Other comprehensive (loss) income (40 ) 24 Balance – end of year 356 101 Less: current portion 75 (103 ) $ 281 $ 204 |
Schedule of Derivative Financial Instruments Outstanding to Manage Commodity Price Risk [Table Text Block] | At December 31, 2018 , the Company had the following derivative financial instruments outstanding to manage its commodity price risk: Remaining term Volume Weighted average price Index Crude Oil WCS differential swaps Jan 2019 - Mar 2019 28,000 bbl/d US $ 17.65 WCS WCS differential swaps Jan 2019 - Sep 2019 8,000 bbl/d US $ 23.57 WCS Natural Gas AECO basis swaps Jan 2019 - Mar 2019 10,000 MMbtu/d US $ 1.39 AECO AECO fixed price swaps Jan 2019 - Mar 2019 30,000 GJ/d $ 2.30 AECO AECO fixed price swaps (1) Apr 2019 - Oct 2019 10,000 GJ/d $ 1.30 AECO (1) As at March 6, 2019, the Company has hedged an additional 105,000 GJ/d of currently forecasted natural gas volumes using AECO fixed price swaps, at a weighted average price of $1.32/GJ, for April to October 2019. |
Schedule of derivative financial instruments | At December 31, 2018 the Company had the following cross currency swap contracts outstanding: Remaining term Amount Exchange rate (US$/C$) Interest rate (US$) Interest rate (C$) Cross currency Swaps Jan 2019 — Nov 2021 US$500 1.022 3.45 % 3.96 % Jan 2019 — Mar 2038 US$550 1.170 6.25 % 5.76 % |
Disclosure of financial instrument sensitivities | The following table summarizes the annualized sensitivities of the Company’s 2018 net earnings and other comprehensive income (loss) to changes in the fair value of financial instruments outstanding as at December 31, 2018 , resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those sensitivities 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. 2018 2017 Increase (decrease) to net earnings Increase (decrease) to other comprehensive income Increase (decrease) to net earnings (Increase) decrease to other comprehensive loss Commodity price risk (1) Increase WCS differential US$1.00/bbl $ (5 ) $ — $ — $ — Decrease WCS differential US$1.00/bbl $ 5 $ — $ — $ — Increase AECO $0.10/Mcf (2) $ (1 ) $ — $ — $ — Decrease AECO $0.10/Mcf (2) $ 1 $ — $ — $ — Interest rate risk Increase interest rate 1% $ (33 ) $ (21 ) $ (42 ) $ (16 ) Decrease interest rate 1% $ 33 $ 25 $ 42 $ 19 Foreign currency exchange rate risk Increase exchange rate by US$0.01 $ (114 ) $ — $ (105 ) $ — Decrease exchange rate by US$0.01 $ 113 $ — $ 101 $ — (1) Based on the Company's contracted AECO basis swap volumes at December 31, 2018, a movement of US$0.10 /Mcf would not have a significant impact on net earnings or other comprehensive income. (2) Movements in AECO are based on the Company's contracted AECO fixed price swap volumes at December 31, 2018. |
Schedule of maturity dates for financial liabilities | Scheduled debt repayments are as follows: Year Repayment 2019 $ 1,141 2020 $ 5,996 2021 $ 1,444 2022 $ 1,003 2023 $ 1,365 Thereafter $ 9,793 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 $ 779 $ — $ — $ — Accrued liabilities $ 2,356 $ — $ — $ — Other long-term liabilities $ 42 $ 24 $ 69 $ — Long-term debt (1) (2) $ 1,141 $ 5,996 $ 3,812 $ 9,793 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. (2) In addition to the financial liabilities disclosed above, estimated interest and other financing payments related to long-term debt are as follows: less than one year, $836 million ; one to less than two years, $755 million ; two to less than five years, $1,668 million ; and thereafter, $5,327 million . Interest payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2018 . |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract] | |
Disclosure of future payments | The Company has committed to certain payments as follows: 2019 2020 2021 2022 2023 Thereafter Product transportation and pipeline $ 692 $ 664 $ 620 $ 516 $ 381 $ 3,991 North West Redwater Partnership service toll (1) $ 86 $ 126 $ 157 $ 158 $ 157 $ 2,858 Offshore equipment operating leases $ 94 $ 73 $ 75 $ 8 $ — $ — Office leases $ 42 $ 42 $ 39 $ 31 $ 32 $ 89 Other $ 85 $ 35 $ 32 $ 32 $ 31 $ 424 (1) Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service toll, which currently consists of interest and fees, with principal repayments beginning in 2020. Included in the service toll is $1,301 million of interest payable over the 30 year tolling period. See note 10. |
SUPPLEMENTAL DISCLOSURE OF CA_2
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Statement Of Cash Flows, Additional Disclosures [Abstract] | |
Schedule Of Cash Flow Supplemental Disclosures | 2018 2017 2016 Changes in non-cash working capital Accounts receivable $ 1,233 $ (977 ) $ (142 ) Current income tax assets (liabilities) 471 527 (165 ) Inventory (74 ) 81 (79 ) Prepaids and other (3 ) (28 ) 14 Accounts payable (7 ) 175 31 Accrued liabilities (268 ) 365 (116 ) Other long-term liabilities (1) (2) (351 ) 469 — Net changes in non-cash working capital $ 1,001 $ 612 $ (457 ) Relating to: Operating activities $ 1,346 $ 299 $ (542 ) Investing activities (345 ) 313 85 $ 1,001 $ 612 $ (457 ) 2018 2017 2016 Expenditures on exploration and evaluation assets $ 282 $ 159 $ 29 Net proceeds on sale of exploration and evaluation assets (16 ) (35 ) (35 ) Net expenditures (proceeds) on exploration and evaluation assets $ 266 $ 124 $ (6 ) Expenditures on property, plant and equipment $ 4,175 $ 4,574 $ 4,152 Net proceeds on sale of property, plant and equipment (3) — — (349 ) Net expenditures on property, plant and equipment $ 4,175 $ 4,574 $ 3,803 (1) Included in other long-term liabilities at December 31, 2018 is $118 million of deferred purchase consideration payable over the next five years. (2) Included in other long-term liabilities at December 31, 2017 is $469 million ( US$375 million ) of deferred purchase consideration paid to Marathon. (3) Net expenditures on property, plant and equipment in 2016 exclude non-cash share consideration of $190 million received from Inter Pipeline on the disposition of the Company's interest in the Cold Lake Pipeline. |
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, 2018 and 2017: Long-term debt Cash flow hedges on US dollar debt securities Liabilities from financing activities At December 31, 2016 $ 16,805 $ (485 ) $ 16,320 Changes from financing cash flows: Issue of long-term debt, net (1) 6,622 — 6,622 Settlement of hedge instruments, net — 124 124 Changes in foreign exchange and fair value (2) (969 ) 222 (747 ) At December 31, 2017 $ 22,458 $ (139 ) $ 22,319 Changes from financing cash flows: Repayment of long-term debt, net (1) (2,831 ) — (2,831 ) Changes in foreign exchange and fair value (2) 996 (222 ) 774 At December 31, 2018 $ 20,623 $ (361 ) $ 20,262 (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 and the amortization of original issue discounts and premiums and directly attributable transaction costs. |
SEGMENTED INFORMATION (Tables)
SEGMENTED INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Operating Segments [Abstract] | |
Disclosure of operating segments | Oil Sands Mining and Upgrading Midstream Inter–segment elimination and Other Total 2018 2017 2016 2018 2017 2016 2018 2017 2016 2018 2017 2016 $ 11,521 $ 7,072 $ 2,657 $ 102 $ 102 $ 114 $ 410 $ 448 $ 682 $ 20,668 $ 16,522 $ 10,396 — — — — — — 148 161 167 1,614 1,838 1,606 11,521 7,072 2,657 102 102 114 558 609 849 22,282 18,360 12,002 (479 ) (167 ) (24 ) — — — — — — (1,255 ) (1,018 ) (575 ) 11,042 6,905 2,633 102 102 114 558 609 849 21,027 17,342 11,427 3,367 2,600 1,292 21 16 25 58 71 78 6,464 5,675 4,184 1,087 679 80 — — — 491 527 751 4,189 3,529 2,822 1,557 1,220 662 14 9 11 — — — 5,161 5,186 4,858 61 48 29 — — — — — — 186 164 142 — — — — — — — — — (10 ) (45 ) 6 — (230 ) — — (114 ) (218 ) — — — (452 ) (379 ) (250 ) — — — 5 (31 ) (7 ) — — — 5 (31 ) (7 ) 6,072 4,317 2,063 40 (120 ) (189 ) 549 598 829 15,543 14,099 11,755 $ 4,970 $ 2,588 $ 570 $ 62 $ 222 $ 303 $ 9 $ 11 $ 20 $ 5,484 $ 3,243 $ (328 ) 325 319 345 (146 ) 134 355 739 631 383 (124 ) 80 27 827 (787 ) (55 ) 341 (7 ) (320 ) 1,962 370 735 3,522 2,873 (1,063 ) 374 (164 ) (618 ) 557 640 (241 ) $ 2,591 $ 2,397 $ (204 ) North America North Sea Offshore Africa (millions of Canadian dollars) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Segmented product sales Crude oil and NGLs $ 7,254 $ 7,655 $ 5,933 $ 753 $ 666 $ 478 $ 628 $ 579 $ 532 Natural gas 1,256 1,506 1,276 140 118 92 70 53 71 Total segmented product sales 8,510 9,161 7,209 893 784 570 698 632 603 Less: royalties (723 ) (809 ) (524 ) (2 ) (1 ) (1 ) (51 ) (41 ) (26 ) Segmented revenue 7,787 8,352 6,685 891 783 569 647 591 577 Segmented expenses Production 2,405 2,362 2,186 405 400 403 208 226 200 Transportation, blending and feedstock 2,587 2,291 1,941 22 31 48 2 1 2 Depletion, depreciation and amortization 3,132 3,243 3,465 257 509 458 201 205 262 Asset retirement obligation accretion 87 80 66 29 27 35 9 9 12 Realized risk management (commodity derivatives) (10 ) (45 ) 6 — — — — — — Gain on acquisition, disposition and revaluation of properties (277 ) (35 ) (32 ) (139 ) — — (36 ) — — Equity loss (gain) from investments — — — — — — — — — Total segmented expenses 7,924 7,896 7,632 574 967 944 384 441 476 Segmented earnings (loss) before the following $ (137 ) $ 456 $ (947 ) $ 317 $ (184 ) $ (375 ) $ 263 $ 150 $ 101 Non–segmented expenses Administration Share-based compensation Interest and other financing expense Risk management activities (other) Foreign exchange loss (gain) Loss (gain) from investments Total non–segmented expenses Earnings (loss) before taxes Current income tax expense (recovery) Deferred income tax expense (recovery) Net earnings (loss) 2018 2017 Exploration and Production North America $ 27,199 $ 28,705 North Sea 1,699 1,854 Offshore Africa 1,471 1,331 Other 33 29 Oil Sands Mining and Upgrading 39,634 40,559 Midstream 1,413 1,279 Head office 110 110 $ 71,559 $ 73,867 2018 2017 Net expenditures Non-cash and fair value changes Capitalized costs Net expenditures (2) Non-cash and fair value changes (2) Capitalized costs Exploration and evaluation assets Exploration and Production North America (3) $ 118 $ (52 ) $ 66 $ 160 $ (184 ) $ (24 ) North Sea — — — — — — Offshore Africa (4) (54 ) — (54 ) 15 — 15 Oil Sands Mining and Upgrading 218 (225 ) (7 ) 142 117 259 $ 282 $ (277 ) $ 5 $ 317 $ (67 ) $ 250 Property, plant and equipment Exploration and Production North America $ 2,553 $ (362 ) $ 2,191 $ 2,815 $ 354 $ 3,169 North Sea 131 (597 ) (466 ) 160 95 255 Offshore Africa 228 (86 ) 142 89 12 101 2,912 (1,045 ) 1,867 3,064 461 3,525 Oil Sands Mining and Upgrading (5) 1,229 (166 ) 1,063 9,592 5,454 15,046 Midstream (6) 13 — 13 80 114 194 Head office 21 — 21 19 — 19 $ 4,175 $ (1,211 ) $ 2,964 $ 12,755 $ 6,029 $ 18,784 (1) This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments. (2) Net expenditures on exploration and evaluation assets and property, plant and equipment for the year ended December 31, 2017 exclude non-cash share consideration of $3,818 million issued on the acquisition of AOSP and other assets. This non-cash consideration is included in non-cash and other fair value changes. (3) The above noted figures for 2017 exclude the impact of a pre-tax cash gain of $35 million on the disposition of certain exploration and evaluation assets. (4) The above noted figures for 2018 exclude the impact of a pre-tax cash gain of $16 million on the disposition of certain exploration and evaluation assets. (5) Net expenditures for Oil Sands Mining and Upgrading include capitalized interest and share-based compensation. (6) Included in 2017 is the impact of a pre-tax non-cash revaluation gain of $114 million ( $83 million after-tax) related to a previously held joint interest in a pipeline system. |
REMUNERATION OF DIRECTORS AND_2
REMUNERATION OF DIRECTORS AND SENIOR MANAGEMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Related Party [Abstract] | |
Remuneration of non-management directors and senior management | Remuneration of Non-Management Directors 2018 2017 2016 Fees earned $ 2 $ 3 $ 2 Remuneration of Senior Management (1) 2018 2017 2016 Salary $ 2 $ 3 $ 3 Common stock option based awards 8 10 9 Annual incentive plans 4 5 5 Long-term incentive plans 15 17 15 $ 29 $ 35 $ 32 (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 & GAS INFOR_2
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Schedule of Twelve Month Average Benchmark Prices | The Company has used the following 12-month average benchmark prices to determine its 2018 reserves for SEC requirements. Crude Oil and NGLs Natural Gas WTI Cushing Oklahoma WCS Canadian Light Sweet Cromer LSB North Sea Brent Edmonton C5+ Henry Hub Louisiana AECO BC Westcoast Station 2 (US$/bbl) (C$/bbl) (C$/bbl) (C$/bbl) (US$/bbl) (C$/bbl) (US$/MMBtu) (C$/MMBtu) (C$/MMBtu) 65.55 53.67 70.32 75.54 72.09 80.65 3.02 1.46 1.25 |
Schedule of 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, 2018 , 2017 , 2016 , and 2015 : North America Crude Oil and NGLs (MMbbl) Synthetic Crude Oil Bitumen (1) Crude Oil & NGLs North America Total North Sea Offshore Africa Total Net Proved Reserves Reserves, December 31, 2015 2,283 1,263 471 4,017 119 73 4,209 Extensions and discoveries — 46 15 61 — — 61 Improved recovery — 5 14 19 1 2 22 Purchases of reserves in place — 3 15 18 — — 18 Sales of reserves in place — — — — — — — Production (45 ) (71 ) (43 ) (159 ) (9 ) (8 ) (176 ) Economic revisions due to prices 108 23 (19 ) 112 (10 ) 1 103 Revisions of prior estimates 196 32 51 279 (8 ) 6 277 Reserves, December 31, 2016 2,542 1,301 504 4,347 93 74 4,514 Extensions and discoveries — 28 17 45 — — 45 Improved recovery — 7 19 26 1 — 27 Purchases of reserves in place 2,232 37 67 2,336 — — 2,336 Sales of reserves in place — — — — — — — Production (100 ) (70 ) (44 ) (214 ) (9 ) (6 ) (229 ) Economic revisions due to prices — 18 17 35 18 1 54 Revisions of prior estimates 282 44 14 340 4 — 344 Reserves, December 31, 2017 4,956 1,365 594 6,915 107 69 7,091 Extensions and discoveries 744 151 17 912 — — 912 Improved recovery — 10 50 60 1 3 64 Purchases of reserves in place — 2 7 9 7 — 16 Sales of reserves in place — (4 ) — (4 ) — — (4 ) Production (148 ) (64 ) (47 ) (259 ) (9 ) (6 ) (274 ) Economic revisions due to prices — (45 ) (18 ) (63 ) 11 1 (51 ) Revisions of prior estimates 109 54 1 164 (3 ) 4 165 Reserves, December 31, 2018 5,661 1,469 604 7,734 114 71 7,919 Net proved developed reserves December 31, 2015 2,194 411 341 2,946 3 41 2,990 December 31, 2016 2,527 384 353 3,264 12 31 3,307 December 31, 2017 4,967 410 399 5,776 28 21 5,825 December 31, 2018 5,661 461 378 6,500 37 34 6,571 (1) 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. Natural Gas (Bcf) North America North Sea Offshore Africa Total Net Proved Reserves Reserves, December 31, 2015 4,523 38 21 4,582 Extensions and discoveries 176 — — 176 Improved recovery 166 — 3 169 Purchases of reserves in place 85 — — 85 Sales of reserves in place (5 ) — — (5 ) Production (571 ) (14 ) (11 ) (596 ) Economic revisions due to prices (572 ) (10 ) 1 (581 ) Revisions of prior estimates 792 11 11 814 Reserves, December 31, 2016 4,594 25 25 4,644 Extensions and discoveries 261 — — 261 Improved recovery 179 — — 179 Purchases of reserves in place 106 — — 106 Sales of reserves in place — — — — Production (558 ) (14 ) (7 ) (579 ) Economic revisions due to prices 403 5 (1 ) 407 Revisions of prior estimates 214 9 (1 ) 222 Reserves, December 31, 2017 5,199 25 16 5,240 Extensions and discoveries 90 — — 90 Improved recovery 414 — — 414 Purchases of reserves in place 67 — — 67 Sales of reserves in place (3 ) — — (3 ) Production (523 ) (11 ) (8 ) (542 ) Economic revisions due to prices (746 ) — (2 ) (748 ) Revisions of prior estimates (192 ) 13 15 (164 ) Reserves, December 31, 2018 4,306 27 21 4,354 Net proved developed reserves December 31, 2015 2,883 26 15 2,924 December 31, 2016 2,805 18 18 2,841 December 31, 2017 3,081 22 9 3,112 December 31, 2018 2,382 23 12 2,417 |
Schedule of Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure | Capitalized Costs Related to Crude Oil and Natural Gas Activities 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 110,154 $ 7,321 $ 5,471 $ 122,946 Unproved properties 2,600 — 37 2,637 112,754 7,321 5,508 125,583 Less: accumulated depletion and depreciation (48,862 ) (5,735 ) (4,203 ) (58,800 ) Net capitalized costs $ 63,892 $ 1,586 $ 1,305 $ 66,783 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 106,900 $ 7,126 $ 4,881 $ 118,907 Unproved properties 2,541 — 91 2,632 109,441 7,126 4,972 121,539 Less: accumulated depletion and depreciation (44,779 ) (5,653 ) (3,719 ) (54,151 ) Net capitalized costs $ 64,662 $ 1,473 $ 1,253 $ 67,388 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Proved properties $ 88,685 $ 7,380 $ 5,132 $ 101,197 Unproved properties 2,306 — 76 2,382 90,991 7,380 5,208 103,579 Less: accumulated depletion and depreciation (41,139 ) (5,584 ) (3,797 ) (50,520 ) Net capitalized costs $ 49,852 $ 1,796 $ 1,411 $ 53,059 |
Disclosure of Detailed Information About Costs Incurred In Crude Oil And Natural Gas Activities | Costs Incurred in Crude Oil and Natural Gas Activities 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 214 $ 127 $ — $ 341 Unproved 340 — (89 ) 251 Exploration 116 — 35 151 Development 3,245 110 212 3,567 Costs incurred $ 3,915 $ 237 $ 158 $ 4,310 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 15,091 $ — $ — $ 15,091 Unproved 321 — — 321 Exploration 112 — 15 127 Development 3,753 255 101 4,109 Costs incurred $ 19,277 $ 255 $ 116 $ 19,648 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Property acquisitions Proved $ 50 $ — $ — $ 50 Unproved — — — — Exploration 17 — 9 26 Development 4,125 186 116 4,427 Costs incurred $ 4,192 $ 186 $ 125 $ 4,503 |
Disclosure Of Detailed Information About Results Of Operations From Crude Oil And Natural Gas Activities [Table Text Block] | The Company's results of operations from crude oil and natural gas producing activities for the years ended December 31, 2018, 2017, and 2016 are summarized in the following tables: 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 16,065 $ 891 $ 647 $ 17,603 Production (5,772 ) (405 ) (208 ) (6,385 ) Transportation (929 ) (22 ) (2 ) (953 ) Depletion, depreciation and amortization (4,689 ) (257 ) (201 ) (5,147 ) Asset retirement obligation accretion (148 ) (29 ) (9 ) (186 ) Petroleum revenue tax — 12 — 12 Income tax (1,223 ) (76 ) (51 ) (1,350 ) Results of operations $ 3,304 $ 114 $ 176 $ 3,594 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 13,083 $ 784 $ 578 $ 14,445 Production (4,962 ) (400 ) (226 ) (5,588 ) Transportation (790 ) (31 ) (1 ) (822 ) Depletion, depreciation and amortization (4,463 ) (509 ) (205 ) (5,177 ) Asset retirement obligation accretion (128 ) (27 ) (9 ) (164 ) Petroleum revenue tax — 78 — 78 Income tax (740 ) 42 (28 ) (726 ) Results of operations $ 2,000 $ (63 ) $ 109 $ 2,046 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Crude oil and natural gas revenue, net of royalties, blending and feedstock costs $ 7,791 $ 565 $ 577 $ 8,933 Production (3,478 ) (403 ) (200 ) (4,081 ) Transportation (623 ) (48 ) (2 ) (673 ) Depletion, depreciation and amortization (4,127 ) (458 ) (262 ) (4,847 ) Asset retirement obligation accretion (95 ) (35 ) (12 ) (142 ) Petroleum revenue tax — 333 — 333 Income tax 143 18 (22 ) 139 Results of operations $ (389 ) $ (28 ) $ 79 $ (338 ) |
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": 2018 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 500,557 $ 12,002 $ 6,447 $ 519,006 Future production costs (193,387 ) (5,148 ) (2,284 ) (200,819 ) Future development costs and asset retirement obligations (63,202 ) (2,909 ) (1,099 ) (67,210 ) Future income taxes (60,526 ) (1,484 ) (626 ) (62,636 ) Future net cash flows 183,442 2,461 2,438 188,341 10% annual discount for timing of future cash flows (126,699 ) (545 ) (771 ) (128,015 ) Standardized measure of future net cash flows $ 56,743 $ 1,916 $ 1,667 $ 60,326 2017 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 413,180 $ 8,740 $ 4,786 $ 426,706 Future production costs (198,304 ) (4,168 ) (1,876 ) (204,348 ) Future development costs and asset retirement obligations (61,169 ) (2,853 ) (1,258 ) (65,280 ) Future income taxes (35,645 ) (595 ) (248 ) (36,488 ) Future net cash flows 118,062 1,124 1,404 120,590 10% annual discount for timing of future cash flows (73,171 ) (59 ) (455 ) (73,685 ) Standardized measure of future net cash flows $ 44,891 $ 1,065 $ 949 $ 46,905 2016 (millions of Canadian dollars) North America North Sea Offshore Africa Total Future cash inflows $ 206,729 $ 5,999 $ 4,129 $ 216,857 Future production costs (92,070 ) (3,284 ) (1,659 ) (97,013 ) Future development costs and asset retirement obligations (42,167 ) (3,249 ) (1,234 ) (46,650 ) Future income taxes (15,396 ) 280 (125 ) (15,241 ) Future net cash flows 57,096 (254 ) 1,111 57,953 10% annual discount for timing of future cash flows (33,590 ) 271 (319 ) (33,638 ) Standardized measure of future net cash flows $ 23,506 $ 17 $ 792 $ 24,315 |
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) 2018 2017 2016 Sales of crude oil and natural gas produced, net of production costs $ (10,229 ) $ (8,013 ) $ (4,159 ) Net changes in sales prices and production costs 20,386 7,466 (7,305 ) Extensions, discoveries and improved recovery 2,807 481 700 Changes in estimated future development costs (698 ) (5,548 ) 1,750 Purchases of proved reserves in place 396 25,782 352 Sales of proved reserves in place (55 ) — (2 ) Revisions of previous reserve estimates 2,711 4,245 3,668 Accretion of discount 6,119 3,075 3,527 Changes in production timing and other (955 ) (662 ) (2,137 ) Net change in income taxes (7,061 ) (4,236 ) 385 Net change 13,421 22,590 (3,221 ) Balance - beginning of year 46,905 24,315 27,536 Balance - end of year $ 60,326 $ 46,905 $ 24,315 |
ACCOUNTING POLICIES - Narrative
ACCOUNTING POLICIES - Narrative (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Bottom of range | Midstream | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life | 5 years |
Bottom of range | Other equipment | Oil Sands Mining and Upgrading | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life | 2 years |
Top of range | Midstream | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life | 30 years |
Top of range | Other equipment | Oil Sands Mining and Upgrading | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Estimated useful life | 18 years |
Performance Share Units | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Vesting term | 3 years |
ACCOUNTING STANDARDS ISSUED B_2
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED - Narrative (Details) - Adjustment on adoption of IFRS 16 $ in Billions | Jan. 01, 2019CAD ($) |
Bottom of range | |
Disclosure of finance lease and operating lease by lessee [line items] | |
Right-of-use assets | $ 1.5 |
Lease liabilities | 1.5 |
Top of range | |
Disclosure of finance lease and operating lease by lessee [line items] | |
Right-of-use assets | 1.6 |
Lease liabilities | $ 1.6 |
CRITICAL ACCOUNTING ESTIMATES_2
CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS - Narrative (Details) | Dec. 31, 2018 |
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 | 10.00% |
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 | 12.00% |
INVENTORY - Schedule of Invento
INVENTORY - Schedule of Inventory (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Inventories [Abstract] | ||
Product inventory | $ 297 | $ 285 |
Materials and supplies | 658 | 609 |
Total inventory | $ 955 | $ 894 |
INVENTORY - Narrative (Details)
INVENTORY - Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Inventories [Abstract] | ||
Write-down of product inventory | $ 13 | $ 33 |
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, 2018 | Dec. 31, 2017 | |
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||
Beginning balance | $ 2,632 | $ 2,382 |
Additions | 502 | 159 |
Acquisition of AOSP and other assets (note 7) | 290 | |
Transfers to property, plant and equipment | (397) | (198) |
Disposals/derecognitions | (100) | (1) |
Ending balance | 2,637 | 2,632 |
North America | ||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||
Beginning balance | 2,282 | 2,306 |
Additions | 245 | 144 |
Acquisition of AOSP and other assets (note 7) | 31 | |
Transfers to property, plant and equipment | (175) | (198) |
Disposals/derecognitions | (4) | (1) |
Ending balance | 2,348 | 2,282 |
North Sea | ||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||
Beginning balance | 0 | 0 |
Additions | 0 | 0 |
Acquisition of AOSP and other assets (note 7) | 0 | |
Transfers to property, plant and equipment | 0 | 0 |
Disposals/derecognitions | 0 | 0 |
Ending balance | 0 | 0 |
Offshore Africa | ||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||
Beginning balance | 91 | 76 |
Additions | 35 | 15 |
Acquisition of AOSP and other assets (note 7) | 0 | |
Transfers to property, plant and equipment | 0 | 0 |
Disposals/derecognitions | (89) | 0 |
Ending balance | 37 | 91 |
Oil Sands Mining and Upgrading | ||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||
Beginning balance | 259 | 0 |
Additions | 222 | 0 |
Acquisition of AOSP and other assets (note 7) | 259 | |
Transfers to property, plant and equipment | (222) | 0 |
Disposals/derecognitions | (7) | 0 |
Ending balance | $ 252 | $ 259 |
EXPLORATION AND EVALUATION AS_4
EXPLORATION AND EVALUATION ASSETS - Narrative (Details) $ in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018USD ($)agreement | Dec. 31, 2018CAD ($)agreement | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2018CAD ($) | May 31, 2017CAD ($) | |
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Disposals of exploration and evaluation assets | $ 100 | $ 1 | ||||
Proceeds from disposal of exploration and evaluation assets | $ 16 | 35 | $ 35 | |||
Farm-out agreements, working interest retained | 20.00% | 20.00% | ||||
Oil Sands Mining and Upgrading | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Disposals of exploration and evaluation assets | $ 7 | 0 | ||||
North America | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Asset retirement obligations | $ 13 | |||||
Disposals of exploration and evaluation assets | 4 | 1 | ||||
Proceeds from disposal of exploration and evaluation assets | 36 | |||||
Gain on sale of exploration and evaluation assets | $ 16 | 35 | ||||
Offshore Africa | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Number of farm-out agreements | agreement | 2 | 2 | ||||
Disposals of exploration and evaluation assets | $ 89 | $ 0 | ||||
Joslyn Oil Sands Project | Oil Sands Mining and Upgrading | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Exploration and evaluation assets recognized as of acquisition date | 222 | |||||
Asset retirement obligations | 4 | |||||
Total purchase consideration | 218 | |||||
Cash transferred | 100 | |||||
Laricina Energy Ltd | North America | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Exploration and evaluation assets recognized as of acquisition date | 118 | |||||
Asset retirement obligations | 17 | |||||
Total purchase consideration | 46 | |||||
Property, plant and equipment | 44 | |||||
Cash | 24 | |||||
Deferred tax assets recognised as of acquisition date | 168 | |||||
Net working capital liabilities recognised as of acquisition date | 18 | |||||
Notes payable recognised as of acquisition date | $ 48 | |||||
Gain recognised on acquisition, pre-tax | $ 225 | |||||
AOSP | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Exploration and evaluation assets recognized as of acquisition date | $ 290 | |||||
Asset retirement obligations | 721 | |||||
Total purchase consideration | 12,541 | |||||
Cash transferred | 8,217 | |||||
Property, plant and equipment | 14,181 | |||||
Cash | $ 93 | |||||
Farm-Out Agreements, Offshore Africa [Member] | Offshore Africa | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Farm-out agreements, working interest disposed | 30.00% | 30.00% | ||||
Disposals of exploration and evaluation assets | $ 89 | |||||
Disposals of exploration and evaluation assets, costs incurred in past fiscal year recovered | 14 | |||||
Proceeds from disposal of exploration and evaluation assets | $ 79 | 105 | ||||
Gain recognised on farm-out, pre-tax | 16 | |||||
Gain recognised on farm-out, after-tax | $ 12 | |||||
Bottom of range | Crude Oil and NGLs | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Estimated financial effect of contingent assets | 623 | |||||
Bottom of range | Natural Gas | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Estimated financial effect of contingent assets | 126 | |||||
Top of range | Crude Oil and NGLs | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Estimated financial effect of contingent assets | 645 | |||||
Top of range | Natural Gas | ||||||
Disclosure Of Detailed Information About Exploration For And Evaluation Of Mineral Resources [Line Items] | ||||||
Estimated financial effect of contingent assets | $ 132 |
PROPERTY, PLANT AND EQUIPMENT -
PROPERTY, PLANT AND EQUIPMENT - Detailed information about property, plant and equipment (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | $ (65,170) | |
Ending balance | (64,559) | $ (65,170) |
Revaluation pre-tax gain | 19 | 114 |
Project costs not subject to depletion and depreciation | 1,424 | 944 |
Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (119,749) | (101,826) |
Additions | 3,961 | 5,232 |
Acquisition of AOSP and other assets (note 7) | 14,181 | |
Transfers from E&E assets | 397 | 198 |
Disposals/derecognitions | (1,394) | (827) |
Foreign exchange adjustments and other | (1,109) | 861 |
Ending balance | (123,822) | (119,749) |
Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 54,579 | 50,916 |
Disposals/derecognitions | 1,375 | 827 |
Foreign exchange adjustments and other | 898 | (696) |
Expense | 5,161 | 5,186 |
Ending balance | 59,263 | 54,579 |
North Sea | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Additions | 108 | |
Revaluation pre-tax gain | 19 | |
Midstream | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Revaluation pre-tax gain | 114 | 114 |
Operating segments | North America | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (23,665) | |
Ending balance | (23,126) | (23,665) |
Operating segments | North America | Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (64,816) | (61,647) |
Additions | 2,428 | 3,003 |
Acquisition of AOSP and other assets (note 7) | 349 | |
Transfers from E&E assets | 175 | 198 |
Disposals/derecognitions | (412) | (381) |
Foreign exchange adjustments and other | 0 | 0 |
Ending balance | (67,007) | (64,816) |
Operating segments | North America | Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 41,151 | 38,311 |
Disposals/derecognitions | 393 | 381 |
Foreign exchange adjustments and other | 12 | 1 |
Expense | 3,111 | 3,220 |
Ending balance | 43,881 | 41,151 |
Operating segments | North Sea | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (1,473) | |
Ending balance | (1,586) | (1,473) |
Operating segments | North Sea | Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (7,126) | (7,380) |
Additions | 237 | 255 |
Acquisition of AOSP and other assets (note 7) | 0 | |
Transfers from E&E assets | 0 | 0 |
Disposals/derecognitions | (703) | 0 |
Foreign exchange adjustments and other | (661) | 509 |
Ending balance | (7,321) | (7,126) |
Operating segments | North Sea | Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 5,653 | 5,584 |
Disposals/derecognitions | 703 | 0 |
Foreign exchange adjustments and other | 528 | (440) |
Expense | 257 | 509 |
Ending balance | 5,735 | 5,653 |
Operating segments | Offshore Africa | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (1,162) | |
Ending balance | (1,268) | (1,162) |
Operating segments | Offshore Africa | Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (4,881) | (5,132) |
Additions | 212 | 101 |
Acquisition of AOSP and other assets (note 7) | 0 | |
Transfers from E&E assets | 0 | 0 |
Disposals/derecognitions | (70) | 0 |
Foreign exchange adjustments and other | (448) | 352 |
Ending balance | (5,471) | (4,881) |
Operating segments | Offshore Africa | Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 3,719 | 3,797 |
Disposals/derecognitions | 70 | 0 |
Foreign exchange adjustments and other | 353 | (283) |
Expense | 201 | 205 |
Ending balance | 4,203 | 3,719 |
Operating segments | Oil Sands Mining and Upgrading | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (38,456) | |
Ending balance | (38,166) | (38,456) |
Operating segments | Oil Sands Mining and Upgrading | Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (42,084) | (27,038) |
Additions | 1,050 | 1,660 |
Acquisition of AOSP and other assets (note 7) | 13,832 | |
Transfers from E&E assets | 222 | 0 |
Disposals/derecognitions | (209) | (446) |
Foreign exchange adjustments and other | 0 | 0 |
Ending balance | (43,147) | (42,084) |
Operating segments | Oil Sands Mining and Upgrading | Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 3,628 | 2,828 |
Disposals/derecognitions | 209 | 446 |
Foreign exchange adjustments and other | 5 | 26 |
Expense | 1,557 | 1,220 |
Ending balance | 4,981 | 3,628 |
Operating segments | Midstream | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (304) | |
Ending balance | (303) | (304) |
Operating segments | Midstream | Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (428) | (234) |
Additions | 13 | 194 |
Acquisition of AOSP and other assets (note 7) | 0 | |
Transfers from E&E assets | 0 | 0 |
Disposals/derecognitions | 0 | 0 |
Foreign exchange adjustments and other | 0 | 0 |
Ending balance | (441) | (428) |
Operating segments | Midstream | Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 124 | 115 |
Disposals/derecognitions | 0 | 0 |
Foreign exchange adjustments and other | 0 | 0 |
Expense | 14 | 9 |
Ending balance | 138 | 124 |
Head office | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (110) | |
Ending balance | (110) | (110) |
Head office | Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | (414) | (395) |
Additions | 21 | 19 |
Acquisition of AOSP and other assets (note 7) | 0 | |
Transfers from E&E assets | 0 | 0 |
Disposals/derecognitions | 0 | 0 |
Foreign exchange adjustments and other | 0 | 0 |
Ending balance | (435) | (414) |
Head office | Accumulated depletion and depreciation | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Beginning balance | 304 | 281 |
Disposals/derecognitions | 0 | 0 |
Foreign exchange adjustments and other | 0 | 0 |
Expense | 21 | 23 |
Ending balance | $ 325 | $ 304 |
PROPERTY, PLANT AND EQUIPMENT_2
PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | May 31, 2017 | |
Disclosure of detailed information about property, plant and equipment [line items] | |||||
Revaluation pre-tax gain | $ 19,000,000 | $ 114,000,000 | |||
Return of asset retirement obligations upon disposal of property | $ 69,000,000 | 69,000,000 | |||
Disposals of property, plant and equipment pre-tax gain | 20,000,000 | ||||
Disposals of property, plant and equipment after-tax gain | 14,000,000 | ||||
Interest costs capitalized | $ 69,000,000 | $ 82,000,000 | $ 233,000,000 | ||
Weighted average capitalization rate | 3.90% | 3.80% | 3.90% | ||
North America | |||||
Disclosure of detailed information about property, plant and equipment [line items] | |||||
Net cash paid for consideration for acquisition of exploration and evaluation assets | $ 170,000,000 | ||||
Asset retirement obligations | 13,000,000 | 13,000,000 | |||
Deferred tax liabilities | 0 | 0 | |||
Gains on acquisitions of property, plant and equipment, pre-tax | 47,000,000 | ||||
Acquired exploration and evaluation assets | $ 27,000,000 | $ 0 | |||
North Sea | |||||
Disclosure of detailed information about property, plant and equipment [line items] | |||||
Asset retirement obligations | 41,000,000 | 41,000,000 | |||
Deferred tax liabilities | 27,000,000 | 27,000,000 | |||
Gains on acquisitions of property, plant and equipment, pre-tax | 120,000,000 | ||||
Property, plant and equipment acquisition | 108,000,000 | ||||
Net proceeds received for acquisition of property, plant and equipment | 73,000,000 | ||||
Net working capital assets recognised, property, plant and equipment acquisition | $ 7,000,000 | 7,000,000 | |||
Revaluation pre-tax gain | 19,000,000 | ||||
North America, Exploration and Production segment and Midstream segment | |||||
Disclosure of detailed information about property, plant and equipment [line items] | |||||
Net cash paid for consideration for acquisition of exploration and evaluation assets | 1,013,000,000 | 159,000,000 | |||
Asset retirement obligations | 63,000,000 | 30,000,000 | |||
Deferred tax liabilities | 0 | $ 0 | |||
Midstream | |||||
Disclosure of detailed information about property, plant and equipment [line items] | |||||
Revaluation pre-tax gain | 114,000,000 | 114,000,000 | |||
Revaluation after-tax gain | $ 83,000,000 | $ 83,000,000 | |||
AOSP | |||||
Disclosure of detailed information about property, plant and equipment [line items] | |||||
Asset retirement obligations | $ 721,000,000 | ||||
Deferred tax liabilities | $ 1,287,000,000 |
ACQUISITION OF INTERESTS IN T_3
ACQUISITION OF INTERESTS IN THE ATHABASCA OIL SANDS PROJECT AND OTHER ASSETS - Narrative (Details) shares in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017CAD ($) | Dec. 31, 2018CAD ($) | May 31, 2017USD ($)shares | May 31, 2017CAD ($)shares | |
Disclosure of detailed information about business combination [line items] | ||||
Borrowings | $ 22,458,000,000 | $ 20,623,000,000 | ||
Non-revolving term credit facility maturing May 2020 | ||||
Disclosure of detailed information about business combination [line items] | ||||
Non-revolving term loan facility | 3,000,000,000 | $ 1,800,000,000 | ||
AOSP | ||||
Disclosure of detailed information about business combination [line items] | ||||
Interest acquired | 70.00% | 70.00% | ||
Total purchase consideration | $ 12,541,000,000 | |||
Cash transferred | $ 8,217,000,000 | |||
Common shares issued (in shares) | shares | 97.6 | 97.6 | ||
Fair value of share considerations issued | 3,818,000,000 | $ 3,818,000,000 | ||
Deferred purchase consideration payable | $ 375 | 506,000,000 | ||
Gain on acquisition, net of transaction costs | 230,000,000 | |||
Acquisition related transaction costs | $ 3,000,000 | |||
AOSP | Medium-term notes | ||||
Disclosure of detailed information about business combination [line items] | ||||
Borrowings | 1,800,000,000 | |||
AOSP | Long-term debt | ||||
Disclosure of detailed information about business combination [line items] | ||||
Borrowings | $ 3,000 | |||
AOSP | Non-revolving term credit facility maturing May 2020 | ||||
Disclosure of detailed information about business combination [line items] | ||||
Non-revolving term loan facility | $ 3,000,000,000 | |||
AOSP, Mining And Extraction Operations | ||||
Disclosure of detailed information about business combination [line items] | ||||
Interest acquired | 70.00% | 70.00% | ||
AOSP, Scotford Upgrader And Quest Carbon Capture And Storage Project | ||||
Disclosure of detailed information about business combination [line items] | ||||
Interest acquired | 70.00% | 70.00% | ||
AOSP, Peace River Thermal In Situ Operations And Cliffdale Heavy Oil Field | ||||
Disclosure of detailed information about business combination [line items] | ||||
Interest acquired | 100.00% | 100.00% |
ACQUISITION OF INTERESTS IN T_4
ACQUISITION OF INTERESTS IN THE ATHABASCA OIL SANDS PROJECT AND OTHER ASSETS - Summary of Net Assets Acquired and Liabilities Assumed (Details) - AOSP - CAD ($) $ in Millions | May 31, 2017 | Dec. 31, 2017 |
Disclosure of detailed information about business combination [line items] | ||
Cash | $ 93 | |
Other working capital | 291 | $ 291 |
Property, plant and equipment | 14,181 | |
Exploration and evaluation assets | 290 | |
Asset retirement obligations | (721) | |
Other long-term liabilities | (73) | |
Deferred income taxes | (1,287) | |
Net assets acquired | 12,774 | |
Total purchase consideration | 12,541 | |
Gain on acquisition before transaction costs | $ 233 |
INVESTMENTS - Summary of Invest
INVESTMENTS - Summary of Investments (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Disclosure of detailed information about financial instruments [line items] | ||
Investments | $ 524 | $ 893 |
Investment in PrairieSky Royalty Ltd. | ||
Disclosure of detailed information about financial instruments [line items] | ||
Investments | 400 | 726 |
Investment in Inter Pipeline Ltd. | ||
Disclosure of detailed information about financial instruments [line items] | ||
Investments | $ 124 | $ 167 |
INVESTMENTS - Narrative (Detail
INVESTMENTS - Narrative (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2018 | |
Investment in PrairieSky Royalty Ltd. | ||
Disclosure of detailed information about financial instruments [line items] | ||
Number of shares held as investment (in shares) | 22.6 | |
Investment in Inter Pipeline Ltd. | ||
Disclosure of detailed information about financial instruments [line items] | ||
Number of shares held as investment (in shares) | 6.4 | |
Disposal of Cold Lake Pipeline | Investment in Inter Pipeline Ltd. | ||
Disclosure of detailed information about financial instruments [line items] | ||
Non-cash share consideration received | $ 190 | |
Non-cash share consideration received (in shares) | 6.4 | |
Non-cash share consideration received, price per share (in CAD per share) | $ 29.57 |
INVESTMENTS - PrairieSky (Detai
INVESTMENTS - PrairieSky (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of detailed information about financial instruments [line items] | |||
(Gain) loss from investment | $ 346 | $ (38) | $ (327) |
Investment in PrairieSky Royalty Ltd. | |||
Disclosure of detailed information about financial instruments [line items] | |||
Fair value loss (gain) from PrairieSky | 326 | (3) | (292) |
Dividend income from PrairieSky | (17) | (17) | (27) |
(Gain) loss from investment | $ 309 | $ (20) | $ (319) |
INVESTMENTS - Inter Pipeline (D
INVESTMENTS - Inter Pipeline (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of financial assets [line items] | |||
(Gain) loss from investment | $ 346 | $ (38) | $ (327) |
Investment in Inter Pipeline Ltd. | |||
Disclosure of financial assets [line items] | |||
Fair value loss from Inter Pipeline | 43 | 23 | 0 |
Dividend income from Inter Pipeline | (11) | (10) | (1) |
(Gain) loss from investment | $ 32 | $ 13 | $ (1) |
OTHER LONG-TERM ASSETS - Schedu
OTHER LONG-TERM ASSETS - Schedule of other long-term assets (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Subclassifications of assets, liabilities and equities [abstract] | ||
Investment in North West Redwater Partnership | $ 287 | $ 292 |
North West Redwater Partnership subordinated debt | 591 | 510 |
Risk management (note 19) | 373 | 204 |
Other | 208 | 241 |
Other assets | 1,459 | 1,247 |
Less: current portion | 116 | 79 |
Other long-term assets | $ 1,343 | $ 1,168 |
OTHER LONG-TERM ASSETS - Narrat
OTHER LONG-TERM ASSETS - Narrative (Details) | 12 Months Ended | ||||
Dec. 31, 2018CAD ($)bbl | Dec. 31, 2013 | Jun. 01, 2018 | Mar. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | |
Disclosure of joint ventures [line items] | |||||
North West Redwater Partnership subordinated debt | $ 591,000,000 | $ 510,000,000 | |||
Prepaid service tolls | 62,000,000 | ||||
Borrowings | 20,623,000,000 | 22,458,000,000 | |||
Non-revolving term credit facility maturing February 2020 | |||||
Disclosure of joint ventures [line items] | |||||
Maximum credit facility | $ 750,000,000 | ||||
North West Redwater Partnership | |||||
Disclosure of joint ventures [line items] | |||||
Company's voting percent interest in joint venture | 50.00% | ||||
Processing agreement, barrels of bitumen feedstock per day | bbl | 50,000 | ||||
Processing agreement, barrels of bitumen feedstock per date for the Company | bbl | 12,500 | ||||
Processing agreement, barrels of bitumen feedstock per date for others | bbl | 37,500 | ||||
Company's ownership interest in joint venture | 50.00% | 50.00% | |||
Subordinated debt interest rate variable | 6.00% | ||||
Debt to equity ratio | 400.00% | ||||
Subordinated debt contributed before accrued interest | $ 439,000,000 | ||||
Accrued interest | 152,000,000 | ||||
North West Redwater Partnership subordinated debt | $ 591,000,000 | ||||
Percent of pro rata share of debt company has committed paying to joint venture | 25.00% | 25.00% | |||
Term of commitment to joint venture | 30 years | ||||
North West Redwater Partnership | |||||
Disclosure of joint ventures [line items] | |||||
Processing agreement, barrels of bitumen feedstock per day | bbl | 50,000 | ||||
Processing agreement term | 30 years | ||||
Facility capital cost budget for the Project | $ 9,700,000,000 | ||||
North West Redwater Partnership | 2.80% Series J Senior Secured Bonds Due June 2027 | |||||
Disclosure of joint ventures [line items] | |||||
Bonds issued | $ 750,000,000 | ||||
Bonds issued, interest rate | 2.80% | ||||
North West Redwater Partnership | 3.65% Series K Senior Secured Bonds Due June 2035 | |||||
Disclosure of joint ventures [line items] | |||||
Bonds issued | $ 750,000,000 | ||||
Bonds issued, interest rate | 3.65% | ||||
North West Redwater Partnership | Syndicated credit facility | |||||
Disclosure of joint ventures [line items] | |||||
Borrowings | 2,333,000,000 | ||||
Maximum credit facility | $ 3,500,000,000 | $ 3,500,000,000 | |||
North West Redwater Partnership | Non-revolving term credit facility maturing February 2020 | |||||
Disclosure of joint ventures [line items] | |||||
Maximum credit facility | 1,500,000,000 | ||||
Major Borrowings Transactions | North West Redwater Partnership | Syndicated credit facility | |||||
Disclosure of joint ventures [line items] | |||||
Maximum credit facility | $ 2,000,000,000 |
OTHER LONG-TERM ASSETS - Summar
OTHER LONG-TERM ASSETS - Summary of Assets, Liabilities, Partners' Equity and Equity (Income) Loss (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of joint ventures [line items] | |||
Current assets | $ 3,020 | $ 4,897 | |
Current liabilities | 4,762 | 6,261 | |
Partners’ equity | 31,974 | 31,653 | $ 26,267 |
Equity loss (income) | (2,591) | (2,397) | $ 204 |
North West Redwater Partnership | |||
Disclosure of joint ventures [line items] | |||
Current assets | 105 | 165 | |
Non-current assets | 5,625 | 5,270 | |
Current liabilities | 176 | 1,238 | |
Non-current liabilities | 5,267 | 3,905 | |
Partners’ equity | 287 | 292 | |
Equity loss (income) | 5 | (31) | |
North West Redwater Partnership | |||
Disclosure of joint ventures [line items] | |||
Current assets | 210 | 330 | |
Non-current assets | 11,250 | 10,540 | |
Current liabilities | 352 | 2,476 | |
Non-current liabilities | 10,534 | 7,810 | |
Partners’ equity | 574 | 584 | |
Equity loss (income) | $ 10 | $ (62) |
LONG-TERM DEBT - Summary of Lon
LONG-TERM DEBT - Summary of Long-term Debt (Details) | Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD ($) |
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 20,623,000,000 | $ 22,458,000,000 | ||
Less: current portion of commercial paper | 141,000,000 | 625,000,000 | ||
Current portion of other long-term debt | 1,000,000,000 | 1,252,000,000 | ||
Long-term debt | $ 19,482,000,000 | $ 20,581,000,000 | ||
3.05% debentures due June 19, 2019 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.05% | 3.05% | ||
2.60% debentures due December 3, 2019 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 2.60% | 2.60% | ||
2.05% debentures due June 1, 2020 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 2.05% | 2.05% | 2.05% | 2.05% |
Notional amount | $ 900,000,000 | |||
2.89% debentures due August 14, 2020 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 2.89% | 2.89% | ||
3.31% debentures due February 11, 2022 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.31% | 3.31% | ||
3.55% debentures due June 3, 2024 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.55% | 3.55% | ||
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% |
Notional amount | $ 600,000,000 | |||
4.85% debentures due May 30, 2047 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 4.85% | 4.85% | 4.85% | 4.85% |
Notional amount | $ 300,000,000 | |||
Bank credit facilities (December 31, 2018 - US$2,954 million; December 31, 2017 - US$1,839 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 2,954,000,000 | $ 1,839,000,000 | ||
Commercial paper (December 31, 2018 - US$104 million; December 31, 2017 - US$500 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Notional amount | $ 104,000,000 | $ 500,000,000 | ||
1.75% due January 15, 2018 (US$600 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 1.75% | 1.75% | 1.75% | 1.75% |
Notional amount | $ 600,000,000 | |||
5.90% due February 1, 2018 (US$400 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 5.90% | 5.90% | 5.90% | 5.90% |
Notional amount | $ 400,000,000 | |||
3.45% due November 15, 2021 (US$500 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.45% | 3.45% | ||
Notional amount | $ 500,000,000 | |||
2.95% due January 15, 2023 (US$1,000 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 2.95% | 2.95% | 2.95% | 2.95% |
Notional amount | $ 1,000,000,000 | $ 1,000,000,000 | ||
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 | |||
3.90% 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 | |||
3.85% due June 1, 2027 (US$1,250 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 3.85% | 3.85% | 3.85% | 3.85% |
Notional amount | $ 1,250,000,000 | $ 1,250,000,000 | ||
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 | |||
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 | |||
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 | |||
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 | |||
6.25% 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 | |||
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 | |||
4.95% due June 1, 2047 (US$750 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings, interest rate | 4.95% | 4.95% | 4.95% | 4.95% |
Notional amount | $ 750,000,000 | $ 750,000,000 | ||
Gross carrying amount | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 20,742,000,000 | $ 22,597,000,000 | ||
Gross carrying amount | Bank credit facilities | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 831,000,000 | 3,544,000,000 | ||
Gross carrying amount | 3.05% debentures due June 19, 2019 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 500,000,000 | 500,000,000 | ||
Gross carrying amount | 2.60% debentures due December 3, 2019 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 500,000,000 | 500,000,000 | ||
Gross carrying amount | 2.05% debentures due June 1, 2020 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 900,000,000 | 900,000,000 | ||
Gross carrying amount | 2.89% debentures due August 14, 2020 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 1,000,000,000 | 1,000,000,000 | ||
Gross carrying amount | 3.31% debentures due February 11, 2022 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 1,000,000,000 | 1,000,000,000 | ||
Gross carrying amount | 3.55% debentures due June 3, 2024 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 500,000,000 | 500,000,000 | ||
Gross carrying amount | 3.42% debentures due December 1, 2026 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 600,000,000 | 600,000,000 | ||
Gross carrying amount | 4.85% debentures due May 30, 2047 | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 300,000,000 | 300,000,000 | ||
Gross carrying amount | Medium-term notes | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 6,131,000,000 | 8,844,000,000 | ||
Gross carrying amount | Bank credit facilities (December 31, 2018 - US$2,954 million; December 31, 2017 - US$1,839 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 4,031,000,000 | 2,300,000,000 | ||
Gross carrying amount | Commercial paper (December 31, 2018 - US$104 million; December 31, 2017 - US$500 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 141,000,000 | 625,000,000 | ||
Gross carrying amount | 1.75% due January 15, 2018 (US$600 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 0 | 751,000,000 | ||
Gross carrying amount | 5.90% due February 1, 2018 (US$400 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 0 | 501,000,000 | ||
Gross carrying amount | 3.45% due November 15, 2021 (US$500 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 682,000,000 | 625,000,000 | ||
Gross carrying amount | 2.95% due January 15, 2023 (US$1,000 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 1,364,000,000 | 1,252,000,000 | ||
Gross carrying amount | 3.80% due April 15, 2024 (US$500 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 682,000,000 | 625,000,000 | ||
Gross carrying amount | 3.90% due February 1, 2025 (US$600 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 819,000,000 | 751,000,000 | ||
Gross carrying amount | 3.85% due June 1, 2027 (US$1,250 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 1,706,000,000 | 1,566,000,000 | ||
Gross carrying amount | 7.20% due January 15, 2032 (US$400 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 546,000,000 | 501,000,000 | ||
Gross carrying amount | 6.45% due June 30, 2033 (US$350 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 478,000,000 | 438,000,000 | ||
Gross carrying amount | 5.85% due February 1, 2035 (US$350 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 478,000,000 | 438,000,000 | ||
Gross carrying amount | 6.50% due February 15, 2037 (US$450 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 614,000,000 | 563,000,000 | ||
Gross carrying amount | 6.25% due March 15, 2038 (US$1,100 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 1,501,000,000 | 1,377,000,000 | ||
Gross carrying amount | 6.75% due February 1, 2039 (US$400 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 546,000,000 | 501,000,000 | ||
Gross carrying amount | 4.95% due June 1, 2047 (US$750 million) | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 1,023,000,000 | 939,000,000 | ||
Gross carrying amount | Long-term debt | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 14,611,000,000 | 13,753,000,000 | ||
Original issue discounts, net | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | 17,000,000 | 18,000,000 | ||
Transaction costs | ||||
Disclosure of detailed information about borrowings [line items] | ||||
Borrowings | $ 102,000,000 | $ 121,000,000 |
LONG-TERM DEBT - Narrative (Det
LONG-TERM DEBT - Narrative (Details) | 3 Months Ended | 12 Months Ended | ||||||||
Sep. 30, 2018CAD ($) | Mar. 31, 2018CAD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2018GBP (£) | Dec. 31, 2017CAD ($) | Jul. 31, 2017USD ($) | Jul. 31, 2017CAD ($) | |
Disclosure of detailed information about borrowings [line items] | ||||||||||
Letters of credit and guarantees outstanding | $ 450,000,000 | |||||||||
Bank credit facilities | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 4,976,000,000 | |||||||||
Undrawn borrowing facilities | 4,723,000,000 | |||||||||
Term Credit Facility | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 4,750,000,000 | |||||||||
Demand credit facility | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 100,000,000 | £ 15,000,000 | ||||||||
Non-revolving term credit facility maturing May 2020 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 1,800,000,000 | $ 3,000,000,000 | ||||||||
Repayments of lines of credit | $ 1,050,000,000 | $ 150,000,000 | $ 1,200,000,000 | |||||||
Non-revolving term credit facility maturing October 2020 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 2,200,000,000 | |||||||||
Non-Revolving Term Credit Facility Maturing February 2019 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Repayments of lines of credit | $ 125,000,000 | |||||||||
Non-revolving term credit facility maturing February 2020 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 750,000,000 | |||||||||
Commercial Paper | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 2,500,000,000 | |||||||||
Notional amount | $ 104,000,000 | $ 500,000,000 | ||||||||
Revolving syndicated credit facility | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 2,425,000,000 | |||||||||
Revolving syndicated credit facility maturing June 2019 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 330,000,000 | |||||||||
Revolving syndicated credit facility maturing June 2021 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | 2,095,000,000 | |||||||||
Revolving syndicated credit facility maturing June 2022 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Maximum credit facility | $ 2,425,000,000 | |||||||||
Credit facilities and commercial paper | Weighted average | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 2.60% | 2.20% | 2.60% | 2.60% | 2.20% | |||||
Long-term debt | Weighted average | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 3.90% | 3.80% | 3.90% | 3.90% | 3.80% | |||||
2.05% debentures due June 1, 2020 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 2.05% | 2.05% | 2.05% | 2.05% | 2.05% | |||||
Notional amount | $ 900,000,000 | |||||||||
3.42% debentures due December 1, 2026 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 3.42% | 3.42% | 3.42% | 3.42% | 3.42% | |||||
Notional amount | $ 600,000,000 | |||||||||
4.85% debentures due May 30, 2047 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 4.85% | 4.85% | 4.85% | 4.85% | 4.85% | |||||
Notional amount | $ 300,000,000 | |||||||||
Medium-Term Borrowings Expiring August 2019 | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Base shell prospectus borrowings | $ 3,000,000,000 | |||||||||
1.75% due January 15, 2018 (US$600 million) | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 1.75% | 1.75% | 1.75% | 1.75% | 1.75% | |||||
Notional amount | $ 600,000,000 | |||||||||
Repayments of borrowings | $ 600,000,000 | |||||||||
5.90% due February 1, 2018 (US$400 million) | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 5.90% | 5.90% | 5.90% | 5.90% | 5.90% | |||||
Notional amount | $ 400,000,000 | |||||||||
Repayments of borrowings | $ 400,000,000 | |||||||||
5.70% due May 15, 2017 (US$1,100 million) | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 5.70% | 5.70% | ||||||||
Repayments of borrowings | $ 1,100,000,000 | |||||||||
2.95% due January 15, 2023 (US$1,000 million) | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 2.95% | 2.95% | 2.95% | 2.95% | 2.95% | |||||
Notional amount | $ 1,000,000,000 | $ 1,000,000,000 | ||||||||
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% | 3.85% | 3.85% | 3.85% | |||||
Notional amount | $ 1,250,000,000 | $ 1,250,000,000 | ||||||||
4.95% due June 1, 2047 (US$750 million) | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Borrowings, interest rate | 4.95% | 4.95% | 4.95% | 4.95% | 4.95% | |||||
Notional amount | $ 750,000,000 | $ 750,000,000 | ||||||||
US dollar denominated debt, unsecured | ||||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||||
Base shell prospectus borrowings | $ 3,000,000,000 |
LONG-TERM DEBT - Schedule of De
LONG-TERM DEBT - Schedule of Debt Repayments (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | $ 20,623 | $ 22,458 |
Gross carrying amount | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 20,742 | $ 22,597 |
Gross carrying amount | 2019 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 1,141 | |
Gross carrying amount | 2020 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 5,996 | |
Gross carrying amount | 2021 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 1,444 | |
Gross carrying amount | 2022 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 1,003 | |
Gross carrying amount | 2023 | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | 1,365 | |
Gross carrying amount | Thereafter | ||
Disclosure of maturity analysis for non-derivative financial liabilities [line items] | ||
Borrowings | $ 9,793 |
OTHER LONG-TERM LIABILITIES - S
OTHER LONG-TERM LIABILITIES - Schedule of other long-term liabilities (Details) $ in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2015CAD ($) | |
Disclosure Of Other Non-Current Liabilities [Line Items] | |||||
Asset retirement obligations | $ 3,886 | $ 4,327 | $ 3,243 | $ 2,950 | |
Share-based compensation | 124 | 414 | $ 426 | $ 128 | |
Risk management (note 19) | 17 | 103 | |||
Other | 80 | 96 | |||
Other liabilities | 4,225 | 5,409 | |||
Less: current portion | 335 | 1,012 | |||
Other long-term liabilities | 3,890 | 4,397 | |||
Deferred purchase consideration payable | 118 | 469 | |||
Annual installment amount | $ 25 | ||||
Installment period | 5 years | ||||
AOSP | |||||
Disclosure Of Other Non-Current Liabilities [Line Items] | |||||
Deferred purchase consideration payable | $ 118 | $ 375 | $ 469 |
OTHER LONG-TERM LIABILITIES - A
OTHER LONG-TERM LIABILITIES - Asset Retirement Obligations (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of other provisions [line items] | |||
Asset retirement obligations settlement period | 60 years | ||
Inflation rate | 2.00% | 2.00% | |
Reconciliation Of Changes In Provision For Decommissioning Restoration And Rehabilitation Costs [Roll Forward] | |||
Balance – beginning of year | $ 4,327 | $ 3,243 | $ 2,950 |
Balance – end of year | 3,886 | 4,327 | 3,243 |
Less: current portion | 186 | 92 | 95 |
Non-current asset retirement obligation | $ 3,700 | $ 4,235 | $ 3,148 |
Provision for decommissioning, restoration and rehabilitation costs [member] | |||
Disclosure of other provisions [line items] | |||
Weighted average discount rate | 5.00% | 4.70% | 5.20% |
Reconciliation Of Changes In Provision For Decommissioning Restoration And Rehabilitation Costs [Roll Forward] | |||
Liabilities incurred | $ 19 | $ 12 | $ 3 |
Liabilities acquired, net | 6 | 784 | 30 |
Liabilities settled | (290) | (274) | (267) |
Asset retirement obligation accretion | 186 | 164 | 142 |
Revision of cost, inflation rates and timing estimates | (111) | (40) | (68) |
Change in discount rate | (334) | 509 | 493 |
Foreign exchange adjustments | $ 83 | $ (71) | $ (40) |
OTHER LONG-TERM LIABILITIES -_2
OTHER LONG-TERM LIABILITIES - Segmented Asset Retirement Obligations (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | $ 3,886 | $ 4,327 | $ 3,243 | $ 2,950 |
North America | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 1,665 | 1,840 | ||
North Sea | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 707 | 755 | ||
Offshore Africa | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 134 | 245 | ||
Oil Sands Mining and Upgrading | ||||
Disclosure of operating segments [line items] | ||||
Asset retirement obligations | 1,379 | 1,486 | ||
Midstream | ||||
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation Of Changes In Liabilities From Share-Based Payment Transactions [Roll Forward] | |||
Balance – beginning of year | $ 414 | $ 426 | $ 128 |
Share-based compensation (recovery) expense | (146) | 134 | 355 |
Cash payment for stock options surrendered | (5) | (6) | (7) |
Transferred to common shares | (120) | (154) | (117) |
(Recovered from) charged to Oil Sands Mining and Upgrading, net | (19) | 14 | 67 |
Balance – end of year | 124 | 414 | 426 |
Less: current portion | 92 | 348 | 368 |
Non-current liabilities from share-based payment arrangements | 32 | 66 | 58 |
Performance Share Units | |||
Reconciliation Of Changes In Liabilities From Share-Based Payment Transactions [Roll Forward] | |||
Share-based compensation (recovery) expense | $ 13 | $ 5 | $ 0 |
OTHER LONG-TERM LIABILITIES - W
OTHER LONG-TERM LIABILITIES - Weighted Average Assumptions Used to Calculate Share-Based Compensation Liability (Details) | 12 Months Ended | ||
Dec. 31, 2018CAD ($)year | Dec. 31, 2017CAD ($)year | Dec. 31, 2016CAD ($)year | |
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Fair value | $ 3.33 | $ 11.82 | $ 11.41 |
Share price | $ 32.94 | $ 44.92 | $ 42.79 |
Expected volatility | 27.40% | 27.10% | 30.70% |
Expected dividend yield | 4.10% | 2.50% | 2.30% |
Risk free interest rate | 1.90% | 1.80% | 0.90% |
Expected forfeiture rate | 4.20% | 5.00% | 5.00% |
Expected stock option life | year | 4.4 | 4.5 | 4.6 |
Stock options | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Intrinsic value of vested stock options | $ 27,000,000 | $ 195,000,000 | $ 191,000,000 |
INCOME TAXES - Schedule Of Prov
INCOME TAXES - Schedule Of Provision For Income Tax (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current | |||
Other taxes | $ 9 | $ 11 | $ 9 |
Current income tax | 374 | (164) | (618) |
Deferred | |||
Deferred corporate income tax | 540 | 586 | (106) |
Deferred income tax | 557 | 640 | (241) |
Income tax expense (recovery) | 931 | 476 | (859) |
North America | |||
Current | |||
Current corporate income tax | 312 | (145) | (377) |
North Sea | |||
Current | |||
Current corporate income tax | 28 | 57 | (74) |
Current PRT - North Sea | (29) | (132) | (198) |
Deferred | |||
Deferred PRT - North Sea | 17 | 54 | (135) |
Offshore Africa | |||
Current | |||
Current corporate income tax | $ 54 | $ 45 | $ 22 |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of accounting profit multiplied by applicable tax rates [abstract] | |||
Canadian statutory income tax rate | 27.00% | 27.00% | 27.00% |
Income tax provision at statutory rate | $ 951 | $ 776 | $ (287) |
UK PRT and other taxes | (3) | (67) | (324) |
Impact of deductible UK PRT and other taxes on corporate income tax | 3 | 28 | 131 |
Foreign and domestic tax rate differentials | 6 | (43) | (54) |
Non-taxable portion of capital gains/losses | 142 | (86) | (80) |
Stock options exercised for common shares | (41) | 33 | 94 |
Income tax rate and other legislative changes | 0 | 10 | (107) |
Non-taxable gain on corporate acquisitions | (119) | (63) | 0 |
Revisions arising from prior year tax filings | (136) | (3) | (120) |
Change in unrecognized capital loss carryforward asset | 142 | (86) | (80) |
Other | (14) | (23) | (32) |
Income tax expense (recovery) | $ 931 | $ 476 | $ (859) |
INCOME TAXES - Summary of Major
INCOME TAXES - Summary of Major Temporary Differences (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | $ 13,553 | $ 12,859 | ||
Deferred income tax assets | (2,102) | (1,884) | ||
Net deferred income tax liability | 11,451 | 10,975 | $ 9,073 | $ 9,344 |
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 | 12,885 | 12,484 | ||
Unrealized risk management activities | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 33 | 20 | ||
PRT deduction for corporate income tax | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 1 | 7 | ||
Investments | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 46 | 96 | ||
Investment in North West Redwater Partnership | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 414 | 252 | ||
Asset retirement obligations | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (1,142) | (1,264) | ||
Loss carryforwards | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (855) | (523) | ||
Unrealized foreign exchange (gain) loss on long-term debt | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (104) | (29) | ||
Deferred PRT | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax assets | (1) | (18) | ||
Other | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Deferred income tax liabilities | 174 | 0 | ||
Deferred income tax assets | $ 0 | $ (50) |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | $ 557 | $ 640 | $ (241) |
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) | 281 | 541 | 37 |
Timing of partnership items | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 0 | 0 | (261) |
Unrealized foreign exchange (gain) loss on long-term debt | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (75) | 120 | 63 |
Unrealized risk management activities | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 18 | (46) | (44) |
Asset retirement obligations | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 175 | (88) | (20) |
Loss carryforwards | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (61) | 48 | (221) |
Investments | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (50) | (2) | 38 |
Investment in North West Redwater Partnership | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 162 | 30 | 81 |
Deferred PRT | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | 17 | 54 | (135) |
PRT deduction for corporate income tax | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | (7) | (21) | 61 |
Other | |||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | |||
Deferred income tax expense (recovery) | $ 97 | $ 4 | $ 160 |
INCOME TAXES - Summary of Net D
INCOME TAXES - Summary of Net Deferred Income Tax Liability (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of changes in deferred tax liability (asset) [abstract] | |||
Balance – beginning of year | $ 10,975 | $ 9,073 | $ 9,344 |
Deferred income tax expense (recovery) | 557 | 640 | (241) |
Deferred income tax (recovery) expense included in other comprehensive income | (6) | 4 | (5) |
Foreign exchange adjustments | 41 | (29) | (25) |
Business combinations (note 6,7,8) | (116) | 1,287 | 0 |
Balance – end of year | $ 11,451 | $ 10,975 | $ 9,073 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Provincial corporate income tax rate | 11.00% | |||
Increase in deferred income tax liability due to change in provincial corporate income tax rate | $ 10 | |||
Supplementary charge tax rate | 10.00% | 20.00% | ||
Decrease in deferred corporate tax liability | $ 107 | |||
Petroleum revenue tax rate | 0.00% | 35.00% | ||
Recovery PRT rate for prior taxation years | 50.00% | |||
Decrease in deferred PRT liability | $ 228 | |||
Increase in deferred corporate income tax liability due to change in PRT rate | $ 114 | |||
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 | $ 750 | |||
Changes in tax rate | ||||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||||
Provincial corporate income tax rate | 12.00% |
SHARE CAPITAL - Outstanding Com
SHARE CAPITAL - Outstanding Common Shares (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Reconciliation of number of shares outstanding [abstract] | ||||
Balance – beginning of year | $ 31,653 | $ 26,267 | ||
Issued upon exercise of stock options (in shares) | 9,975,000 | 14,256,000 | ||
Purchase of common shares under Normal Course Issuer Bid (In shares) | (30,857,727) | |||
Purchase of common shares under Normal Course Issuer Bid | $ 1,282 | |||
Balance – end of year | 31,974 | $ 31,653 | $ 26,267 | |
Share capital | ||||
Reconciliation of number of shares outstanding [abstract] | ||||
Balance – beginning of year | 9,109 | 4,671 | 4,541 | |
Issued for the acquisition of AOSP and other assets (note 8) | [1] | 0 | 3,818 | 0 |
Issued upon exercise of stock options | 332 | 466 | 559 | |
Previously recognized liability on stock options exercised for common shares | 120 | 154 | 117 | |
Purchase of common shares under Normal Course Issuer Bid | (238) | 0 | 0 | |
Balance – end of year | $ 9,323 | $ 9,109 | $ 4,671 | |
Ordinary shares | Share capital | ||||
Reconciliation of number of shares outstanding [abstract] | ||||
Balance - beginning of year (in shares) | 1,222,769,000 | 1,110,952,000 | ||
Balance – beginning of year | $ 9,109 | $ 4,671 | ||
Issued for the acquisition of AOSP and other assets (note 7) (in shares) | 0 | 97,561,000 | ||
Issued for the acquisition of AOSP and other assets (note 8) | $ 0 | $ 3,818 | ||
Issued upon exercise of stock options (in shares) | 9,975,000 | 14,256,000 | ||
Issued upon exercise of stock options | $ 332 | $ 466 | ||
Previously recognized liability on stock options exercised for common shares | $ 120 | $ 154 | ||
Purchase of common shares under Normal Course Issuer Bid (In shares) | (30,858,000) | 0 | ||
Purchase of common shares under Normal Course Issuer Bid | $ (238) | $ 0 | ||
Balance - end of year (in shares) | 1,201,886,000 | 1,222,769,000 | 1,110,952,000 | |
Balance – end of year | $ 9,323 | $ 9,109 | $ 4,671 | |
[1] | During 2017, in connection with the acquisition of direct and indirect interests in the Athabasca Oil Sands Project ("AOSP") and other assets, the Company issued non-cash share consideration of $3,818 million. See note 8. |
SHARE CAPITAL - Narrative (Deta
SHARE CAPITAL - Narrative (Details) - CAD ($) $ / shares in Units, $ in Millions | Mar. 06, 2019 | Feb. 28, 2018 | Mar. 01, 2017 | Nov. 02, 2016 | Mar. 02, 2016 | Mar. 27, 2019 | May 22, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | May 16, 2018 |
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Quarterly dividend declared (in CAD per share) | $ 0.375 | $ 0.335 | $ 0.275 | $ 0.25 | $ 0.23 | ||||||
Share repurchase term | 12 months | ||||||||||
Shares repurchased and retired (in shares) | 30,857,727 | ||||||||||
Weighted average price per share of shares repurchased and retired (in CAD per share) | $ 41.56 | ||||||||||
Purchase of common shares under Normal Course Issuer Bid | $ (1,282) | ||||||||||
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) | 61,454,856 | ||||||||||
Stock options | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Vesting term | 5 years | ||||||||||
Shares that may be reserved for issuance as a percentage of common shares outstanding | 9.00% | ||||||||||
Stock options | Bottom of range | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Expiration term | 5 years | ||||||||||
Stock options | Top of range | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Expiration term | 6 years | ||||||||||
Retained earnings | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Purchase of common shares under Normal Course Issuer Bid | $ 1,044 | $ 0 | $ 0 | ||||||||
Purchase Of Common Shares For Retirement | |||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||
Shares repurchased and retired (in shares) | 4,340,000 | ||||||||||
Weighted average price per share of shares repurchased and retired (in CAD per share) | $ 35.86 | ||||||||||
Purchase of common shares under Normal Course Issuer Bid | $ (156) |
SHARE CAPITAL - Stock Option Ac
SHARE CAPITAL - Stock Option Activity (Details) shares in Thousands | 12 Months Ended | |
Dec. 31, 2018CAD ($)shares | Dec. 31, 2017CAD ($)shares | |
Share Capital, Reserves And Other Equity Interest [Abstract] | ||
Stock options outstanding - beginning of year (in shares) | shares | 56,036 | 58,299 |
Stock options granted (in shares) | shares | 4,256 | 16,052 |
Stock options surrendered for cash settlement (in shares) | shares | (392) | (626) |
Stock options exercised for common shares (in shares) | shares | (9,975) | (14,256) |
Stock options forfeited (in shares) | shares | (3,240) | (3,433) |
Stock options outstanding - end of year (in shares) | shares | 46,685 | 56,036 |
Stock options exercisable (in shares) | shares | 19,436 | 18,282 |
Weighted average exercise price, options outstanding - beginning of year (in CAD per share) | $ | $ 36.67 | $ 34.22 |
Weighted average exercise price, options granted (in CAD per share) | $ | 43.75 | 42.07 |
Weighted average exercise price, options surrendered for cash settlement (in CAD per share) | $ | 33.46 | 33.18 |
Weighted average exercise price, options exercised (in CAD per share) | $ | 33.28 | 32.66 |
Weighted average exercise price, options forfeited (in CAD per share) | $ | 38.76 | 37.53 |
Weighted average exercise price, options outstanding - end of year (in CAD per share) | $ | 37.92 | 36.67 |
Weighted average exercise price, options exercisable (in CAD per share) | $ | $ 36.03 | $ 34.25 |
SHARE CAPITAL - Range of Exerci
SHARE CAPITAL - Range of Exercise Prices of Stock Options (Details) shares in Thousands | Dec. 31, 2018CAD ($)sharesyear | Dec. 31, 2017CAD ($)shares | Dec. 31, 2016CAD ($)shares |
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 46,685 | 56,036 | 58,299 |
Weighted average remaining term (years) | year | 2.66 | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 37.92 | $ 36.67 | $ 34.22 |
Stock options exercisable (in shares) | shares | 19,436 | 18,282 | |
Weighted average exercise price, options exercisable (in CAD per share) | $ 36.03 | $ 34.25 | |
$22.90 - $24.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 3,120 | ||
Weighted average remaining term (years) | year | 2.04 | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 22.90 | ||
Stock options exercisable (in shares) | shares | 1,515 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 22.90 | ||
$22.90 - $24.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 22.90 | ||
$22.90 - $24.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 24.99 | ||
$25.00 - $29.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 5,112 | ||
Weighted average remaining term (years) | year | 2.02 | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 28.86 | ||
Stock options exercisable (in shares) | shares | 2,453 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 28.87 | ||
$25.00 - $29.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 25 | ||
$25.00 - $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 - $34.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 6,013 | ||
Weighted average remaining term (years) | year | 0.83 | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 33.27 | ||
Stock options exercisable (in shares) | shares | 4,831 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 33.43 | ||
$30.00 - $34.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 30 | ||
$30.00 - $34.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 34.99 | ||
$35.00 - $39.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 11,304 | ||
Weighted average remaining term (years) | year | 2.72 | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 37.46 | ||
Stock options exercisable (in shares) | shares | 4,131 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 35.91 | ||
$35.00 - $39.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 35 | ||
$35.00 - $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 - $44.99 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 17,107 | ||
Weighted average remaining term (years) | year | 3.23 | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 43.59 | ||
Stock options exercisable (in shares) | shares | 5,664 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 43.60 | ||
$40.00 - $44.99 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 40 | ||
$40.00 - $44.99 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 44.99 | ||
$45.00 - $46.74 | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Stock options outstanding (in shares) | shares | 4,029 | ||
Weighted average remaining term (years) | year | 4.06 | ||
Weighted average exercise price, options outstanding (in CAD per share) | $ 45.20 | ||
Stock options exercisable (in shares) | shares | 842 | ||
Weighted average exercise price, options exercisable (in CAD per share) | $ 45.08 | ||
$45.00 - $46.74 | Bottom of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | 45 | ||
$45.00 - $46.74 | Top of range | |||
Disclosure of range of exercise prices of outstanding share options [line items] | |||
Range of exercise prices | $ 46.74 |
ACCUMULATED OTHER COMPREHENSI_3
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Analysis Of Other Comprehensive Income By Item [Abstract] | ||
Derivative financial instruments designated as cash flow hedges | $ 13 | $ 47 |
Foreign currency translation adjustment | 109 | (115) |
Accumulated other comprehensive income (loss) | $ 122 | $ (68) |
CAPITAL DISCLOSURES (Details)
CAPITAL DISCLOSURES (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of objectives, policies and processes for managing capital [line items] | |||
Debt to book capitalization | 39.00% | 41.00% | |
Long-term debt, net | $ 20,522 | $ 22,321 | |
Total shareholders’ equity | $ 31,974 | $ 31,653 | $ 26,267 |
Bottom of range | |||
Disclosure of objectives, policies and processes for managing capital [line items] | |||
Debt to book capitalization | 25.00% | ||
Top of range | |||
Disclosure of objectives, policies and processes for managing capital [line items] | |||
Debt to book capitalization | 45.00% | ||
Debt to book capitalization | 65.00% |
NET EARNINGS (LOSS) PER COMMO_3
NET EARNINGS (LOSS) PER COMMON SHARE - Schedule of Basic and Diluted Net Earnings (Loss) per Common Share (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Weighted average ordinary shares and adjusted weighted average ordinary shares [abstract] | |||
Weighted average common shares outstanding – basic (thousands of shares) | 1,218,798 | 1,175,094 | 1,100,471 |
Effect of dilutive stock options (thousands of shares) | 4,960 | 7,729 | 0 |
Weighted average common shares outstanding – diluted (thousands of shares) | 1,223,758 | 1,182,823 | 1,100,471 |
Net earnings (loss) | $ 2,591 | $ 2,397 | $ (204) |
Net earnings (loss) per common share - basic (in CAD per share) | $ 2.13 | $ 2.04 | $ (0.19) |
Net earnings (loss) per common share - diluted (in CAD per share) | $ 2.12 | $ 2.03 | $ (0.19) |
NET EARNINGS (LOSS) PER COMMO_4
NET EARNINGS (LOSS) PER COMMON SHARE - Narrative (Details) - shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Earnings per share [abstract] | ||
Potentially anti-dilutive securities (in shares) | 23,458,000 | 17,547,000 |
INTEREST AND OTHER FINANCING _3
INTEREST AND OTHER FINANCING EXPENSE (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Borrowing costs [abstract] | |||
Long-term debt | $ 867 | $ 810 | $ 664 |
Less: amounts capitalized on qualifying assets | 69 | 82 | 233 |
Total interest and other financing expense | 798 | 728 | 431 |
Total interest income | (59) | (97) | (48) |
Net interest and other financing expense | $ 739 | $ 631 | $ 383 |
FINANCIAL INSTRUMENTS - Carryin
FINANCIAL INSTRUMENTS - Carrying amounts of financial instruments by category (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD ($) | |
Disclosure of detailed information about financial instruments [line items] | |||
Deferred purchase consideration payable | $ 118 | $ 469 | |
Financial assets at amortized cost | 1,739 | 2,907 | |
Fair value through profit or loss | 519 | 855 | |
Derivatives used for hedging | 361 | 139 | |
Financial liabilities at amortized cost | (23,876) | (26,299) | |
Financial liabilities | (572) | ||
Total | $ (21,257) | (22,398) | |
Installment period | 5 years | ||
Accounts payable | |||
Disclosure of detailed information about financial instruments [line items] | |||
Financial liabilities at amortized cost | $ (779) | (775) | |
Financial liabilities | (779) | (775) | |
Accrued liabilities | |||
Disclosure of detailed information about financial instruments [line items] | |||
Financial liabilities at amortized cost | (2,356) | (2,597) | |
Financial liabilities | (2,356) | (2,597) | |
Other long-term liabilities | |||
Disclosure of detailed information about financial instruments [line items] | |||
Financial liabilities, fair value through profit or loss | (17) | (38) | |
Financial liabilities, derivatives used for hedging | 0 | (65) | |
Financial liabilities at amortized cost | (118) | (469) | |
Financial liabilities | (135) | ||
Long-term debt | |||
Disclosure of detailed information about financial instruments [line items] | |||
Financial liabilities at amortized cost | (20,623) | (22,458) | |
Financial liabilities | (20,623) | (22,458) | |
Accounts receivable | |||
Disclosure of detailed information about financial instruments [line items] | |||
Financial assets at amortized cost | 1,148 | 2,397 | |
Financial assets | 1,148 | 2,397 | |
Investments | |||
Disclosure of detailed information about financial instruments [line items] | |||
Financial assets at amortized cost | 0 | 0 | |
Financial assets, fair value through profit or loss | 524 | 893 | |
Financial assets | 524 | 893 | |
Other long-term assets | |||
Disclosure of detailed information about financial instruments [line items] | |||
Financial assets at amortized cost | 591 | 510 | |
Financial assets, fair value through profit or loss | 12 | 0 | |
Financial assets, derivatives used for hedging | 361 | 204 | |
Financial assets | 964 | 714 | |
AOSP | |||
Disclosure of detailed information about financial instruments [line items] | |||
Deferred purchase consideration payable | $ 118 | $ 375 | $ 469 |
FINANCIAL INSTRUMENTS - Carry_2
FINANCIAL INSTRUMENTS - Carrying amounts and fair values of financial instruments (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, carrying amount | $ (572) | |
Other long-term liabilities | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, carrying amount | $ (135) | (103) |
Other long-term liabilities | Level 1 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, at fair value | 0 | 0 |
Other long-term liabilities | Level 2 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, at fair value | (17) | (103) |
Other long-term liabilities | Level 3 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, at fair value | (118) | 0 |
Fixed rate long-term debt | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, carrying amount | (20,623) | (22,458) |
Fixed rate long-term debt | Fixed interest rate | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, carrying amount | (15,620) | (15,989) |
Fixed rate long-term debt | Fixed interest rate | Level 1 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, at fair value | (15,952) | (17,259) |
Fixed rate long-term debt | Fixed interest rate | Level 2 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, at fair value | 0 | 0 |
Fixed rate long-term debt | Fixed interest rate | Level 3 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial liabilities, at fair value | 0 | 0 |
Investments | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, carrying amount | 524 | 893 |
Investments | Level 1 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, at fair value | 524 | 893 |
Investments | Level 2 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, at fair value | 0 | 0 |
Investments | Level 3 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, at fair value | 0 | 0 |
Other long-term assets | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, carrying amount | 964 | 714 |
Other long-term assets | Level 1 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, at fair value | 0 | 0 |
Other long-term assets | Level 2 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, at fair value | 373 | 204 |
Other long-term assets | Level 3 | ||
Disclosure of detailed information about financial instruments [line items] | ||
Financial assets, at fair value | $ 591 | $ 510 |
FINANCIAL INSTRUMENTS - Carry_3
FINANCIAL INSTRUMENTS - Carrying amounts and reconciliation of derivative financial instruments (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of detailed information about hedging instruments [line items] | |||
Derivative financial asset (liability), net | $ 356 | $ 101 | $ 489 |
Current portion of other long-term assets | 92 | 0 | |
Current portion of other long-term liabilities | (17) | (103) | |
Other long-term assets | 281 | 204 | |
Financial liabilities at amortised cost | 23,876 | 26,299 | |
Cash flow hedges | |||
Disclosure of detailed information about hedging instruments [line items] | |||
Gain (loss) on hedge ineffectiveness | 2 | 5 | $ 7 |
Forward contracts | |||
Disclosure of detailed information about hedging instruments [line items] | |||
Derivatives held for trading, asset (liability) | 8 | (38) | |
Forward contracts | Cash flow hedges | |||
Disclosure of detailed information about hedging instruments [line items] | |||
Cash flow hedges, asset (liability) | 70 | (71) | |
WCS differential swaps | |||
Disclosure of detailed information about hedging instruments [line items] | |||
Derivatives held for trading, asset (liability) | (17) | 0 | |
AECO basis swap | |||
Disclosure of detailed information about hedging instruments [line items] | |||
Derivatives held for trading, asset (liability) | 1 | 0 | |
AECO fixed price swaps | |||
Disclosure of detailed information about hedging instruments [line items] | |||
Derivatives held for trading, asset (liability) | 3 | 0 | |
Cross currency swaps | Cash flow hedges | |||
Disclosure of detailed information about hedging instruments [line items] | |||
Cash flow hedges, asset (liability) | $ 291 | $ 210 |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation Of Changes In Derivative Financial Assets (Liabilities), Net [Roll Forward] | |||
Derivative financial asset (liability), net | $ 101 | $ 489 | |
Net change in fair value of outstanding derivatives financial instruments recognized in: Risk management activities | 35 | (37) | $ (25) |
Net change in fair value of outstanding derivatives financial instruments recognized in: Foreign exchange | 260 | (375) | |
Net change in fair value of outstanding derivatives financial instruments recognized in: Other comprehensive income (loss) | (40) | 24 | |
Derivative financial asset (liability), net | 356 | 101 | $ 489 |
Asset (liability), included in current portion of other long-term (liabilities) assets | 75 | (103) | |
Asset (liability), included in other long-term assets | $ 281 | $ 204 |
FINANCIAL INSTRUMENTS - Net (ga
FINANCIAL INSTRUMENTS - Net (gains) losses from risk management activities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Financial Instruments [Abstract] | |||
Net realized risk management (gain) loss | $ (99) | $ (2) | $ 8 |
Net unrealized risk management (gain) loss | (35) | 37 | 25 |
Gains (losses) on change in fair value of derivatives | $ (134) | $ 35 | $ 33 |
FINANCIAL INSTRUMENTS - Commodi
FINANCIAL INSTRUMENTS - Commodity price risk management (Details) - Commodity price risk - Swap contract | Mar. 06, 2019$ / GJGJ / d | Dec. 31, 2018$ / bbl$ / MMBTU$ / GJbbl / dGJ / dMMBTU / d |
WCS Differential Swaps, Jan 2019 to Mar 2019 | ||
Disclosure of detailed information about hedging instruments [line items] | ||
Oil volume per day | bbl / d | 28,000 | |
Average price of hedging instrument | $ / bbl | 17.65 | |
WCS Differential Swaps, Jan 2019 to Sep 2019 | ||
Disclosure of detailed information about hedging instruments [line items] | ||
Oil volume per day | bbl / d | 8,000 | |
Average price of hedging instrument | $ / bbl | 23.57 | |
AECO Basis Swap, Jan 2019 to Mar 2019 | ||
Disclosure of detailed information about hedging instruments [line items] | ||
Natural gas energy per day | MMBTU / d | 10,000 | |
Average price of hedging instrument | $ / MMBTU | 1.39 | |
AECO Fixed Price Swap, Jan 2019 to Mar 2019 | ||
Disclosure of detailed information about hedging instruments [line items] | ||
Natural gas energy per day | GJ / d | 30,000 | |
Average price of hedging instrument | $ / GJ | 2.30 | |
AECO Fixed Price Swap, Apr 2019 to Oct 2019 | ||
Disclosure of detailed information about hedging instruments [line items] | ||
Natural gas energy per day | GJ / d | 10,000 | |
Average price of hedging instrument | $ / GJ | 1.30 | |
Hedging Instruments Transactions | AECO Fixed Price Swap, Apr 2019 to Oct 2019 | ||
Disclosure of detailed information about hedging instruments [line items] | ||
Natural gas energy per day | GJ / d | 105,000 | |
Average price of hedging instrument | $ / GJ | 1.32 |
FINANCIAL INSTRUMENTS - Foreign
FINANCIAL INSTRUMENTS - Foreign currency exchange rate risk management (Details) | 12 Months Ended |
Dec. 31, 2018USD ($)$ / $ | |
Foreign currency exchange rate risk | Cash flow hedges | Forward contracts | |
Disclosure of detailed information about hedging instruments [line items] | |
Notional amount | $ 3,058,000,000 |
US | |
Disclosure of detailed information about hedging instruments [line items] | |
Exchange rate (US$/C$) | 1 |
Cross currency swaps | Foreign currency exchange rate risk | Cash flow hedges | Currency swap contract, term through November 2021 | |
Disclosure of detailed information about hedging instruments [line items] | |
Amount | 500,000,000 |
Exchange rate (US$/C$) | $ / $ | 1.022 |
Cross currency swaps | Foreign currency exchange rate risk | Cash flow hedges | Currency swap contract, term through March 2038 | |
Disclosure of detailed information about hedging instruments [line items] | |
Amount | 550,000,000 |
Exchange rate (US$/C$) | $ / $ | 1.170 |
Cross currency swaps | US | Foreign currency exchange rate risk | Cash flow hedges | Currency swap contract, term through November 2021 | |
Disclosure of detailed information about hedging instruments [line items] | |
Interest rate | 3.45% |
Cross currency swaps | US | Foreign currency exchange rate risk | Cash flow hedges | Currency swap contract, term through March 2038 | |
Disclosure of detailed information about hedging instruments [line items] | |
Interest rate | 6.25% |
Cross currency swaps | CAD | Foreign currency exchange rate risk | Cash flow hedges | Currency swap contract, term through November 2021 | |
Disclosure of detailed information about hedging instruments [line items] | |
Interest rate | 3.96% |
Cross currency swaps | CAD | Foreign currency exchange rate risk | Cash flow hedges | Currency swap contract, term through March 2038 | |
Disclosure of detailed information about hedging instruments [line items] | |
Interest rate | 5.76% |
Forward contracts | Foreign currency exchange rate risk | |
Disclosure of detailed information about hedging instruments [line items] | |
Notional amount | $ 3,506,000,000 |
Derivative, term of contract | 90 days |
FINANCIAL INSTRUMENTS - Financi
FINANCIAL INSTRUMENTS - Financial instrument sensitivities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)$ / bbl$ / Mcf$ / Mcf | Dec. 31, 2018CAD ($)$ / bbl$ / Mcf$ / Mcf | Dec. 31, 2017CAD ($) | |
Commodity price risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Increase WCS US$1.00/bbl (USD per bbl) | $ / bbl | 1 | 1 | |
Decrease WCS US$1.00/bbl (USD per bbl) | $ / bbl | 1 | 1 | |
Increase AECO $0.10/Mcf (CAD per Mcf) | $ / Mcf | 0.10 | 0.10 | |
Decrease AECO $0.10/Mcf (CAD per Mcf) | $ / Mcf | 0.10 | 0.10 | |
Increase AECO $0.10/Mcf (USD per Mcf) | $ / Mcf | 0.10 | 0.10 | |
Decrease AECO $0.10/Mcf (USD per Mcf) | $ / Mcf | 0.10 | 0.10 | |
Interest rate risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Increase interest rate 1% | 1.00% | 1.00% | |
Decrease interest rate 1% | 1.00% | 1.00% | |
Increase (decrease) to net earnings | $ (33) | $ (42) | |
Increase (decrease) to net earnings | 33 | 42 | |
Increase (decrease) to other comprehensive income | (21) | (16) | |
Increase (decrease) to other comprehensive income | 25 | 19 | |
Foreign currency exchange rate risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Increase exchange rate by US$0.01 | $ 0.01 | ||
Decrease exchange rate by US$0.01 | $ 0.01 | ||
Increase (decrease) to net earnings | (114) | (105) | |
Increase (decrease) to net earnings | 113 | 101 | |
Increase (decrease) to other comprehensive income | 0 | 0 | |
Increase (decrease) to other comprehensive income | 0 | 0 | |
WCS differential swaps | Commodity price risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Increase (decrease) to net earnings | (5) | 0 | |
Increase (decrease) to net earnings | 5 | 0 | |
Increase (decrease) to other comprehensive income | 0 | 0 | |
Increase (decrease) to other comprehensive income | 0 | 0 | |
AECO Swap | Commodity price risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Increase (decrease) to net earnings | (1) | 0 | |
Increase (decrease) to net earnings | 1 | 0 | |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Disclosure of detailed information about financial instruments [line items] | |||
Expected credit loss rate | 1.00% | ||
Derivative financial asset (liability), net | $ 356 | $ 101 | $ 489 |
Credit risk | |||
Disclosure of detailed information about financial instruments [line items] | |||
Derivative financial asset (liability), net | $ 361 | $ 187 |
FINANCIAL INSTRUMENTS - Maturit
FINANCIAL INSTRUMENTS - Maturity dates for financial liabilities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of detailed information about financial instruments [line items] | |||
Accounts payable | $ 779 | $ 775 | |
Accrued liabilities | 2,356 | 2,597 | |
Other long-term liabilities | 3,890 | 4,397 | |
Long-term debt | 20,623 | 22,458 | |
Interest and other financing expense | 798 | 728 | $ 431 |
Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 20,742 | $ 22,597 | |
Less than 1 year | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 1,141 | ||
1 to less than 2 years | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 5,996 | ||
Thereafter | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 9,793 | ||
Liquidity risk | Less than 1 year | |||
Disclosure of detailed information about financial instruments [line items] | |||
Accounts payable | 779 | ||
Accrued liabilities | 2,356 | ||
Other long-term liabilities | 42 | ||
Interest and other financing expense | 836 | ||
Liquidity risk | Less than 1 year | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 1,141 | ||
Liquidity risk | 1 to less than 2 years | |||
Disclosure of detailed information about financial instruments [line items] | |||
Accounts payable | 0 | ||
Accrued liabilities | 0 | ||
Other long-term liabilities | 24 | ||
Interest and other financing expense | 755 | ||
Liquidity risk | 1 to less than 2 years | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 5,996 | ||
Liquidity risk | 2 to less than 5 years | |||
Disclosure of detailed information about financial instruments [line items] | |||
Accounts payable | 0 | ||
Accrued liabilities | 0 | ||
Other long-term liabilities | 69 | ||
Interest and other financing expense | 1,668 | ||
Liquidity risk | 2 to less than 5 years | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | 3,812 | ||
Liquidity risk | Thereafter | |||
Disclosure of detailed information about financial instruments [line items] | |||
Accounts payable | 0 | ||
Accrued liabilities | 0 | ||
Other long-term liabilities | 0 | ||
Interest and other financing expense | 5,327 | ||
Liquidity risk | Thereafter | Gross carrying amount | |||
Disclosure of detailed information about financial instruments [line items] | |||
Long-term debt | $ 9,793 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Jun. 01, 2018 | |
2019 | ||
Disclosure Of Commitments [Line Items] | ||
Product transportation and pipeline | $ 692 | |
North West Redwater Partnership service toll (1) | 86 | |
Other | 85 | |
2020 | ||
Disclosure Of Commitments [Line Items] | ||
Product transportation and pipeline | 664 | |
North West Redwater Partnership service toll (1) | 126 | |
Other | 35 | |
2021 | ||
Disclosure Of Commitments [Line Items] | ||
Product transportation and pipeline | 620 | |
North West Redwater Partnership service toll (1) | 157 | |
Other | 32 | |
2022 | ||
Disclosure Of Commitments [Line Items] | ||
Product transportation and pipeline | 516 | |
North West Redwater Partnership service toll (1) | 158 | |
Other | 32 | |
2023 | ||
Disclosure Of Commitments [Line Items] | ||
Product transportation and pipeline | 381 | |
North West Redwater Partnership service toll (1) | 157 | |
Other | 31 | |
Thereafter | ||
Disclosure Of Commitments [Line Items] | ||
Product transportation and pipeline | 3,991 | |
North West Redwater Partnership service toll (1) | 2,858 | |
Other | $ 424 | |
North West Redwater Partnership | ||
Disclosure Of Commitments [Line Items] | ||
Percent of pro rata share of debt company has committed paying to joint venture | 25.00% | 25.00% |
Interest payable included in service toll | $ 1,301 | |
Term of commitment to joint venture | 30 years | |
Offshore equipment operating leases | 2019 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | $ 94 | |
Offshore equipment operating leases | 2020 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 73 | |
Offshore equipment operating leases | 2021 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 75 | |
Offshore equipment operating leases | 2022 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 8 | |
Offshore equipment operating leases | 2023 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 0 | |
Offshore equipment operating leases | Thereafter | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 0 | |
Office leases | 2019 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 42 | |
Office leases | 2020 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 42 | |
Office leases | 2021 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 39 | |
Office leases | 2022 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 31 | |
Office leases | 2023 | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | 32 | |
Office leases | Thereafter | ||
Disclosure Of Commitments [Line Items] | ||
Office leases | $ 89 |
SUPPLEMENTAL DISCLOSURE OF CA_3
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION - Supplemental Schedule Of Cash Flow Information (Details) $ in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD ($) | ||
Disclosure Of Detailed Information About Cash Flows [Line Items] | ||||||
Accounts receivable | $ 1,233 | $ (977) | $ (142) | |||
Current income tax assets (liabilities) | 471 | 527 | (165) | |||
Inventory | (74) | 81 | (79) | |||
Prepaids and other | (3) | (28) | 14 | |||
Accounts payable | (7) | 175 | 31 | |||
Accrued liabilities | (268) | 365 | (116) | |||
Other long-term liabilities | (351) | 469 | 0 | |||
Net changes in non-cash working capital | 1,001 | 612 | (457) | |||
Net change in non-cash working capital | 1,346 | 299 | (542) | |||
Net change in non-cash working capital, investing activities | (345) | 313 | 85 | |||
Exploration and evaluation assets | ||||||
Expenditures on exploration and evaluation assets | 282 | 159 | 29 | |||
Net proceeds on sale of exploration and evaluation assets | (16) | (35) | (35) | |||
Net expenditures (proceeds) on exploration and evaluation assets | 266 | 124 | (6) | |||
Property, plant and equipment | ||||||
Expenditures on property, plant and equipment | 4,175 | 4,574 | 4,152 | |||
Net proceeds on sale of property, plant and equipment | 0 | 0 | (349) | |||
Net expenditures on property, plant and equipment | [1] | 4,175 | $ 4,574 | 3,803 | ||
Deferred purchase consideration payable | 118 | $ 469 | ||||
Disposal of Cold Lake Pipeline | Investment in Inter Pipeline Ltd. | ||||||
Property, plant and equipment | ||||||
Non-cash share consideration received | $ 190 | |||||
AOSP | ||||||
Property, plant and equipment | ||||||
Deferred purchase consideration payable | $ 118 | $ 375 | $ 469 | |||
[1] | Net expenditures on property, plant and equipment in 2016 exclude non-cash share consideration of $190 million received from Inter Pipeline Ltd. ("Inter Pipeline") on the disposition of the Company's interest in the Cold Lake Pipeline |
SUPPLEMENTAL DISCLOSURE OF CA_4
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION - Liabilities Arising From Financing Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2016 | |
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Liabilities arising from financing activities, beginning balance | $ 22,319 | |
Changes in liabilities arising from financing activities [abstract] | ||
Issue of long-term debt | (2,831) | $ 6,622 |
Settlement of hedge instruments, net | 124 | |
Non-cash changes | 774 | (747) |
Liabilities arising from financing activities, ending balance | 20,262 | 16,320 |
Long-term debt | ||
Disclosure of reconciliation of liabilities arising from financing activities [line items] | ||
Liabilities arising from financing activities, beginning balance | 22,458 | |
Changes in liabilities arising from financing activities [abstract] | ||
Issue of long-term debt | (2,831) | 6,622 |
Settlement of hedge instruments, net | 0 | |
Non-cash changes | 996 | (969) |
Liabilities arising from financing activities, ending balance | 20,623 | 16,805 |
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 | (139) | |
Changes in liabilities arising from financing activities [abstract] | ||
Issue of long-term debt | 0 | 0 |
Settlement of hedge instruments, net | 124 | |
Non-cash changes | (222) | 222 |
Liabilities arising from financing activities, ending balance | $ (361) | $ (485) |
SEGMENTED INFORMATION - Narrati
SEGMENTED INFORMATION - Narrative (Details) | 12 Months Ended |
Dec. 31, 2018segment | |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||
Revenue [abstract] | |||||
Product sales | $ 22,282 | $ 18,360 | [1] | $ 12,002 | [1] |
Less: royalties | (1,255) | (1,018) | (575) | ||
Revenue | 21,027 | 17,342 | 11,427 | ||
Expenses | |||||
Production | 6,464 | 5,675 | [1] | 4,184 | [1] |
Transportation, blending and feedstock | 4,189 | 3,529 | [1] | 2,822 | [1] |
Depletion, depreciation and amortization | 5,161 | 5,186 | 4,858 | ||
Asset retirement obligation accretion | 186 | 164 | 142 | ||
Realized risk management (commodity derivatives) | (99) | (2) | 8 | ||
Gain on acquisition, disposition and revaluation of properties | (452) | (379) | (250) | ||
Loss (gain) from investments | 346 | (38) | (327) | ||
Total expenses | 17,505 | 14,469 | 12,490 | ||
Administration | 325 | 319 | 345 | ||
Share-based compensation | (146) | 134 | 355 | ||
Interest and other financing expense | 739 | 631 | 383 | ||
Net unrealized risk management (gain) loss | (35) | 37 | 25 | ||
Foreign exchange loss (gain) | 827 | (787) | (55) | ||
Earnings (loss) before taxes | 3,522 | 2,873 | (1,063) | ||
Current income tax expense (recovery) | 374 | (164) | (618) | ||
Deferred income tax expense (recovery) | 557 | 640 | (241) | ||
Net earnings (loss) | 2,591 | 2,397 | (204) | ||
Inter–segment elimination and other | |||||
Revenue [abstract] | |||||
Product sales | 558 | 609 | 849 | ||
Less: royalties | 0 | 0 | 0 | ||
Revenue | 558 | 609 | 849 | ||
Expenses | |||||
Production | 58 | 71 | 78 | ||
Transportation, blending and feedstock | 491 | 527 | 751 | ||
Depletion, depreciation and amortization | 0 | 0 | 0 | ||
Asset retirement obligation accretion | 0 | 0 | 0 | ||
Realized risk management (commodity derivatives) | 0 | 0 | 0 | ||
Gain on acquisition, disposition and revaluation of properties | 0 | 0 | 0 | ||
Loss (gain) from investments | 0 | 0 | 0 | ||
Total expenses | 549 | 598 | 829 | ||
Earnings (loss) before taxes | 9 | 11 | 20 | ||
Non-segmented | |||||
Expenses | |||||
Loss (gain) from investments | 341 | (7) | (320) | ||
Total expenses | 1,962 | 370 | 735 | ||
Administration | 325 | 319 | 345 | ||
Share-based compensation | (146) | 134 | 355 | ||
Interest and other financing expense | 739 | 631 | 383 | ||
Net unrealized risk management (gain) loss | (124) | 80 | 27 | ||
Foreign exchange loss (gain) | 827 | (787) | (55) | ||
Total Segments | |||||
Revenue [abstract] | |||||
Product sales | 22,282 | 18,360 | 12,002 | ||
Less: royalties | (1,255) | (1,018) | (575) | ||
Revenue | 21,027 | 17,342 | 11,427 | ||
Expenses | |||||
Production | 6,464 | 5,675 | 4,184 | ||
Transportation, blending and feedstock | 4,189 | 3,529 | 2,822 | ||
Depletion, depreciation and amortization | 5,161 | 5,186 | 4,858 | ||
Asset retirement obligation accretion | 186 | 164 | 142 | ||
Realized risk management (commodity derivatives) | (10) | (45) | 6 | ||
Gain on acquisition, disposition and revaluation of properties | (452) | (379) | (250) | ||
Loss (gain) from investments | 5 | (31) | (7) | ||
Total expenses | 15,543 | 14,099 | 11,755 | ||
Earnings (loss) before taxes | 5,484 | 3,243 | (328) | ||
North America | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 8,510 | 9,161 | 7,209 | ||
Less: royalties | (723) | (809) | (524) | ||
Revenue | 7,787 | 8,352 | 6,685 | ||
Expenses | |||||
Production | 2,405 | 2,362 | 2,186 | ||
Transportation, blending and feedstock | 2,587 | 2,291 | 1,941 | ||
Depletion, depreciation and amortization | 3,132 | 3,243 | 3,465 | ||
Asset retirement obligation accretion | 87 | 80 | 66 | ||
Realized risk management (commodity derivatives) | (10) | (45) | 6 | ||
Gain on acquisition, disposition and revaluation of properties | (277) | (35) | (32) | ||
Loss (gain) from investments | 0 | 0 | 0 | ||
Total expenses | 7,924 | 7,896 | 7,632 | ||
Earnings (loss) before taxes | (137) | 456 | (947) | ||
North Sea | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 893 | 784 | 570 | ||
Less: royalties | (2) | (1) | (1) | ||
Revenue | 891 | 783 | 569 | ||
Expenses | |||||
Production | 405 | 400 | 403 | ||
Transportation, blending and feedstock | 22 | 31 | 48 | ||
Depletion, depreciation and amortization | 257 | 509 | 458 | ||
Asset retirement obligation accretion | 29 | 27 | 35 | ||
Realized risk management (commodity derivatives) | 0 | 0 | 0 | ||
Gain on acquisition, disposition and revaluation of properties | (139) | 0 | 0 | ||
Loss (gain) from investments | 0 | 0 | 0 | ||
Total expenses | 574 | 967 | 944 | ||
Earnings (loss) before taxes | 317 | (184) | (375) | ||
Offshore Africa | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 698 | 632 | 603 | ||
Less: royalties | (51) | (41) | (26) | ||
Revenue | 647 | 591 | 577 | ||
Expenses | |||||
Production | 208 | 226 | 200 | ||
Transportation, blending and feedstock | 2 | 1 | 2 | ||
Depletion, depreciation and amortization | 201 | 205 | 262 | ||
Asset retirement obligation accretion | 9 | 9 | 12 | ||
Realized risk management (commodity derivatives) | 0 | 0 | 0 | ||
Gain on acquisition, disposition and revaluation of properties | (36) | 0 | 0 | ||
Loss (gain) from investments | 0 | 0 | 0 | ||
Total expenses | 384 | 441 | 476 | ||
Earnings (loss) before taxes | 263 | 150 | 101 | ||
Oil Sands Mining and Upgrading | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 11,521 | 7,072 | 2,657 | ||
Less: royalties | (479) | (167) | (24) | ||
Revenue | 11,042 | 6,905 | 2,633 | ||
Expenses | |||||
Production | 3,367 | 2,600 | 1,292 | ||
Transportation, blending and feedstock | 1,087 | 679 | 80 | ||
Depletion, depreciation and amortization | 1,557 | 1,220 | 662 | ||
Asset retirement obligation accretion | 61 | 48 | 29 | ||
Realized risk management (commodity derivatives) | 0 | 0 | 0 | ||
Gain on acquisition, disposition and revaluation of properties | 0 | (230) | 0 | ||
Loss (gain) from investments | 0 | 0 | 0 | ||
Total expenses | 6,072 | 4,317 | 2,063 | ||
Earnings (loss) before taxes | 4,970 | 2,588 | 570 | ||
Midstream | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 102 | 102 | 114 | ||
Less: royalties | 0 | 0 | 0 | ||
Revenue | 102 | 102 | 114 | ||
Expenses | |||||
Production | 21 | 16 | 25 | ||
Transportation, blending and feedstock | 0 | 0 | 0 | ||
Depletion, depreciation and amortization | 14 | 9 | 11 | ||
Asset retirement obligation accretion | 0 | 0 | 0 | ||
Realized risk management (commodity derivatives) | 0 | 0 | 0 | ||
Gain on acquisition, disposition and revaluation of properties | 0 | (114) | (218) | ||
Loss (gain) from investments | 5 | (31) | (7) | ||
Total expenses | 40 | (120) | (189) | ||
Earnings (loss) before taxes | 62 | 222 | 303 | ||
Crude oil and NGLs | Inter–segment elimination and other | |||||
Revenue [abstract] | |||||
Product sales | 410 | 448 | 682 | ||
Crude oil and NGLs | Total Segments | |||||
Revenue [abstract] | |||||
Product sales | 20,668 | 16,522 | 10,396 | ||
Crude oil and NGLs | North America | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 7,254 | 7,655 | 5,933 | ||
Crude oil and NGLs | North Sea | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 753 | 666 | 478 | ||
Crude oil and NGLs | Offshore Africa | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 628 | 579 | 532 | ||
Crude oil and NGLs | Oil Sands Mining and Upgrading | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 11,521 | 7,072 | 2,657 | ||
Crude oil and NGLs | Midstream | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 102 | 102 | 114 | ||
Natural gas | Inter–segment elimination and other | |||||
Revenue [abstract] | |||||
Product sales | 148 | 161 | 167 | ||
Natural gas | Total Segments | |||||
Revenue [abstract] | |||||
Product sales | 1,614 | 1,838 | 1,606 | ||
Natural gas | North America | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 1,256 | 1,506 | 1,276 | ||
Natural gas | North Sea | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 140 | 118 | 92 | ||
Natural gas | Offshore Africa | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 70 | 53 | 71 | ||
Natural gas | Oil Sands Mining and Upgrading | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | 0 | 0 | 0 | ||
Natural gas | Midstream | Operating segments | |||||
Revenue [abstract] | |||||
Product sales | $ 0 | $ 0 | $ 0 | ||
[1] | In connection with adoption of IFRS 15 on January 1, 2018, the Company has reclassified certain comparative amounts in a manner consistent with the presentation adopted for the year ended December 31, 2018 (see note 2). |
SEGMENTED INFORMATION - Capital
SEGMENTED INFORMATION - Capital Expenditures (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | May 31, 2017 | |
Exploration and evaluation assets | |||
Net expenditures (2) | $ 282 | $ 317 | |
Non-cash and fair value changes | (277) | (67) | |
Capitalized costs | 5 | 250 | |
Property, plant and equipment | |||
Net expenditures (2) | 4,175 | 12,755 | |
Non-cash and fair value changes | (1,211) | 6,029 | |
Capitalized costs | 2,964 | 18,784 | |
Pre-tax non-cash revaluation gain | 19 | 114 | |
Head office | |||
Property, plant and equipment | |||
Net expenditures (2) | 21 | 19 | |
Non-cash and fair value changes | 0 | 0 | |
Capitalized costs | 21 | 19 | |
North America | |||
Property, plant and equipment | |||
Gain on sale of exploration and evaluation assets | 16 | 35 | |
North America | Operating segments | |||
Exploration and evaluation assets | |||
Net expenditures (2) | 118 | 160 | |
Non-cash and fair value changes | (52) | (184) | |
Capitalized costs | 66 | (24) | |
Property, plant and equipment | |||
Net expenditures (2) | 2,553 | 2,815 | |
Non-cash and fair value changes | (362) | 354 | |
Capitalized costs | 2,191 | 3,169 | |
North Sea | |||
Property, plant and equipment | |||
Pre-tax non-cash revaluation gain | 19 | ||
North Sea | Operating segments | |||
Exploration and evaluation assets | |||
Net expenditures (2) | 0 | 0 | |
Non-cash and fair value changes | 0 | 0 | |
Capitalized costs | 0 | 0 | |
Property, plant and equipment | |||
Net expenditures (2) | 131 | 160 | |
Non-cash and fair value changes | (597) | 95 | |
Capitalized costs | (466) | 255 | |
Offshore Africa | Operating segments | |||
Exploration and evaluation assets | |||
Net expenditures (2) | (54) | 15 | |
Non-cash and fair value changes | 0 | 0 | |
Capitalized costs | (54) | 15 | |
Property, plant and equipment | |||
Net expenditures (2) | 228 | 89 | |
Non-cash and fair value changes | (86) | 12 | |
Capitalized costs | 142 | 101 | |
Oil Sands Mining and Upgrading | Operating segments | |||
Exploration and evaluation assets | |||
Net expenditures (2) | 218 | 142 | |
Non-cash and fair value changes | (225) | 117 | |
Capitalized costs | (7) | 259 | |
Property, plant and equipment | |||
Net expenditures (2) | 1,229 | 9,592 | |
Non-cash and fair value changes | (166) | 5,454 | |
Capitalized costs | 1,063 | 15,046 | |
Exploration and Production | Operating segments | |||
Property, plant and equipment | |||
Net expenditures (2) | 2,912 | 3,064 | |
Non-cash and fair value changes | (1,045) | 461 | |
Capitalized costs | 1,867 | 3,525 | |
Midstream | |||
Property, plant and equipment | |||
Pre-tax non-cash revaluation gain | 114 | 114 | |
After-tax non-cash revaluation gain | 83 | 83 | |
Midstream | Operating segments | |||
Property, plant and equipment | |||
Net expenditures (2) | 13 | 80 | |
Non-cash and fair value changes | 0 | 114 | |
Capitalized costs | $ 13 | 194 | |
AOSP | |||
Property, plant and equipment | |||
Non-cash share considerations issued on the acquisition of AOSP and other assets | $ 3,818 | $ 3,818 |
SEGMENTED INFORMATION - Segment
SEGMENTED INFORMATION - Segmented Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Disclosure of operating segments [line items] | ||
Assets | $ 71,559 | $ 73,867 |
Head office | ||
Disclosure of operating segments [line items] | ||
Assets | 110 | 110 |
North America | Operating segments | ||
Disclosure of operating segments [line items] | ||
Assets | 27,199 | 28,705 |
North Sea | Operating segments | ||
Disclosure of operating segments [line items] | ||
Assets | 1,699 | 1,854 |
Offshore Africa | Operating segments | ||
Disclosure of operating segments [line items] | ||
Assets | 1,471 | 1,331 |
Other | Operating segments | ||
Disclosure of operating segments [line items] | ||
Assets | 33 | 29 |
Oil Sands Mining and Upgrading | Operating segments | ||
Disclosure of operating segments [line items] | ||
Assets | 39,634 | 40,559 |
Midstream | Operating segments | ||
Disclosure of operating segments [line items] | ||
Assets | $ 1,413 | $ 1,279 |
REMUNERATION OF DIRECTORS AND_3
REMUNERATION OF DIRECTORS AND SENIOR MANAGEMENT (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Non-management directors | |||
Disclosure of transactions between related parties [line items] | |||
Fees earned and salary | $ 2 | $ 3 | $ 2 |
Senior management | |||
Disclosure of transactions between related parties [line items] | |||
Fees earned and salary | 2 | 3 | 3 |
Common stock option based awards | 8 | 10 | 9 |
Annual incentive plans | 4 | 5 | 5 |
Long-term incentive plans | 15 | 17 | 15 |
Total | $ 29 | $ 35 | $ 32 |
SUPPLEMENTARY OIL & GAS INFOR_3
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) - Twelve Month Average Benchmark Prices (Details) | 12 Months Ended |
Dec. 31, 2018$ / bbl$ / MMBTU$ / bbl$ / MMBTU | |
Crude Oil and NGLs | WTI Cushing Oklahoma | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Twelve month average benchmark price dollars per bbl | 65.55 |
Crude Oil and NGLs | WCS | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Twelve month average benchmark price dollars per bbl | 53.67 |
Crude Oil and NGLs | Canadian Light Sweet | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Twelve month average benchmark price dollars per bbl | 70.32 |
Crude Oil and NGLs | Cromer LSB | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Twelve month average benchmark price dollars per bbl | 75.54 |
Crude Oil and NGLs | North Sea Brent | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Twelve month average benchmark price dollars per bbl | 72.09 |
Crude Oil and NGLs | Edmonton C5 | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Twelve month average benchmark price dollars per bbl | 80.65 |
Natural Gas | Henry Hub Louisiana | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Twelve month average benchmark price dollars per MMBtu | $ / MMBTU | 3.02 |
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 | 1.46 |
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 | 1.25 |
USD | |
Oil And Gas, Average Sale Price And Production Cost Per Unit1 [Line Items] | |
Average foreign exchange rate | 1 |
SUPPLEMENTARY OIL & GAS INFOR_4
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) - Proved and Proved Developed Oil and Natural Gas Reserves, Net of Royalties (Details) - MMBbls | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Crude Oil, Synthetic Crude Oil, Bitumen, Natural Gas, Natural Gas Liquids | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 7,091 | 4,514 | 4,209 | |
Extensions and discoveries (in MMbbl) | 912 | 45 | 61 | |
Improved recovery (in MMbbl) | 64 | 27 | 22 | |
Purchases of reserves in place (in MMbbl) | 16 | 2,336 | 18 | |
Sales of reserves in place (in MMbbl) | 4 | 0 | 0 | |
Production (in MMbbl) | 274 | 229 | 176 | |
Economic revisions due to prices (in MMbbl) | 51 | (54) | (103) | |
Revisions of prior estimates (in MMbbl) | 165 | 344 | 277 | |
Proved reserves, net, ending balance | 7,919 | 7,091 | 4,514 | |
Net proved developed reserves (in MMbbl) | 6,571 | 5,825 | 3,307 | 2,990 |
Change in proved developed and undeveloped reserves, net (in MMbbl) | 828 | 2,577 | 305 | |
North America | Synthetic Crude Oil | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 4,956 | 2,542 | 2,283 | |
Extensions and discoveries (in MMbbl) | 744 | 0 | 0 | |
Improved recovery (in MMbbl) | 0 | 0 | 0 | |
Purchases of reserves in place (in MMbbl) | 0 | 2,232 | 0 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | 148 | 100 | 45 | |
Economic revisions due to prices (in MMbbl) | 0 | 0 | (108) | |
Revisions of prior estimates (in MMbbl) | 109 | 282 | 196 | |
Proved reserves, net, ending balance | 5,661 | 4,956 | 2,542 | |
Net proved developed reserves (in MMbbl) | 5,661 | 4,967 | 2,527 | 2,194 |
North America | Bitumen | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 1,365 | 1,301 | 1,263 | |
Extensions and discoveries (in MMbbl) | 151 | 28 | 46 | |
Improved recovery (in MMbbl) | 10 | 7 | 5 | |
Purchases of reserves in place (in MMbbl) | 2 | 37 | 3 | |
Sales of reserves in place (in MMbbl) | 4 | 0 | 0 | |
Production (in MMbbl) | 64 | 70 | 71 | |
Economic revisions due to prices (in MMbbl) | 45 | (18) | (23) | |
Revisions of prior estimates (in MMbbl) | 54 | 44 | 32 | |
Proved reserves, net, ending balance | 1,469 | 1,365 | 1,301 | |
Net proved developed reserves (in MMbbl) | 461 | 410 | 384 | 411 |
North America | Crude Oil and NGLs | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 594 | 504 | 471 | |
Extensions and discoveries (in MMbbl) | 17 | 17 | 15 | |
Improved recovery (in MMbbl) | 50 | 19 | 14 | |
Purchases of reserves in place (in MMbbl) | 7 | 67 | 15 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | 47 | 44 | 43 | |
Economic revisions due to prices (in MMbbl) | 18 | (17) | 19 | |
Revisions of prior estimates (in MMbbl) | 1 | 14 | 51 | |
Proved reserves, net, ending balance | 604 | 594 | 504 | |
Net proved developed reserves (in MMbbl) | 378 | 399 | 353 | 341 |
North America | Crude Oil, Synthetic Crude Oil, Bitumen, Natural Gas, Natural Gas Liquids | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 6,915 | 4,347 | 4,017 | |
Extensions and discoveries (in MMbbl) | 912 | 45 | 61 | |
Improved recovery (in MMbbl) | 60 | 26 | 19 | |
Purchases of reserves in place (in MMbbl) | 9 | 2,336 | 18 | |
Sales of reserves in place (in MMbbl) | 4 | 0 | 0 | |
Production (in MMbbl) | 259 | 214 | 159 | |
Economic revisions due to prices (in MMbbl) | 63 | (35) | (112) | |
Revisions of prior estimates (in MMbbl) | 164 | 340 | 279 | |
Proved reserves, net, ending balance | 7,734 | 6,915 | 4,347 | |
Net proved developed reserves (in MMbbl) | 6,500 | 5,776 | 3,264 | 2,946 |
North Sea | Crude Oil and NGLs | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 107 | 93 | 119 | |
Extensions and discoveries (in MMbbl) | 0 | 0 | 0 | |
Improved recovery (in MMbbl) | 1 | 1 | 1 | |
Purchases of reserves in place (in MMbbl) | 7 | 0 | 0 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | 9 | 9 | 9 | |
Economic revisions due to prices (in MMbbl) | (11) | (18) | 10 | |
Revisions of prior estimates (in MMbbl) | (3) | 4 | (8) | |
Proved reserves, net, ending balance | 114 | 107 | 93 | |
Net proved developed reserves (in MMbbl) | 37 | 28 | 12 | 3 |
Offshore Africa | Crude Oil and NGLs | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 69 | 74 | 73 | |
Extensions and discoveries (in MMbbl) | 0 | 0 | 0 | |
Improved recovery (in MMbbl) | 3 | 0 | 2 | |
Purchases of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Sales of reserves in place (in MMbbl) | 0 | 0 | 0 | |
Production (in MMbbl) | 6 | 6 | 8 | |
Economic revisions due to prices (in MMbbl) | (1) | (1) | (1) | |
Revisions of prior estimates (in MMbbl) | 4 | 0 | 6 | |
Proved reserves, net, ending balance | 71 | 69 | 74 | |
Net proved developed reserves (in MMbbl) | 34 | 21 | 31 | 41 |
SUPPLEMENTARY OIL & GAS INFOR_5
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) - Proved and Proved Developed Natural Gas Reserve Quantities (Details) - Natural Gas | 12 Months Ended | |||
Dec. 31, 2018MMBblsBcf | Dec. 31, 2017MMBblsBcf | Dec. 31, 2016MMBblsBcf | Dec. 31, 2015Bcf | |
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 5,240 | 4,644 | 4,582 | |
Extensions and discoveries (in Bcf) | 90 | 261 | 176 | |
Improved recovery (in Bcf) | 414 | 179 | 169 | |
Purchases of reserves in place (in Bcf) | 67 | 106 | 85 | |
Sales of reserves in place (in Bcf) | (3) | 0 | 5 | |
Production (in Bcf) | (542) | (579) | (596) | |
Economic revisions due to prices (in Bcf) | 748 | (407) | 581 | |
Revisions of prior estimates (in Bcf) | 164 | (222) | (814) | |
Proved reserves, net, ending balance | 4,354 | 5,240 | 4,644 | |
Net proved developed reserves (in Bcf) | 2,417 | 3,112 | 2,841 | 2,924 |
Change in proved developed and undeveloped reserves, net (in Bcf) | MMBbls | 886 | 596 | 62 | |
North America | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 5,199 | 4,594 | 4,523 | |
Extensions and discoveries (in Bcf) | 90 | 261 | 176 | |
Improved recovery (in Bcf) | 414 | 179 | 166 | |
Purchases of reserves in place (in Bcf) | 67 | 106 | 85 | |
Sales of reserves in place (in Bcf) | 3 | 0 | 5 | |
Production (in Bcf) | (523) | (558) | (571) | |
Economic revisions due to prices (in Bcf) | 746 | (403) | 572 | |
Revisions of prior estimates (in Bcf) | 192 | (214) | (792) | |
Proved reserves, net, ending balance | 4,306 | 5,199 | 4,594 | |
Net proved developed reserves (in Bcf) | 2,382 | 3,081 | 2,805 | 2,883 |
North Sea | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 25 | 25 | 38 | |
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) | (11) | (14) | (14) | |
Economic revisions due to prices (in Bcf) | 0 | (5) | 10 | |
Revisions of prior estimates (in Bcf) | (13) | (9) | (11) | |
Proved reserves, net, ending balance | 27 | 25 | 25 | |
Net proved developed reserves (in Bcf) | 23 | 22 | 18 | 26 |
Offshore Africa | ||||
Proved Developed And Undeveloped Reserves [Roll Forward] | ||||
Proved reserves, net, beginning balance | 16 | 25 | 21 | |
Extensions and discoveries (in Bcf) | 0 | 0 | 0 | |
Improved recovery (in Bcf) | 0 | 0 | 3 | |
Purchases of reserves in place (in Bcf) | 0 | 0 | 0 | |
Sales of reserves in place (in Bcf) | 0 | 0 | 0 | |
Production (in Bcf) | (8) | (7) | (11) | |
Economic revisions due to prices (in Bcf) | 2 | 1 | (1) | |
Revisions of prior estimates (in Bcf) | (15) | 1 | (11) | |
Proved reserves, net, ending balance | 21 | 16 | 25 | |
Net proved developed reserves (in Bcf) | 12 | 9 | 18 | 15 |
SUPPLEMENTARY OIL & GAS INFOR_6
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) - Capitalized Costs Related to Crude Oil and Natural Gas Activities (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Capitalized costs, proved properties | $ 122,946 | $ 118,907 | $ 101,197 |
Capitalized costs, unproved properties | 2,637 | 2,632 | 2,382 |
Capitalized costs, gross | 125,583 | 121,539 | 103,579 |
Net capitalized costs | 66,783 | 67,388 | 53,059 |
Oil and gas assets | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Less: accumulated depletion and depreciation | (58,800) | (54,151) | (50,520) |
North America | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Capitalized costs, proved properties | 110,154 | 106,900 | 88,685 |
Capitalized costs, unproved properties | 2,600 | 2,541 | 2,306 |
Capitalized costs, gross | 112,754 | 109,441 | 90,991 |
Net capitalized costs | 63,892 | 64,662 | 49,852 |
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 | (48,862) | (44,779) | (41,139) |
North Sea | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Capitalized costs, proved properties | 7,321 | 7,126 | 7,380 |
Capitalized costs, unproved properties | 0 | 0 | 0 |
Capitalized costs, gross | 7,321 | 7,126 | 7,380 |
Net capitalized costs | 1,586 | 1,473 | 1,796 |
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 | (5,735) | (5,653) | (5,584) |
Offshore Africa | |||
Capitalized Costs Relating To Oil And Gas Producing Activities, By Geographic Area1 [Line Items] | |||
Capitalized costs, proved properties | 5,471 | 4,881 | 5,132 |
Capitalized costs, unproved properties | 37 | 91 | 76 |
Capitalized costs, gross | 5,508 | 4,972 | 5,208 |
Net capitalized costs | 1,305 | 1,253 | 1,411 |
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 | $ (4,203) | $ (3,719) | $ (3,797) |
SUPPLEMENTARY OIL & GAS INFOR_7
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Property acquisitions, proved | $ 341 | $ 15,091 | $ 50 |
Property acquisitions, unproved | 251 | 321 | 0 |
Exploration | 151 | 127 | 26 |
Development | 3,567 | 4,109 | 4,427 |
Costs incurred | 4,310 | 19,648 | 4,503 |
North Sea | |||
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Property acquisitions, proved | 127 | 0 | 0 |
Property acquisitions, unproved | 0 | 0 | 0 |
Exploration | 0 | 0 | 0 |
Development | 110 | 255 | 186 |
Costs incurred | 237 | 255 | 186 |
Offshore Africa | |||
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Property acquisitions, proved | 0 | 0 | 0 |
Property acquisitions, unproved | (89) | 0 | 0 |
Exploration | 35 | 15 | 9 |
Development | 212 | 101 | 116 |
Costs incurred | 158 | 116 | 125 |
North America | |||
Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities1 [Line Items] | |||
Property acquisitions, proved | 214 | 15,091 | 50 |
Property acquisitions, unproved | 340 | 321 | 0 |
Exploration | 116 | 112 | 17 |
Development | 3,245 | 3,753 | 4,125 |
Costs incurred | $ 3,915 | $ 19,277 | $ 4,192 |
SUPPLEMENTARY OIL & GAS INFOR_8
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) - Results of Operations from Crude Oil and Natural Gas Producing Activities (Details) - CAD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||
Supplementary Oil & Gas Information [Line Items] | |||||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | $ 21,027 | $ 17,342 | $ 11,427 | ||
Production | (6,464) | (5,675) | [1] | (4,184) | [1] |
Transportation | (4,189) | (3,529) | [1] | (2,822) | [1] |
Depletion, depreciation and amortization | (5,161) | (5,186) | (4,858) | ||
Asset retirement obligation accretion | (186) | (164) | (142) | ||
Income tax | (374) | 164 | 618 | ||
Oil And Gas | |||||
Supplementary Oil & Gas Information [Line Items] | |||||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 17,603 | 14,445 | 8,933 | ||
Production | (6,385) | (5,588) | (4,081) | ||
Transportation | (953) | (822) | (673) | ||
Depletion, depreciation and amortization | (5,147) | (5,177) | (4,847) | ||
Asset retirement obligation accretion | (186) | (164) | (142) | ||
Petroleum revenue tax | 12 | 78 | 333 | ||
Income tax | (1,350) | (726) | 139 | ||
Results of operations | 3,594 | 2,046 | (338) | ||
Oil And Gas | North America | |||||
Supplementary Oil & Gas Information [Line Items] | |||||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 16,065 | 13,083 | 7,791 | ||
Production | (5,772) | (4,962) | (3,478) | ||
Transportation | (929) | (790) | (623) | ||
Depletion, depreciation and amortization | (4,689) | (4,463) | (4,127) | ||
Asset retirement obligation accretion | (148) | (128) | (95) | ||
Petroleum revenue tax | 0 | 0 | 0 | ||
Income tax | (1,223) | (740) | 143 | ||
Results of operations | 3,304 | 2,000 | (389) | ||
Oil And Gas | North Sea | |||||
Supplementary Oil & Gas Information [Line Items] | |||||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 891 | 784 | 565 | ||
Production | (405) | (400) | (403) | ||
Transportation | (22) | (31) | (48) | ||
Depletion, depreciation and amortization | (257) | (509) | (458) | ||
Asset retirement obligation accretion | (29) | (27) | (35) | ||
Petroleum revenue tax | 12 | 78 | 333 | ||
Income tax | (76) | 42 | 18 | ||
Results of operations | 114 | (63) | (28) | ||
Oil And Gas | Offshore Africa | |||||
Supplementary Oil & Gas Information [Line Items] | |||||
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs | 647 | 578 | 577 | ||
Production | (208) | (226) | (200) | ||
Transportation | (2) | (1) | (2) | ||
Depletion, depreciation and amortization | (201) | (205) | (262) | ||
Asset retirement obligation accretion | (9) | (9) | (12) | ||
Petroleum revenue tax | 0 | 0 | 0 | ||
Income tax | (51) | (28) | (22) | ||
Results of operations | $ 176 | $ 109 | $ 79 | ||
[1] | In connection with adoption of IFRS 15 on January 1, 2018, the Company has reclassified certain comparative amounts in a manner consistent with the presentation adopted for the year ended December 31, 2018 (see note 2). |
SUPPLEMENTARY OIL & GAS INFOR_9
SUPPLEMENTARY OIL & GAS INFORMATION (Unaudited) - Future Net Cash Flows Relating to Proved Crude Oil and Natural Gas Reserves (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 519,006 | $ 426,706 | $ 216,857 | |
Future production costs | (200,819) | (204,348) | (97,013) | |
Future development costs and asset retirement obligations | (67,210) | (65,280) | (46,650) | |
Future income taxes | (62,636) | (36,488) | (15,241) | |
Future net cash flows | 188,341 | 120,590 | 57,953 | |
10% annual discount for timing of future cash flows | (128,015) | (73,685) | (33,638) | |
Standardized measure of future net cash flows | 60,326 | 46,905 | 24,315 | $ 27,536 |
North America | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 500,557 | 413,180 | 206,729 | |
Future production costs | (193,387) | (198,304) | (92,070) | |
Future development costs and asset retirement obligations | (63,202) | (61,169) | (42,167) | |
Future income taxes | (60,526) | (35,645) | (15,396) | |
Future net cash flows | 183,442 | 118,062 | 57,096 | |
10% annual discount for timing of future cash flows | (126,699) | (73,171) | (33,590) | |
Standardized measure of future net cash flows | 56,743 | 44,891 | 23,506 | |
North Sea | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 12,002 | 8,740 | 5,999 | |
Future production costs | (5,148) | (4,168) | (3,284) | |
Future development costs and asset retirement obligations | (2,909) | (2,853) | (3,249) | |
Future income taxes | (1,484) | (595) | 280 | |
Future net cash flows | 2,461 | 1,124 | (254) | |
10% annual discount for timing of future cash flows | (545) | (59) | 271 | |
Standardized measure of future net cash flows | 1,916 | 1,065 | 17 | |
Offshore Africa | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | 6,447 | 4,786 | 4,129 | |
Future production costs | (2,284) | (1,876) | (1,659) | |
Future development costs and asset retirement obligations | (1,099) | (1,258) | (1,234) | |
Future income taxes | (626) | (248) | (125) | |
Future net cash flows | 2,438 | 1,404 | 1,111 | |
10% annual discount for timing of future cash flows | (771) | (455) | (319) | |
Standardized measure of future net cash flows | $ 1,667 | $ 949 | $ 792 |
SUPPLEMENTARY OIL & GAS INFO_10
SUPPLEMENTARY OIL & 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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
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 | $ (10,229) | $ (8,013) | $ (4,159) |
Net changes in sales prices and production costs | 20,386 | 7,466 | (7,305) |
Extensions, discoveries and improved recovery | 2,807 | 481 | 700 |
Changes in estimated future development costs | (698) | (5,548) | 1,750 |
Purchases of proved reserves in place | 396 | 25,782 | 352 |
Sales of proved reserves in place | (55) | 0 | (2) |
Revisions of previous reserve estimates | 2,711 | 4,245 | 3,668 |
Accretion of discount | 6,119 | 3,075 | 3,527 |
Changes in production timing and other | (955) | (662) | (2,137) |
Net change in income taxes | (7,061) | (4,236) | 385 |
Net change | 13,421 | 22,590 | (3,221) |
Balance - beginning of year | 46,905 | 24,315 | 27,536 |
Balance - end of year | $ 60,326 | $ 46,905 | $ 24,315 |