Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2020shares | |
Document Information [Line Items] | |
Entity Central Index Key | 0001126874 |
Document Type | 40-F |
Document Registration Statement | false |
Document Annual Report | true |
Document Period End Date | Dec. 31, 2020 |
Entity File Number | 001-15150 |
Entity Registrant Name | ENERPLUS CORPORATION |
Entity Incorporation, State or Country Code | A0 |
Entity Primary SIC Number | 1311 |
Entity Address, Address Line One | The Dome Tower, 3000 |
Entity Address, Address Line Two | 333 - 7th Avenue S.W. |
Entity Address, City or Town | Calgary |
Entity Address, State or Province | AB |
Entity Address, Country | CA |
Entity Address, Postal Zip Code | T2P 2Z1 |
City Area Code | 403 |
Local Phone Number | 298-2200 |
Title of 12(b) Security | Common Shares |
Trading Symbol | ERF |
Security Exchange Name | NYSE |
Annual Information Form | true |
Audited Annual Financial Statements | true |
Entity Common Stock, Shares Outstanding | 222,547,600 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity Emerging Growth Company | false |
ICFR Auditor Attestation Flag | true |
Current Fiscal Year End Date | --12-31 |
Document Fiscal Year Focus | 2020 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Business Contact [Member] | |
Document Information [Line Items] | |
Contact Personnel Name | CT Corporation System |
Entity Address, Address Line One | 28 Liberty Street |
Entity Address, City or Town | New York |
Entity Address, State or Province | NY |
Entity Address, Postal Zip Code | 10005 |
City Area Code | 212 |
Local Phone Number | 894-8940 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Current assets | ||
Cash and cash equivalents | $ 114,455 | $ 151,649 |
Accounts receivable | 106,209 | 176,119 |
Income tax receivable | 167 | 27,770 |
Derivative financial assets | 3,550 | 10,570 |
Other current assets | 7,137 | 2,990 |
Total Current Assets | 231,518 | 369,098 |
Property, plant and equipment: | ||
Crude oil and natural gas properties (full cost method) | 575,559 | 1,547,362 |
Other capital assets, net | 19,524 | 20,244 |
Property, plant and equipment | 595,083 | 1,567,606 |
Right of use assets | 32,853 | 48,729 |
Goodwill | 0 | 194,015 |
Deferred income tax asset | 607,001 | 372,502 |
Income tax receivable | 13,852 | |
Total Assets | 1,466,455 | 2,565,802 |
Current liabilities | ||
Accounts payable | 251,822 | 291,540 |
Dividends payable | 2,225 | 2,217 |
Current portion of long-term debt | 103,836 | 105,998 |
Derivative financial liabilities | 19,261 | 2,734 |
Current portion of lease liabilities | 13,391 | 17,541 |
Total Current Liabilities | 390,535 | 420,030 |
Long-term debt | 386,586 | 500,635 |
Asset retirement obligation | 130,208 | 138,049 |
Lease liabilities | 23,446 | 35,530 |
Total Non-current Liabilities | 540,240 | 674,214 |
Total Liabilities | 930,775 | 1,094,244 |
Shareholders' Equity | ||
Share capital - authorized unlimited common shares, no par value Issued and outstanding: December 31, 2019 - 222 million shares December 31, 2018 - 239 million shares | 3,096,969 | 3,088,094 |
Paid-in capital | 50,604 | 59,490 |
Accumulated deficit | (2,932,017) | (1,984,365) |
Accumulated other comprehensive income | 320,124 | 308,339 |
Total Shareholders' Equity | 535,680 | 1,471,558 |
Total Liabilities & Shareholders' Equity | 1,466,455 | 2,565,802 |
Commitments and Contingencies |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Share capital | ||
Share capital, shares authorized, unlimited | Unlimited | Unlimited |
Share capital, par value (in CAD per share) | $ 0 | $ 0 |
Share capital, shares issued (in shares) | 223 | 222 |
Share capital, shares outstanding (in shares) | 223 | 222 |
Consolidated Statements of Inco
Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Revenues | |||
Crude oil and natural gas sales, net of royalties | $ 737,205 | $ 1,254,806 | $ 1,292,736 |
Type of revenue | us-gaap:OilAndGasMember | us-gaap:OilAndGasMember | us-gaap:OilAndGasMember |
Commodity derivative instruments gain/(loss) | $ 108,819 | $ (66,071) | $ 88,232 |
Total | 846,024 | 1,188,735 | 1,380,968 |
Expenses | |||
Production taxes | 49,900 | 83,109 | 87,286 |
General and administrative | 57,583 | 72,853 | 75,783 |
Depletion, depreciation and accretion | 293,156 | 356,830 | 304,274 |
Asset impairment | 994,776 | ||
Goodwill impairment | 202,767 | 451,121 | 0 |
Interest | 28,362 | 33,919 | 36,799 |
Foreign exchange (gain)/loss | 1,338 | (25,378) | 39,521 |
Other expense /(income) | 6,303 | (7,529) | (5,909) |
Total | 2,030,146 | 1,400,594 | 899,478 |
Income/(Loss) Before Taxes | (1,184,122) | (211,859) | 481,490 |
Current income tax expense/(recovery) | (14,525) | (33,414) | (27,093) |
Deferred income tax expense/(recovery) | (246,230) | 81,275 | 130,304 |
Net Income/(Loss) | (923,367) | (259,720) | 378,279 |
Other Comprehensive Income/(Loss) | |||
Unrealized gain/(loss) on foreign currency translation | 9,583 | (80,602) | 125,817 |
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt, net of tax | 2,202 | ||
Other Comprehensive Income/(Loss) | 11,785 | (80,602) | 125,817 |
Total Comprehensive Income/(Loss) | $ (911,582) | $ (340,322) | $ 504,096 |
Net Income/(Loss) per Share | |||
Basic (in CAD per share) | $ (4.15) | $ (1.12) | $ 1.55 |
Diluted (in CAD per share) | $ (4.15) | $ (1.12) | $ 1.53 |
Operating | |||
Expenses | |||
Costs of goods sold | $ 263,575 | $ 290,766 | $ 238,261 |
Transportation | |||
Expenses | |||
Costs of goods sold | $ 132,386 | $ 144,903 | $ 123,463 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders' Equity $ in Thousands, $ in Millions | Share CapitalCAD ($) | Share CapitalUSD ($) | Paid-in CapitalCAD ($) | Accumulated DeficitCAD ($) | Accumulated DeficitUSD ($) | Accumulated Other Comprehensive IncomeCAD ($) | CAD ($) | USD ($) |
Balance, beginning of year at Dec. 31, 2017 | $ 3,386,946 | $ 75,375 | $ (2,124,676) | $ 263,124 | ||||
Increase (decrease) in equity | ||||||||
Purchase of common shares under Normal Course Issuer Bid | (82,596) | 3,569 | ||||||
Share-based compensation - cash settled | (30,648) | |||||||
Share-based compensation - treasury settled | 23,389 | |||||||
Share-based compensation - equity settled | (23,389) | |||||||
Share-based compensation - non-cash | 25,917 | |||||||
Stock Option Plan - cash | 9,138 | |||||||
Stock Option Plan - exercised | 731 | (731) | ||||||
Net income/(loss) | 378,279 | $ 378,279 | ||||||
Dividends declared | (29,256) | (29,300) | ||||||
Unrealized gain/(loss) on foreign currency translation | 125,817 | 125,817 | ||||||
Balance, end of year at Dec. 31, 2018 | 3,337,608 | 46,524 | (1,772,084) | 388,941 | 2,000,989 | |||
Increase (decrease) in equity | ||||||||
Purchase of common shares under Normal Course Issuer Bid | (253,920) | $ (253.9) | 75,127 | $ 75.1 | $ (178.8) | |||
Share-based compensation - cash settled (tax withholding) | (4,952) | |||||||
Share-based compensation - treasury settled | 4,406 | |||||||
Share-based compensation - equity settled | (4,406) | |||||||
Share-based compensation - non-cash | 22,324 | |||||||
Net income/(loss) | (259,720) | (259,720) | ||||||
Dividends declared | (27,688) | (27,700) | ||||||
Unrealized gain/(loss) on foreign currency translation | (80,602) | (80,602) | ||||||
Balance, end of year at Dec. 31, 2019 | 3,088,094 | 59,490 | (1,984,365) | 308,339 | 1,471,558 | |||
Increase (decrease) in equity | ||||||||
Purchase of common shares under Normal Course Issuer Bid | (4,731) | 2,195 | (2,500) | |||||
Share-based compensation - cash settled (tax withholding) | (7,232) | |||||||
Share-based compensation - treasury settled | 13,824 | |||||||
Share-based compensation - equity settled | (13,824) | |||||||
Share-based compensation - non-cash | 12,170 | |||||||
Stock Option Plan - cash | (218) | |||||||
Net income/(loss) | (923,367) | (923,367) | ||||||
Cancellation of predecessor shares | (218) | 218 | ||||||
Dividends declared | (26,698) | (26,700) | ||||||
Unrealized gain/(loss) on foreign currency translation | 9,583 | 9,583 | ||||||
Foreign exchange gain/(loss) on net investment hedge with U.S. denominated debt, net of tax | 2,202 | 2,202 | ||||||
Balance, end of year at Dec. 31, 2020 | $ 3,096,969 | $ 50,604 | $ (2,932,017) | $ 320,124 | $ 535,680 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) | 12 Months Ended |
Dec. 31, 2020$ / shares | |
Dividends declared | |
Dividends declared (in CAD per share) | $ 0.12 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Operating Activities | |||
Net income/(loss) | $ (923,367) | $ (259,720) | $ 378,279 |
Non-cash items add/(deduct): | |||
Depletion, depreciation and accretion | 293,156 | 356,830 | 304,274 |
Asset impairment | 994,776 | ||
Goodwill impairment | 202,767 | 451,121 | 0 |
Changes in fair value of derivative instruments | 23,547 | 81,733 | (124,266) |
Deferred income tax expense/(recovery) | (246,230) | 81,275 | 130,304 |
Foreign exchange (gain)/loss on debt and working capital | 1,931 | (34,085) | 58,628 |
Share-based compensation and general and administrative | 12,726 | 23,044 | 25,917 |
Translation of U.S. dollar cash held in Canada (gain)/loss | (1,147) | 8,794 | (19,630) |
Asset retirement obligation expenditures | (17,709) | (16,715) | (11,263) |
Changes in non-cash operating working capital | 105,915 | 1,963 | (3,459) |
Cash flow from operating activities | 446,365 | 694,240 | 738,784 |
Financing Activities | |||
Repayment of senior notes | (114,010) | (59,429) | (29,044) |
Proceeds from the issuance of shares (net of issue costs) | 9,138 | ||
Purchase of common shares under Normal Course Issuer Bid | (2,536) | (178,793) | (79,027) |
Share-based compensation - cash settled (tax withholding) | (7,232) | (4,952) | |
Dividends | (26,690) | (27,866) | (29,282) |
Cash flow from/(used in) financing activities | (150,468) | (271,040) | (128,215) |
Investing Activities | |||
Capital and office expenditures | (10,121) | (24,362) | (18,009) |
Property and land acquisitions | (333,279) | (606,966) | (604,110) |
Property divestments | 6,145 | 9,539 | (919) |
Cash flow from/(used in) investing activities | (337,255) | (621,789) | (623,038) |
Effect of exchange rate changes on cash and cash equivalents | 4,164 | (13,089) | 29,248 |
Change in cash and cash equivalents | (37,194) | (211,678) | 16,779 |
Cash and cash equivalents, beginning of year | 151,649 | 363,327 | 346,548 |
Cash and cash equivalents, end of year | $ 114,455 | $ 151,649 | $ 363,327 |
REPORTING ENTITY
REPORTING ENTITY | 12 Months Ended |
Dec. 31, 2020 | |
REPORTING ENTITY | |
REPORTING ENTITY | 1) REPORTING ENTITY These annual audited Consolidated Financial Statements (“Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (the “Company” or “Enerplus”) including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada. |
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2020 | |
SIGNIFICANT ACCOUNTING POLICIES | |
SIGNIFICANT ACCOUNTING POLICIES | 2) SIGNIFICANT ACCOUNTING POLICIES The following significant accounting policies are presented to assist the reader in evaluating these Consolidated Financial Statements and, together with the following notes, are an integral part of the Consolidated Financial Statements. a) Basis of Preparation Enerplus’ Consolidated Financial Statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Certain prior period amounts have been restated to conform with current period presentation. i. Reporting Currency These Consolidated Financial Statements are presented in Canadian dollars, which is Enerplus’ reporting currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand unless otherwise indicated. ii. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: crude oil and natural gas reserves and related present value of future cash flows, depreciation, depletion and accretion (“DD&A”), impairment of property, plant and equipment, asset retirement obligations, income taxes, ability to realize deferred income tax assets, impairment assessments of goodwill and the fair value of derivative instruments. The estimation of crude oil and natural gas reserves and the related present value of future cash flows involves the use of independent reservoir engineering specialists and numerous estimates and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions. In the opinion of management, these Consolidated Financial Statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies. In early March 2020, the World Health Organization declared the coronavirus (“COVID-19”) outbreak a pandemic. Responses to the spread of COVID-19 have resulted in a challenging economic climate, with more volatile commodity prices and foreign exchange rates, and a decline in long-term interest rates. Although global economies have begun to recover, markets remain volatile and the timing of a full economic recovery remains uncertain. It is difficult to reliably estimate the length or severity of these developments and their financial impact. The impacts of the economic downturn to Enerplus have been considered in management’s estimates described above at December 31, 2020; however, estimates made during periods of extreme volatility are subject to a higher level of uncertainty and as a result, there may be further prospective material impacts in future periods. iii. Basis of Consolidation These Consolidated Financial Statements include the accounts of Enerplus and its subsidiaries. Intercompany balances and transactions are eliminated on consolidation. Interests in jointly controlled crude oil and natural gas assets are accounted for following the concept of undivided interest, whereby Enerplus’ proportionate share of revenues, expenses, assets and liabilities are included in the accounts. iv. Business Combinations The acquisition method of accounting is used to account for acquisitions that meet the definition of a business under U.S. GAAP. The cost of an acquisition is measured as the fair value of the assets transferred, equity instruments issued and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. b) Revenue Revenue from the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers, net of sales taxes. Enerplus recognizes revenue when it satisfies a performance obligation by transferring control of the product to a customer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the contractual delivery points. Enerplus evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, management considers if Enerplus retains control of the product being delivered to the end customer. As part of this assessment, management considers whether the Company retains the economic benefits associated with the good being delivered to the end customer. Management also considers whether the Company has the primary responsibility for the delivery of the product, the ability to establish prices or the inventory risk. If Enerplus acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction. c) Transportation Enerplus generally sells crude oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which the Company sells crude oil or natural gas at the wellhead and collects a price, net of the transportation incurred by the purchaser. In this case, sales are recorded at the price received from the purchaser, net of transportation costs. Under the other arrangement, Enerplus sells crude oil or natural gas at a specific delivery point, pays transportation to a third party and receives proceeds from the purchaser with no transportation deduction. In this case, transportation costs are recorded as transportation expense on the Consolidated Statements of Income/(Loss). Due to these two distinct selling arrangements, Enerplus’ computed realized prices, before the impact of derivative instruments, include revenues which are reported under two separate bases. d) Crude oil and Natural Gas Properties Enerplus uses the full cost method of accounting for its crude oil and natural gas properties. Under this method, all acquisition, exploration and development costs incurred in finding crude oil and natural gas reserves are capitalized, including general and administrative costs attributable to these activities. These costs are recorded on a country-by-country cost centre basis as crude oil and natural gas properties subject to depletion (“full cost pool”). Costs associated with production and general corporate activities are expensed as incurred. The net carrying value of both proved and unproved crude oil and natural gas properties is depleted using the unit of production method using proved reserves, as determined using a constant price assumption of the simple average of the preceding twelve months’ first-day-of-the-month commodity prices (“SEC prices”). The depletion calculation takes into account estimated future development costs necessary to bring those reserves into production. Under full cost accounting, a ceiling test is performed on a cost centre basis each quarter. Enerplus limits capitalized costs of proved and unproved crude oil and natural gas properties, net of accumulated depletion and the related deferred income tax effects, to the estimated future net cash flows from proved crude oil and natural gas reserves discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties (“the ceiling”). This discount rate is not adjusted for current market trends, changes in the cost of capital and the potential impacts, if any, on the discount rate due to climate change factors. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain. The estimated future net cash flows are calculated using the simple average of the preceding twelve months’ first-day-of-the-month commodity prices. If such capitalized costs exceed the ceiling, a write-down equal to that excess is recorded as a non-cash charge to net income. A write-down is not reversed in future periods even if higher crude oil and natural gas prices subsequently increase the ceiling. Under full cost accounting rules, divestitures of crude oil and natural gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized. e) Other Capital Assets Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, computer equipment and Company owned line-fill in third party pipelines. Line fill is recorded at lower of cost and net realizable value. Depreciation is calculated on a straight-line basis over the estimated useful life of the respective asset. The cost of repairs and maintenance is expensed as incurred. f) Cash and Cash Equivalents Cash and cash equivalents includes cash and highly liquid investments with maturities of less than 90 days. g) Goodwill Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. The portion of goodwill that related to U.S. operations fluctuated due to changes in foreign exchange rates. Goodwill is stated at cost less impairment and is not amortized. Goodwill is not deductible for income tax purposes. Goodwill is assessed for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. Enerplus first performs a qualitative assessment to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value, quantitative impairment tests are performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to the reporting unit’s fair value, with an offsetting charge to earnings in the Consolidated Statements of Income/(Loss). The loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The estimated fair value of the reporting unit involves numerous estimates including the estimated cash flows from proved reserves (and in certain periods probable reserves) associated with the reporting unit and the appropriate discount rate to apply to the estimated cash flows. The discount rate is based on the estimated cost of capital. h) Asset Retirement Obligations Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning and site remediation activities. Enerplus recognizes a liability for the estimated present value of the future asset retirement obligation liability at each balance sheet date. Upon recognition, the liability is recorded at its estimated fair value. The associated asset retirement cost is capitalized and amortized over the same period as the underlying asset. Changes in the estimated liability and related asset retirement cost can arise as a result of revisions in the estimated amount or timing of cash flows. Depletion of asset retirement costs and increases in asset retirement obligations resulting from the passage of time are recorded to depreciation, depletion and accretion and charged against net income in the Consolidated Statements of Income/(Loss). i) Leases Enerplus determines if an arrangement is a lease at inception. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating and finance leases are included in right-of-use (“ROU”) assets and the associated lease liability in the Consolidated Balance Sheet. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Lease liabilities are recognized at lease commencement date based on the present value of remaining lease payments over the lease term. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for lease incentives received. Enerplus uses the implicit rate when readily available, or uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is reasonably certain that it will exercise those options. Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease agreements contain both lease and non-lease components which are accounted for separately. For certain equipment leases, a portfolio approach is applied to effectively account for the ROU assets and liabilities. Prior to January 1, 2019, the Company applied lease accounting in accordance with ASC 840. Results reported for 2020 and 2019 reflect the application of the new guidance while the 2018 comparative results were prepared and reported under previous lease guidance. j) Income Tax Enerplus uses the liability method of accounting for income taxes. Deferred income tax assets and liabilities are recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax assets are reviewed each period and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. Enerplus considers both positive and negative evidence including historic and expected future taxable income, reversing existing temporary differences and tax basis carry forward periods in making this assessment. The expected future taxable income considered in the analysis of the valuation allowance is based on cash flows from the proven and probable reserves. The estimated cash flows from proven and probable reserves is subject to numerous estimates and judgments and involves the use of independent reserve evaluators. A valuation allowance is removed in any period where available evidence indicates all or a portion of the valuation allowance is no longer required. The financial statement effect of an uncertain tax position is recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. Penalties and interest expense related to income tax are recognized in income tax expense. k) Financial Instruments i. Fair Value Measurements Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. For financial instruments carried at fair value, and when disclosing the fair value of financial instruments on certain non-financial items, inputs used in determining the fair value are characterized according to the following fair value hierarchy: ● ● ● Subsequent measurement is based on classification of the financial instrument into one of the following five categories: held-for-trading, held-to-maturity, available-for-sale, loans and receivables or other financial liabilities. ii. Non-derivative financial instruments The carrying amount of cash, accounts receivable, income tax receivable, accounts payable, dividends payable and bank credit facilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of the senior notes are considered a level 2 fair value measurement. The fair value of debt has been disclosed in Note 15. The Company uses the current expected credit loss model for its accounts receivable, which requires the use of a lifetime expected loss provision. In making an assessment as to whether financial assets are credit-impaired, the Company considers: (i) historically realized bad debts; (ii) a counterparty’s present financial condition and whether a counterparty has breached certain contracts; (iii) the probability that a counterparty will enter bankruptcy or other financial reorganization; (iv) changes in economic conditions that correlate to increased levels of default; and (v) the term to maturity of the specified receivable. The carrying amounts of receivables are reduced by the amount of the expected credit loss through an allowance account and losses are recognized within general and administrative expense in the Consolidated Statement of Income/(Loss). If the Company subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus has designated certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. These non-derivative financial instruments will be accounted for under hedge accounting. To be accounted for as a hedge, the U.S. dollar denominated debt must be designated as an effective hedge, both at inception and on an ongoing basis. The required hedge documentation defines the relationship between the U.S. dollar denominated debt and the net investment in the U.S. subsidiary, as well as the Company’s risk management objective and strategy for undertaking the hedging transaction. The Company formally assesses, both at inception and on an ongoing basis, whether the changes in fair value of the U.S. dollar denominated debt are highly effective in offsetting changes in fair value of the net investment in the U.S. subsidiary. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in Other Comprehensive Income/(Loss), net of tax, and are limited to the translation gain or loss on the net investment. Prior to January 1, 2020, the Company did not apply hedge accounting to the net investment in foreign operations and unrealized gains and losses were recognized in net income/loss at the end of the respective reporting period. A reduction in the fair value of the net investment in the U.S. subsidiary or increase in the U.S. dollar denominated debt may result in a portion of the hedge becoming ineffective. If the hedging relationship ceases to be effective or is terminated, hedge accounting is not applied and subsequent gains or losses are recorded through net income/(loss). iii. Derivative financial instruments Enerplus enters into financial derivative contracts in order to manage its exposure to market risks from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. Enerplus has not designated its financial derivative contracts as effective accounting hedges and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a result, all remaining financial derivative contracts are classified as held-for-trading and are recorded at fair value based on a Level 2 designation, with changes in fair value recorded in net income. The fair values of these derivative instruments are generally based on an estimate of the amounts that would be paid or received to settle these instruments at the balance sheet date. Enerplus’ accounting policy is to not offset the fair values of its financial derivative assets and liabilities. Realized gains and losses from commodity price risk management activities are recognized in income when the contract is settled. Unrealized gains and losses on commodity price risk management activities are recognized in income based on the changes in fair value of the contracts at the end of the respective reporting period. Enerplus’ crude oil, natural gas and natural gas liquids physical delivery purchase and sales contracts qualify as normal purchases and sales as they are entered into and held for the purpose of receipt or delivery of products in accordance with the Company’s expected purchase, sale or usage requirements. As such, these contracts are not considered derivative financial instruments. Settlements on these physical contracts are recognized in net income over the term of the contracts as they occur. l) Foreign Currency i. Foreign currency transactions Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars) using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency of the entity using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Foreign currency differences arising on translation are recognized in net income in the period in which they arise. ii. Foreign operations Assets and liabilities of Enerplus’ U.S. operations, which has a U.S. dollar functional currency, are translated into Canadian dollars at period end exchange rates while revenues and expenses are translated using average rates for the period. Gains and losses from the translation are deferred and included in the cumulative translation adjustment which is recorded in accumulated other comprehensive income. m) Share-Based Compensation Enerplus’ share-based compensation plans include equity-settled Restricted Share Unit (“RSU”) and Performance Share Unit (“PSU”) awards made pursuant to its Share Award Incentive Plan (“SAIP”). The Company is authorized to issue up to 4.5% of outstanding common shares from treasury under the SAIP. Enerplus also has a cash-settled Deferred Share Unit (“DSU”) Plan for Directors (“Director DSU Plan”) and a cash-settled RSU Plan for Directors (“Director RSU Plan”). i. Long-term Incentive (“LTI”) Plans For RSU awards granted under the SAIP, employees receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and vests one-third each year for three years . The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period. For PSU awards granted under the SAIP, executives and management receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and they vest at the end of three years . The value upon vesting is based on the value of the underlying shares plus notional accrued dividends along with a multiplier that ranges from 0 to 2 depending on Enerplus’ performance compared to a peer group of both Canadian and U.S. crude oil and natural gas producers over the vesting period. Under Enerplus’ Director DSU Plan and Director RSU Plan, directors receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded is based on the annual equity retainer value. Directors may elect to receive all or a portion of their notional shares under either plan. Under the Director DSU Plan, units vest and are paid at a specified date following the director leaving the Board. Under the Director RSU Plan, units vest one-third each year for three years . The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period. All Director DSU and RSU grants are settled in cash. Enerplus recognizes non-cash share-based compensation expense over the vesting period of the equity-settled long-term incentive plans, net of realized forfeitures, based on the estimated grant date share price fair value of the respective awards. The grant date fair value is based on the Company’s 20 day volume weighted average price on December 31 prior to the grant date. The fair value for the PSUs is adjusted for the outcome of the performance condition. Share-based compensation charges are recorded on the Consolidated Statements of Income/(Loss) with an offset to paid-in capital. Each period, management performs an estimate of the PSU plan multiplier. Any differences that arise between the actual multiplier on plan settlement and management’s estimate is recorded to share-based compensation. On settlement of these plans, amounts previously recorded to paid-in capital are reclassified to share capital. Enerplus recognizes a liability with respect to its cash-settled long-term incentive plans based on their estimated fair value. The liability is re-measured at each reporting date and at settlement date with any changes in the fair value recorded as share-based compensation, included in general and administrative expense. ii. Stock options Enerplus’ Stock Option Plan was suspended in 2014 and is now closed. Remaining outstanding stock options expired in March 2020. n) Net Income/(Loss) Per Share Basic net income/(loss) per common share is computed by dividing net income/(loss) by the weighted average number of common shares outstanding during the period. For the diluted net income per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income. The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all stock options and outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price. o) Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recognized when it is probable that a liability has been incurred and the amount can be reasonably estimated. Contingencies are adjusted as additional information becomes available or circumstances change. p) Accounting Changes and Recent Pronouncements Issued Except for the changes below, the Company has consistently applied the accounting policies to all periods presented in these Consolidated Financial Statements, effective January 1, 2020 : ● ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350) – The change was applied prospectively and was applied to the 2020 impairment of goodwill (Refer to Note 5). ● ASC 815 – Derivatives and Hedging – relating to the net investment in foreign operations for which the U.S. dollar is the functional currency. Effective January 1, 2020 , foreign exchange gains and losses on Enerplus’ U.S. denominated debt are recorded in other comprehensive income along with translation gains and losses on Enerplus’ net investment in the U.S. Hedge accounting was applied prospectively thus the change did not impact comparative figures. ● ASC 326 – Financial Instruments – Credit Losses – modified retrospective method. The adoption of the standard had no impact on the financial statements. |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 12 Months Ended |
Dec. 31, 2020 | |
ACCOUNTS RECEIVABLE | |
ACCOUNTS RECEIVABLE | 3) ACCOUNTS RECEIVABLE ($ thousands) December 31, 2020 December 31, 2019 Accrued revenue $ 93,147 $ 142,048 Accounts receivable – trade 16,641 37,736 Allowance for doubtful accounts (3,579) (3,665) Total accounts receivable, net of allowance for doubtful accounts $ 106,209 $ 176,119 |
PROPERTY, PLANT AND EQUIPMENT (
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | 12 Months Ended |
Dec. 31, 2020 | |
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | |
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | 4) PROPERTY, PLANT AND EQUIPMENT (“PP&E”) Accumulated Depletion, As at December 31, 2020 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 15,227,076 $ (14,651,517) $ 575,559 Other capital assets 127,527 (108,003) 19,524 Total PP&E $ 15,354,603 $ (14,759,520) $ 595,083 Accumulated Depletion, As at December 31, 2019 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 15,088,724 $ (13,541,362) $ 1,547,362 Other capital assets 125,265 (105,021) 20,244 Total PP&E $ 15,213,989 $ (13,646,383) $ 1,567,606 (1) All of the Company’s unproved properties are included in the full cost pool. Acquisitions: For the years ended December 31, 2020 and 2019, Enerplus acquired property and land totaling $10.1 million and $24.4 million, respectively. Divestments: For the years ended December 31, 2020 and 2019, Enerplus disposed of properties for proceeds of $6.1 million and $9.6 million, respectively. |
IMPAIRMENT
IMPAIRMENT | 12 Months Ended |
Dec. 31, 2020 | |
IMPAIRMENT | |
IMPAIRMENT | 5) IMPAIRMENT a) Impairment of PP&E ($ thousands) 2020 2019 2018 Crude oil and natural gas properties: Canada cost centre $ 134,349 $ — $ — U.S. cost centre 860,427 — — Total impairment expense $ 994,776 $ — $ — The PP&E impairments for the year ended December 31, 2020 were due to lower twelve-month average trailing crude oil and natural gas prices. There was no PP&E impairments recorded for the years ended December 31, 2019 and 2018. The primary factors that will affect future ceiling values include future first-day-of-the-month commodity prices, reserves revisions, capital expenditure levels and timing, acquisition and divestment activity, and production levels. The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling test as at December 31, WTI Crude Oil Edm Light Crude U.S. Henry Hub Gas Exchange Rate Period US$/bbl CDN$/bbl US$/Mcf US$/CDN 2020 $ 39.54 $ 45.56 $ 2.00 1.34 2019 55.85 66.73 2.58 1.33 2018 65.56 69.58 3.10 1.28 b) Impairment of Goodwill Enerplus recorded goodwill impairment of $202.8 million related to its U.S. reporting unit for the year ended December 31, 2020 (December 31, 2019 - $451.1 million for the Canadian reporting unit). The impairment was a result of lower commodity prices, which resulted in a reduction in the fair value of the U.S. reporting unit. The U.S reporting unit for the goodwill impairment test was based on its reserve values at forecasted prices and costs at June 30 , The fair value of the U.S. reporting unit was estimated using proved reserves as at the measurement date base on forward price curves as determined by external reserve engineers and discounted using an estimated after-tax discount rate of 15%. The estimated fair value of the reporting units is considered a level 3 fair value under the fair value hierarchy. |
ACCOUNTS PAYABLE
ACCOUNTS PAYABLE | 12 Months Ended |
Dec. 31, 2020 | |
ACCOUNTS PAYABLE | |
ACCOUNTS PAYABLE | 6) ACCOUNTS PAYABLE ($ thousands) December 31, 2020 December 31, 2019 Accrued payables $ 107,254 $ 105,928 Accounts payable – trade 144,568 185,612 Total accounts payable $ 251,822 $ 291,540 |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2020 | |
DEBT | |
DEBT | 7) DEBT ($ thousands) December 31, 2020 December 31, 2019 Current: Senior notes $ 103,836 $ 105,998 Long-term: Bank credit facility $ — $ — Senior notes 386,586 500,635 Total debt $ 490,422 $ 606,633 Bank Credit Facility Enerplus has a senior unsecured, covenant-based, US$600 million bank credit facility that matures on October 31, 2023. Drawn fees range between 125 and 315 basis points over bankers’ acceptance and LIBOR rates. Standby fees on the undrawn portion of the facility are based on 20% of the drawn pricing. The Company has the ability to request an extension of the facility or repay the entire balance at the end of the term. At December 31, 2020, Enerplus was undrawn on the facility (December 31, 2019 –undrawn). Senior Notes During 2020, Enerplus made its fourth US$22 million principal repayment on its 2009 senior notes and its first US$59.6 million principal repayment on its 2012 senior notes. During 2019, Enerplus made its third US$22 million principal repayment on its 2009 senior notes and a $30 million bullet repayment on its 2012 senior notes. During 2018, Enerplus made its second US$22 million principal repayment on its 2009 senior notes. The terms and rates of the Company’s outstanding senior notes are detailed below: Original Remaining CDN$ Carrying Coupon Principal Principal Value Issue Date Interest Payment Dates Principal Repayment Rate ($ thousands) ($ thousands) ($ thousands) September 3, 2014 March 3 and Sept 3 5 equal annual installments beginning September 3, 2022 3.79% US$200,000 US$105,000 $ 133,613 May 15, 2012 May 15 and Nov 15 Bullet payment on May 15, 2022 4.40% US$20,000 US$20,000 25,450 May 15, 2012 May 15 and Nov 15 4 equal annual installments beginning May 15, 2021 4.40% US$355,000 US$238,400 303,364 June 18, 2009 June 18 Final installment on June 18, 2021 7.97% US$225,000 US$22,000 27,995 Total carrying value $ 490,422 |
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended |
Dec. 31, 2020 | |
ASSET RETIREMENT OBLIGATION | |
ASSET RETIREMENT OBLIGATION | 8) ASSET RETIREMENT OBLIGATION ($ thousands) December 31, 2020 December 31, 2019 Balance, beginning of year $ 138,049 $ 126,112 Change in estimates 1,331 23,362 Property acquisition and development activity 2,246 2,068 Divestments (1,030) (2,760) Settlements (17,709) (16,715) Accretion expense 7,321 5,982 Balance, end of year $ 130,208 $ 138,049 Enerplus has estimated the present value of its asset retirement obligation to be $130.2 million at December 31, 2020 based on a total undiscounted, uninflated liability of $348.4 million (December 31, 2019 – $138.0 million and $344.7 million, respectively). The asset retirement obligation was calculated using a weighted average credit-adjusted risk-free rate of 5.35% and inflation rate of 0.9% (December 31, 2019 – 5.50% and 1.8%, respectively). The majority of Enerplus’ asset retirement obligation expenditures are expected to be incurred between 2024 and 2046. |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2020 | |
LEASES | |
LEASES | 9) LEASES The Company incurs lease payments related to office space, drilling rig commitments, vehicles and other equipment. Leases are entered into and exited in coordination with specific business requirements which include the assessment of the appropriate durations for the related leased assets. Short-term leases with a lease term of 12 months or less are not recorded on the Consolidated Balance Sheet. Such items are charged to operating expenses and general and administrative expenses in the Consolidated Statement of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with other U.S. GAAP. ($ thousands) December 31, 2020 December 31, 2019 Assets Operating right-of-use assets $ 32,853 $ 48,729 Liabilities Current operating lease liabilities $ 13,391 $ 17,541 Non-current operating lease liabilities 23,446 35,530 Total lease liabilities $ 36,837 $ 53,071 Weighted average remaining lease term (years) Operating leases 3.9 4.3 Weighted average discount rate Operating leases 4.2% 4.1% The components of lease expense for the year ended December 31, 2020 and 2019 are as follows: ($ thousands) 2020 2019 Operating lease cost $ 16,585 $ 19,546 Variable lease cost 1,753 (63) Short-term lease cost 9,512 15,332 Sublease income (1,476) (1,072) Total $ 26,374 $ 33,743 Maturities of lease liabilities, all of which are classified as operating leases at December 31, 2020, are as follows: Maturity of Lease Liabilities ($ thousands) Operating Leases 2021 $ 14,643 2022 8,285 2023 6,963 2024 6,202 2025 1,202 After 2025 2,696 Total lease payments $ 39,991 Less imputed interest (3,154) Total discounted lease payments $ 36,837 Current portion of lease liabilities $ 13,391 Non-current portion of lease liabilities $ 23,446 Supplemental information related to leases are as follows: ($ thousands) 2020 2019 Cash amounts paid to settle lease liabilities: Operating cash flow used for operating leases $ 16,142 $ 18,637 Right-of-use assets obtained/(terminated) in exchange for lease obligations: Operating leases $ (1,752) $ 20,818 |
CRUDE OIL AND NATURAL GAS SALES
CRUDE OIL AND NATURAL GAS SALES | 12 Months Ended |
Dec. 31, 2020 | |
CRUDE OIL AND NATURAL GAS SALES | |
CRUDE OIL AND NATURAL GAS SALES | 10) CRUDE OIL AND NATURAL GAS SALES ($ thousands) 2020 2019 2018 Crude oil and natural gas sales $ 923,546 $ 1,572,955 $ 1,610,899 Royalties (1) (186,341) (318,149) (318,163) Crude oil and natural gas sales, net of royalties $ 737,205 $ 1,254,806 $ 1,292,736 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). Crude oil and natural gas revenue by country and by product for the years ended December 31, 2020 and 2019 are as follows: 2020 Total revenue, net Natural Natural gas ($ thousands) of royalties (1) Crude oil (2) gas (2) liquids (2) Other (3) Canada $ 96,498 $ 78,798 $ 12,307 $ 3,452 $ 1,942 United States 640,707 508,294 119,030 13,233 149 Total $ 737,205 $ 587,092 $ 131,337 $ 16,685 $ 2,091 2019 Total revenue, net Natural Natural gas ($ thousands) of royalties (1) Crude oil (2) gas (2) liquids (2) Other (3) Canada $ 177,299 $ 145,814 $ 21,776 $ 7,158 $ 2,551 United States 1,077,507 847,182 215,963 14,355 7 Total $ 1,254,806 $ 992,996 $ 237,739 $ 21,513 $ 2,558 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). (2) U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties. (3) Includes third party processing income. Enerplus sells the majority of its production pursuant to variable-price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under the contracts, the Company is required to deliver a fixed or variable volume of crude oil, natural gas liquids or natural gas to the contract counterparty. Crude oil, natural gas and natural gas liquids are sold under contracts of varying terms, including multi-year contracts. Revenues are typically collected in the month following production. |
GENERAL AND ADMINISTRATIVE EXPE
GENERAL AND ADMINISTRATIVE EXPENSE | 12 Months Ended |
Dec. 31, 2020 | |
GENERAL AND ADMINISTRATIVE EXPENSE | |
GENERAL AND ADMINISTRATIVE EXPENSE | 11) GENERAL AND ADMINISTRATIVE EXPENSE ($ thousands) 2020 2019 2018 General and administrative expense (1) $ 44,584 $ 49,532 $ 49,943 Share-based compensation expense 12,999 23,321 25,840 General and administrative expense $ 57,583 $ 72,853 $ 75,783 (1) Includes non-cash lease expense/(inducement) of $(288) in 2020 and $(720) in 2019. |
FOREIGN EXCHANGE
FOREIGN EXCHANGE | 12 Months Ended |
Dec. 31, 2020 | |
FOREIGN EXCHANGE | |
FOREIGN EXCHANGE | 12) FOREIGN EXCHANGE ($ thousands) 2020 2019 2018 Realized: Foreign exchange (gain)/loss $ 554 $ (87) $ 523 Translation of U.S. dollar cash held in Canada (gain)/loss (1,147) 8,794 (19,630) Unrealized: Translation of U.S. dollar debt and working capital (gain)/loss 1,931 (34,085) 58,628 Foreign exchange (gain)/loss $ 1,338 $ (25,378) $ 39,521 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2020 | |
INCOME TAXES | |
INCOME TAXES | 13) INCOME TAXES Enerplus’ provision for income tax is as follows: ($ thousands) 2020 2019 2018 Current tax Canada $ — $ (13,910) $ (400) United States (14,525) (19,504) (26,693) Current tax expense/(recovery) (14,525) (33,414) (27,093) Deferred tax Canada $ (24,584) $ 11,023 $ 3,915 United States (221,646) 70,252 126,389 Deferred tax expense/(recovery) (246,230) 81,275 130,304 Income tax expense/(recovery) $ (260,755) $ 47,861 $ 103,211 The following provides a reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes: ($ thousands) 2020 2019 2018 Income/(loss) before taxes Canada $ (13,507) $ (437,571) $ 104,204 United States (1,170,615) 225,712 377,286 Total income/(loss) before taxes (1,184,122) (211,859) 481,490 Canadian statutory rate 24.00% 26.50% 27.00% Expected income tax expense/(recovery) $ (284,189) $ (56,143) $ 130,002 Impact on taxes resulting from: Foreign and statutory rate differences $ (37,451) $ 27,446 $ (23,859) Share-based compensation 2,073 (5,398) (18,102) Capital gains and losses 17,261 3,994 7,254 Change in valuation allowance (31,195) (22,038) 6,292 Amounts in respect of prior periods 8,905 (19,451) — Non-deductible goodwill impairment and other expenses 63,841 119,451 1,624 Income tax expense/(recovery) $ (260,755) $ 47,861 $ 103,211 During the year, the Alberta corporate income tax rate change resulted in a decrease to the Canadian statutory rate by 2.5% for 2020. The deferred income tax asset consists of the following: As at December 31 2020 2019 Deferred income tax assets Property, plant and equipment $ 177,799 $ 59,896 Tax loss carry-forwards and other credits 385,934 383,600 Capital loss carryforwards and other capital items 141,880 154,532 Asset retirement obligation 31,793 33,569 Derivative financial instruments 3,723 — Other assets 8,486 12,219 Deferred income tax assets before valuation allowance 749,615 643,816 Valuation allowance (142,614) (169,129) Deferred income tax assets, net 607,001 474,687 Deferred income tax liabilities Property, plant and equipment $ — $ (100,328) Derivative financial instruments — (1,857) Total deferred income tax liabilities — (102,185) Total deferred income tax asset $ 607,001 $ 372,502 In 2020, $14.5 million was reclassified from deferred income tax asset to income tax receivable for the recognition of the final portion of the AMT refund. As of December 31, 2020, all outstanding AMT refunds have been received. Loss carryforwards available for tax reporting purposes: As at December 31 2020 Expiration Date Canada Capital losses $ 1,053,000 Indefinite Non-capital losses 284,000 2031-2039 United States Net operating losses – prior to 2018 $ 875,000 2030-2040 Net operating losses – 2018 and thereafter 316,000 Indefinite Changes in the balance of Enerplus’ unrecognized tax benefits are as follows: ($ thousands) 2020 2019 2018 Balance, beginning of year $ — $ 13,300 $ 13,300 Increase - tax positions in prior periods 21,030 — — Settlements — (13,300) — Balance, end of year $ 21,030 $ — $ 13,300 If recognized, all of Enerplus’ unrecognized tax benefits as at December 31, 2020 would affect Enerplus’ effective income tax rate. It is not anticipated that the amount of unrecognized tax benefits will significantly change during the next 12 months. A summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities are as follows: Jurisdiction Taxation Years Canada – Federal 2015-2020 United States – Federal 2017-2020 Enerplus and its subsidiaries file income tax returns primarily in Canada and the United States. Matters in dispute with the taxation authorities are ongoing and in various stages of completion. |
SHAREHOLDERS' EQUITY
SHAREHOLDERS' EQUITY | 12 Months Ended |
Dec. 31, 2020 | |
SHAREHOLDERS' EQUITY | |
SHAREHOLDERS' EQUITY | 14) SHAREHOLDERS’ EQUITY a) Share Capital 2020 2019 2018 Authorized: unlimited number of common shares Shares Amount Shares Amount Shares Amount Balance, beginning of year 221,744 $ 3,088,094 239,411 $ 3,337,608 242,129 $ 3,386,946 Issued for cash: Purchase of common shares under Normal Course Issuer Bid (340) (4,731) (18,231) (253,920) (5,925) (82,596) Stock Option Plan — — — — 668 9,138 Non-cash: Share-based compensation – settled (1) 1,160 13,824 564 4,406 2,539 23,389 Stock Option Plan – exercised — — — — — 731 Cancellation of predecessor shares (16) (218) — — — — Balance, end of year 222,548 $ 3,096,969 221,744 $ 3,088,094 239,411 $ 3,337,608 (1) The amount of shares issued on LTI settlement is net of employee withholding taxes in 2020 and 2019. The Company is authorized to issue an unlimited number of common shares without par value. For the year ended December 31, 2020, Enerplus declared dividends of $0.12 per weighted average common share totaling $26.7 million (December 31, 2019 - $0.12 per share and $27.7 million, December 31, 2018 – $0.12 per share and $29.3 million). Enerplus’ Normal Course Issuer Bid (“NCIB”) expired on March 25, 2020. All repurchases were made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess allocated to accumulated deficit. For the year ended December 31, 2020, the Company repurchased 340,434 common shares under the NCIB at an average price of $7.44 per share, for total consideration of $2.5 million. Of the amount paid, $4.7 million was charged to share capital and $2.2 million was credited to accumulated deficit. For the year ended December 31, 2019, the Company repurchased 18,231,401 common shares under the NCIB at an average price of $9.80 per share, for total consideration of $178.8 million. Of the amount paid, $253.9 million was charged to share capital and $75.1 million was credited to accumulated deficit. b) Share-based Compensation The following table summarizes Enerplus' share-based compensation expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss): ($ thousands) 2020 2019 2018 Cash: Long-term incentive plans expense $ (1,411) $ 689 $ 133 Non-Cash: Long-term incentive plans expense 13,014 22,324 25,917 Equity swap (gain)/loss 1,396 308 (210) Share-based compensation expense $ 12,999 $ 23,321 $ 25,840 i) LTI Plans The following table summarizes the PSU, RSU and DSU activity for the year ended December 31, 2020: For the year ended December 31, 2020 Cash-settled LTI Plans Equity-settled LTI Plans Total (thousands of units) DSU PSU (1) RSU Balance, beginning of year 422 2,139 1,531 4,092 Granted 133 1,203 1,142 2,478 Vested — (652) (741) (1,393) Forfeited — (138) (107) (245) Balance, end of year 555 2,552 1,825 4,932 (1) Based on underlying awards before any effect of the performance multiplier. Cash-settled LTI Plans For the year ended December 31, 2020, the Company recorded a cash share-based compensation recovery of $1.4 million (2019 – expense of $0.7 million; 2018 – expense of $0.1 million). As of December 31, 2020, a liability of $2.2 million (December 31, 2019 – $3.9 million) with respect to the Director DSU Plan has been recorded to Accounts Payable on the Consolidated Balance Sheets. Equity-settled LTI Plans The following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms. At December 31, 2020 ($ thousands, except for years) PSU (1) RSU Total Cumulative recognized share-based compensation expense $ 18,564 $ 13,474 $ 32,038 Unrecognized share-based compensation expense 7,444 5,497 12,941 Fair value $ 26,008 $ 18,971 $ 44,979 Weighted-average remaining contractual term (years) 1.8 1.4 (1) Includes estimated performance multipliers. The Company directly withholds shares on PSU and RSU settlements for tax-withholding purposes. For the year ended December 31, 2020 cash withholding taxes of $7.2 million were paid (2019 - $5.0 million, 2018 – nil) . ii) Stock Option Plan At December 31, 2020, all stock options are fully vested and all non-cash share-based compensation expense has been fully recognized. All remaining outstanding stock options expired in March 2020. The following table summarizes the stock option plan activity for the year ended December 31, 2020: Number of Options Weighted Average Year ended December 31, 2020 (thousands) Exercise Price Options outstanding, beginning of year 2,107 $ 14.24 Exercised — — Forfeited (8) 14.85 Expired (2,099) 14.24 Options outstanding and exercisable, end of year — $ — c) Basic and Diluted Net Income/(Loss) Per Share Net income/(loss) per share has been determined as follows: (thousands, except per share amounts) 2020 2019 2018 Net income/(loss) $ (923,367) $ (259,720) $ 378,279 Weighted average shares outstanding – Basic 222,503 231,334 244,076 Dilutive impact of share-based compensation (1) — — 3,185 Weighted average shares outstanding – Diluted 222,503 231,334 247,261 Net income/(loss) per share Basic $ (4.15) $ (1.12) $ 1.55 Diluted $ (4.15) $ (1.12) $ 1.53 (1) For the years ended December 31, 2020 and 2019, the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share. |
FINANCIAL INSTRUMENTS AND RISK
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | 12 Months Ended |
Dec. 31, 2020 | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | 15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT a) Fair Value Measurements At December 31, 2020, the senior notes had a carrying value of $490.4 million and a fair value of $494.1 million (December 31, 2019 – $606.6 million and $613.8 million, respectively). The fair value of the senior notes is estimated based on the amount that Enerplus would have to pay a third party to assume the debt, including the credit spread for the difference between the issue rate and the period end market rate. The period end market rate is estimated by comparing the debt to new issuances (secured or unsecured) and secondary trades of similar size and credit statistics for both public and private debt. There were no transfers between fair value hierarchy levels during the year. b) Derivative Financial Instruments The derivative financial assets and liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value. The following tables summarize the change in fair value for the respective years: Income Gain/(Loss) 2020 2019 2018 Statement Presentation Equity Swaps $ (1,396) $ (308) $ 210 G&A expense Commodity Derivative Instruments: Oil (25,701) (70,481) 114,822 Commodity derivative Gas 3,550 (10,944) 9,234 instruments Total Unrealized Gain/(Loss) $ (23,547) $ (81,733) $ 124,266 The following table summarizes the effect of Enerplus’ commodity derivative instruments on the Consolidated Statements of Income/(Loss): ($ thousands) 2020 2019 2018 Change in fair value gain/(loss) $ (22,151) $ (81,425) $ 124,056 Net realized cash gain/(loss) 130,970 15,354 (35,824) Commodity derivative instruments gain/(loss) $ 108,819 $ (66,071) $ 88,232 The following table summarizes the fair values at the respective year ends: December 31, 2020 December 31, 2019 Assets Liabilities Assets Liabilities ($ thousands) Current Current Current Current Equity Swaps $ — $ 3,613 $ — $ 2,217 Commodity Derivative Instruments: Oil — 15,648 10,570 517 Gas 3,550 — — — Total $ 3,550 $ 19,261 $ 10,570 $ 2,734 The fair value of commodity derivative instruments and the equity swaps is estimated based on commodity and option pricing models that incorporates various factors including forecasted commodity prices, volatility and the credit risk of the entities party to the contract. Changes in commodity prices over the term of the contracts can result in material differences between the estimated fair value at a point in time and the actual settlement amounts of the contracts. c) Risk Management In the normal course of operations, Enerplus is exposed to various market risks, including commodity prices, foreign exchange, interest rates, equity prices, credit risk and liquidity risk. i) Market Risk Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk. Commodity Price Risk: Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes. The following tables summarize Enerplus’ price risk management positions at February 18, 2021: Crude Oil Instruments: Instrument Type (1)(2) bbls/day US$/bbl Jan 1, 2021 – Mar 31, 2021 WTI Swap 5,000 45.55 WTI Purchased Put 15,000 40.53 WTI Sold Put 15,000 32.00 WTI Sold Call 15,000 50.29 Apr 1, 2021 – Jun 30, 2021 WTI Purchased Put 20,000 40.90 WTI Sold Put 20,000 32.00 WTI Sold Call 20,000 50.72 UHC Differential Swap 1,500 (1.80) Jul 1, 2021 – Dec 31, 2021 WTI Purchased Put 23,000 46.39 WTI Sold Put 23,000 36.39 WTI Sold Call 23,000 56.70 UHC Differential Swap 1,500 (1.80) Jan 1, 2022 – Dec 31, 2022 WTI Purchased Put 17,000 50.00 WTI Sold Put 17,000 40.00 WTI Sold Call 17,000 57.91 (1) Transactions with a common term have been aggregated and presented as the weighted average price/bbl before premiums. (2) The total average deferred premium spent on our outstanding hedges is US $0.80 /bbl from January 1, 2021 – December 31, 2021 and US $1.50 /bbl from January 1, 2022 – December 31, 2022. Natural Gas Instruments: Instrument Type MMcf/day US$/Mcf Mar 1, 2021 - Mar 31, 2021 NYMEX Swap 60,000 3.16 Apr 1, 2021 – Oct 31, 2021 NYMEX Swap 60,000 2.90 NYMEX Purchased Put 40,000 2.75 NYMEX Sold Put 40,000 2.15 NYMEX Sold Call 40,000 3.25 Foreign Exchange Risk: Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, U.S. dollar denominated senior notes, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a significant portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At December 31, 2020, Enerplus did not have any foreign exchange derivatives outstanding. Interest Rate Risk: At December 31, 2020, all of Enerplus’ debt was based on fixed interest rates, and Enerplus did not have any interest rate derivatives outstanding. Equity Price Risk: Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps maturing in 2021 that effectively fix the future settlement cost on a portion of its cash settled LTI plans. ii) Credit Risk Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables. Enerplus mitigates credit risk through credit management techniques, including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis. Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At December 31, 2020, approximately 82% of Enerplus’ marketing receivables were with companies considered investment grade. Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts off future payments or seeking other remedies including legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus’ allowance for doubtful accounts balance at December 31, 2020 was $3.6 million (December 31, 2019 – $3.7 million). iii) Liquidity Risk & Capital Management Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt (net of cash and cash equivalents) and shareholders’ capital. Enerplus’ objective is to provide adequate short and longer term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas assets and planned investment opportunities. Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, share repurchases, access to capital markets, as well as acquisition and divestment activity. At December 31, 2020, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2020 | |
COMMITMENTS AND CONTINGENCIES | |
COMMITMENTS AND CONTINGENCIES | 16) COMMITMENTS AND CONTINGENCIES a) Commitments Enerplus has the following minimum annual commitments, excluding operating leases which are recorded in the lease liability (see Note 9): Minimum Annual Commitment Each Year ($ thousands) Total 2021 2022 2023 2024 2025 Thereafter Senior notes (1) $ 490,422 $ 103,836 $ 128,014 $ 102,564 $ 102,564 $ 26,722 $ 26,722 Transportation commitments 289,993 44,539 30,393 29,358 29,088 29,101 127,514 Processing commitments 9,489 1,519 1,519 1,519 1,519 1,519 1,894 Total commitments (2)(3) $ 789,904 $ 149,894 $ 159,926 $ 133,441 $ 133,172 $ 57,343 $ 156,131 (1) Interest payments have not been included. (2) Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment. (3) US$ commitments have been converted to CDN$ using the December 31, 2020 foreign exchange rate of 1.2725 . b) Contingencies Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is probable and the amount can be reasonably estimated, an accrual is recorded. |
GEOGRAPHICAL INFORMATION
GEOGRAPHICAL INFORMATION | 12 Months Ended |
Dec. 31, 2020 | |
GEOGRAPHICAL INFORMATION | |
GEOGRAPHICAL INFORMATION | 17) GEOGRAPHICAL INFORMATION As at and for the year ended December 31, 2020 ($ thousands) Canada U.S. Total Crude oil and natural gas sales, net of royalties $ 96,498 $ 640,707 $ 737,205 Depletion, depreciation and accretion 46,784 246,372 293,156 Property, plant and equipment 112,195 482,888 595,083 Deferred income tax asset 210,615 396,386 607,001 As at and for the year ended December 31, 2019 ($ thousands) Canada U.S. Total Crude oil and natural gas sales, net of royalties $ 177,299 $ 1,077,507 $ 1,254,806 Depletion, depreciation and accretion 59,936 296,894 356,830 Property, plant and equipment 259,514 1,308,092 1,567,606 Deferred income tax asset 185,880 186,622 372,502 Goodwill — 194,015 194,015 Long term income tax receivable — 13,852 13,852 As at and for the year ended December 31, 2018 ($ thousands) Canada U.S. Total Crude oil and natural gas sales, net of royalties $ 198,263 $ 1,094,473 $ 1,292,736 Depletion, depreciation and accretion 58,333 245,941 304,274 Property, plant and equipment 262,159 1,044,912 1,307,071 Deferred income tax asset 196,903 268,221 465,124 Goodwill 451,121 203,678 654,799 Long term income tax receivable — 27,195 27,195 |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2020 | |
SUPPLEMENTAL CASH FLOW INFORMATION | |
SUPPLEMENTAL CASH FLOW INFORMATION | 18) SUPPLEMENTAL CASH FLOW INFORMATION a) Changes in Non-Cash Operating Working Capital ($ thousands) December 31, 2020 December 31, 2019 December 31, 2018 Accounts receivable $ 112,041 $ 8,493 $ (45,385) Other assets (5,611) 4,475 (3,026) Accounts payable (515) (11,005) 44,952 $ 105,915 $ 1,963 $ (3,459) b) Changes in Other Non-Cash Working Capital ($ thousands) December 31, 2020 December 31, 2019 December 31, 2018 Non-cash financing activities (1) $ 8 $ (178) $ (26) Non-cash investing activities (2) $ (37,509) $ 17,682 $ (3,753) (1) Relates to changes in dividends payable and included in dividends on the Consolidated Statements of Cash Flows. (2) Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Consolidated Statements of Cash Flows. c) Other ($ thousands) December 31, 2020 December 31, 2019 December 31, 2018 Income taxes paid/(received) $ (58,361) $ (71,890) $ (481) Interest paid $ 28,758 $ 33,991 $ 36,161 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2020 | |
SUBSEQUENT EVENTS | |
SUBSEQUENT EVENTS | 19) SUBSEQUENT EVENTS On January 25, 2021 , the Company entered into a purchase agreement to acquire the equity interest of Bruin E&P HoldCo, LLC for total cash consideration of US $465 million, subject to customary purchase price adjustments (the “Bruin Acquisition”). On the same date , we entered into a binding commitment letter for a new three-year senior unsecured US $400 million term loan to be fully drawn down on the closing date of the Bruin Acquisition to pay for a portion of the purchase price. We intend to fund the remaining portion of the purchase price with net proceeds from a $132.3 million bought deal equity financing, issuing 33,062,500 common shares at a price of $4.00 per common share, which we completed on February 3, 2021. The Bruin Acquisition is expected to close in early March 2021. |
SIGNIFICANT ACCOUNTING POLICI_2
SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2020 | |
SIGNIFICANT ACCOUNTING POLICIES | |
Basis of Preparation | Enerplus’ Consolidated Financial Statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Certain prior period amounts have been restated to conform with current period presentation. i. Reporting Currency These Consolidated Financial Statements are presented in Canadian dollars, which is Enerplus’ reporting currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand unless otherwise indicated. |
Use of Estimates | ii. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: crude oil and natural gas reserves and related present value of future cash flows, depreciation, depletion and accretion (“DD&A”), impairment of property, plant and equipment, asset retirement obligations, income taxes, ability to realize deferred income tax assets, impairment assessments of goodwill and the fair value of derivative instruments. The estimation of crude oil and natural gas reserves and the related present value of future cash flows involves the use of independent reservoir engineering specialists and numerous estimates and assumptions including forecasted production volumes, forecasted operating, royalty and capital cost assumptions and assumptions around commodity pricing. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions. In the opinion of management, these Consolidated Financial Statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies. In early March 2020, the World Health Organization declared the coronavirus (“COVID-19”) outbreak a pandemic. Responses to the spread of COVID-19 have resulted in a challenging economic climate, with more volatile commodity prices and foreign exchange rates, and a decline in long-term interest rates. Although global economies have begun to recover, markets remain volatile and the timing of a full economic recovery remains uncertain. It is difficult to reliably estimate the length or severity of these developments and their financial impact. The impacts of the economic downturn to Enerplus have been considered in management’s estimates described above at December 31, 2020; however, estimates made during periods of extreme volatility are subject to a higher level of uncertainty and as a result, there may be further prospective material impacts in future periods. |
Basis of Consolidation | iii. Basis of Consolidation These Consolidated Financial Statements include the accounts of Enerplus and its subsidiaries. Intercompany balances and transactions are eliminated on consolidation. Interests in jointly controlled crude oil and natural gas assets are accounted for following the concept of undivided interest, whereby Enerplus’ proportionate share of revenues, expenses, assets and liabilities are included in the accounts. |
Business Combinations | iv. Business Combinations The acquisition method of accounting is used to account for acquisitions that meet the definition of a business under U.S. GAAP. The cost of an acquisition is measured as the fair value of the assets transferred, equity instruments issued and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. |
Revenue | b) Revenue Revenue from the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers, net of sales taxes. Enerplus recognizes revenue when it satisfies a performance obligation by transferring control of the product to a customer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the contractual delivery points. Enerplus evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, management considers if Enerplus retains control of the product being delivered to the end customer. As part of this assessment, management considers whether the Company retains the economic benefits associated with the good being delivered to the end customer. Management also considers whether the Company has the primary responsibility for the delivery of the product, the ability to establish prices or the inventory risk. If Enerplus acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction. |
Transportation | c) Transportation Enerplus generally sells crude oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which the Company sells crude oil or natural gas at the wellhead and collects a price, net of the transportation incurred by the purchaser. In this case, sales are recorded at the price received from the purchaser, net of transportation costs. Under the other arrangement, Enerplus sells crude oil or natural gas at a specific delivery point, pays transportation to a third party and receives proceeds from the purchaser with no transportation deduction. In this case, transportation costs are recorded as transportation expense on the Consolidated Statements of Income/(Loss). Due to these two distinct selling arrangements, Enerplus’ computed realized prices, before the impact of derivative instruments, include revenues which are reported under two separate bases. |
Crude Oil and Natural Gas Properties | d) Crude oil and Natural Gas Properties Enerplus uses the full cost method of accounting for its crude oil and natural gas properties. Under this method, all acquisition, exploration and development costs incurred in finding crude oil and natural gas reserves are capitalized, including general and administrative costs attributable to these activities. These costs are recorded on a country-by-country cost centre basis as crude oil and natural gas properties subject to depletion (“full cost pool”). Costs associated with production and general corporate activities are expensed as incurred. The net carrying value of both proved and unproved crude oil and natural gas properties is depleted using the unit of production method using proved reserves, as determined using a constant price assumption of the simple average of the preceding twelve months’ first-day-of-the-month commodity prices (“SEC prices”). The depletion calculation takes into account estimated future development costs necessary to bring those reserves into production. Under full cost accounting, a ceiling test is performed on a cost centre basis each quarter. Enerplus limits capitalized costs of proved and unproved crude oil and natural gas properties, net of accumulated depletion and the related deferred income tax effects, to the estimated future net cash flows from proved crude oil and natural gas reserves discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties (“the ceiling”). This discount rate is not adjusted for current market trends, changes in the cost of capital and the potential impacts, if any, on the discount rate due to climate change factors. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain. The estimated future net cash flows are calculated using the simple average of the preceding twelve months’ first-day-of-the-month commodity prices. If such capitalized costs exceed the ceiling, a write-down equal to that excess is recorded as a non-cash charge to net income. A write-down is not reversed in future periods even if higher crude oil and natural gas prices subsequently increase the ceiling. Under full cost accounting rules, divestitures of crude oil and natural gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized. |
Other Capital Assets | e) Other Capital Assets Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, computer equipment and Company owned line-fill in third party pipelines. Line fill is recorded at lower of cost and net realizable value. Depreciation is calculated on a straight-line basis over the estimated useful life of the respective asset. The cost of repairs and maintenance is expensed as incurred. |
Cash and Cash Equivalents | f) Cash and Cash Equivalents Cash and cash equivalents includes cash and highly liquid investments with maturities of less than 90 days. |
Goodwill | g) Goodwill Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. The portion of goodwill that related to U.S. operations fluctuated due to changes in foreign exchange rates. Goodwill is stated at cost less impairment and is not amortized. Goodwill is not deductible for income tax purposes. Goodwill is assessed for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. Enerplus first performs a qualitative assessment to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value, quantitative impairment tests are performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to the reporting unit’s fair value, with an offsetting charge to earnings in the Consolidated Statements of Income/(Loss). The loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The estimated fair value of the reporting unit involves numerous estimates including the estimated cash flows from proved reserves (and in certain periods probable reserves) associated with the reporting unit and the appropriate discount rate to apply to the estimated cash flows. The discount rate is based on the estimated cost of capital. |
Asset Retirement Obligations | h) Asset Retirement Obligations Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning and site remediation activities. Enerplus recognizes a liability for the estimated present value of the future asset retirement obligation liability at each balance sheet date. Upon recognition, the liability is recorded at its estimated fair value. The associated asset retirement cost is capitalized and amortized over the same period as the underlying asset. Changes in the estimated liability and related asset retirement cost can arise as a result of revisions in the estimated amount or timing of cash flows. Depletion of asset retirement costs and increases in asset retirement obligations resulting from the passage of time are recorded to depreciation, depletion and accretion and charged against net income in the Consolidated Statements of Income/(Loss). |
Leases | i) Leases Enerplus determines if an arrangement is a lease at inception. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating and finance leases are included in right-of-use (“ROU”) assets and the associated lease liability in the Consolidated Balance Sheet. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Lease liabilities are recognized at lease commencement date based on the present value of remaining lease payments over the lease term. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for lease incentives received. Enerplus uses the implicit rate when readily available, or uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is reasonably certain that it will exercise those options. Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease agreements contain both lease and non-lease components which are accounted for separately. For certain equipment leases, a portfolio approach is applied to effectively account for the ROU assets and liabilities. Prior to January 1, 2019, the Company applied lease accounting in accordance with ASC 840. Results reported for 2020 and 2019 reflect the application of the new guidance while the 2018 comparative results were prepared and reported under previous lease guidance. |
Income Tax | j) Income Tax Enerplus uses the liability method of accounting for income taxes. Deferred income tax assets and liabilities are recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax assets are reviewed each period and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. Enerplus considers both positive and negative evidence including historic and expected future taxable income, reversing existing temporary differences and tax basis carry forward periods in making this assessment. The expected future taxable income considered in the analysis of the valuation allowance is based on cash flows from the proven and probable reserves. The estimated cash flows from proven and probable reserves is subject to numerous estimates and judgments and involves the use of independent reserve evaluators. A valuation allowance is removed in any period where available evidence indicates all or a portion of the valuation allowance is no longer required. The financial statement effect of an uncertain tax position is recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. Penalties and interest expense related to income tax are recognized in income tax expense. |
Financial Instruments | k) Financial Instruments i. Fair Value Measurements Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. For financial instruments carried at fair value, and when disclosing the fair value of financial instruments on certain non-financial items, inputs used in determining the fair value are characterized according to the following fair value hierarchy: ● ● ● Subsequent measurement is based on classification of the financial instrument into one of the following five categories: held-for-trading, held-to-maturity, available-for-sale, loans and receivables or other financial liabilities. ii. Non-derivative financial instruments The carrying amount of cash, accounts receivable, income tax receivable, accounts payable, dividends payable and bank credit facilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of the senior notes are considered a level 2 fair value measurement. The fair value of debt has been disclosed in Note 15. The Company uses the current expected credit loss model for its accounts receivable, which requires the use of a lifetime expected loss provision. In making an assessment as to whether financial assets are credit-impaired, the Company considers: (i) historically realized bad debts; (ii) a counterparty’s present financial condition and whether a counterparty has breached certain contracts; (iii) the probability that a counterparty will enter bankruptcy or other financial reorganization; (iv) changes in economic conditions that correlate to increased levels of default; and (v) the term to maturity of the specified receivable. The carrying amounts of receivables are reduced by the amount of the expected credit loss through an allowance account and losses are recognized within general and administrative expense in the Consolidated Statement of Income/(Loss). If the Company subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus has designated certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. These non-derivative financial instruments will be accounted for under hedge accounting. To be accounted for as a hedge, the U.S. dollar denominated debt must be designated as an effective hedge, both at inception and on an ongoing basis. The required hedge documentation defines the relationship between the U.S. dollar denominated debt and the net investment in the U.S. subsidiary, as well as the Company’s risk management objective and strategy for undertaking the hedging transaction. The Company formally assesses, both at inception and on an ongoing basis, whether the changes in fair value of the U.S. dollar denominated debt are highly effective in offsetting changes in fair value of the net investment in the U.S. subsidiary. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in Other Comprehensive Income/(Loss), net of tax, and are limited to the translation gain or loss on the net investment. Prior to January 1, 2020, the Company did not apply hedge accounting to the net investment in foreign operations and unrealized gains and losses were recognized in net income/loss at the end of the respective reporting period. A reduction in the fair value of the net investment in the U.S. subsidiary or increase in the U.S. dollar denominated debt may result in a portion of the hedge becoming ineffective. If the hedging relationship ceases to be effective or is terminated, hedge accounting is not applied and subsequent gains or losses are recorded through net income/(loss). iii. Derivative financial instruments Enerplus enters into financial derivative contracts in order to manage its exposure to market risks from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. Enerplus has not designated its financial derivative contracts as effective accounting hedges and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a result, all remaining financial derivative contracts are classified as held-for-trading and are recorded at fair value based on a Level 2 designation, with changes in fair value recorded in net income. The fair values of these derivative instruments are generally based on an estimate of the amounts that would be paid or received to settle these instruments at the balance sheet date. Enerplus’ accounting policy is to not offset the fair values of its financial derivative assets and liabilities. Realized gains and losses from commodity price risk management activities are recognized in income when the contract is settled. Unrealized gains and losses on commodity price risk management activities are recognized in income based on the changes in fair value of the contracts at the end of the respective reporting period. Enerplus’ crude oil, natural gas and natural gas liquids physical delivery purchase and sales contracts qualify as normal purchases and sales as they are entered into and held for the purpose of receipt or delivery of products in accordance with the Company’s expected purchase, sale or usage requirements. As such, these contracts are not considered derivative financial instruments. Settlements on these physical contracts are recognized in net income over the term of the contracts as they occur. |
Foreign Currency | l) Foreign Currency i. Foreign currency transactions Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars) using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency of the entity using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Foreign currency differences arising on translation are recognized in net income in the period in which they arise. ii. Foreign operations Assets and liabilities of Enerplus’ U.S. operations, which has a U.S. dollar functional currency, are translated into Canadian dollars at period end exchange rates while revenues and expenses are translated using average rates for the period. Gains and losses from the translation are deferred and included in the cumulative translation adjustment which is recorded in accumulated other comprehensive income. |
Share-Based Compensation | m) Share-Based Compensation Enerplus’ share-based compensation plans include equity-settled Restricted Share Unit (“RSU”) and Performance Share Unit (“PSU”) awards made pursuant to its Share Award Incentive Plan (“SAIP”). The Company is authorized to issue up to 4.5% of outstanding common shares from treasury under the SAIP. Enerplus also has a cash-settled Deferred Share Unit (“DSU”) Plan for Directors (“Director DSU Plan”) and a cash-settled RSU Plan for Directors (“Director RSU Plan”). i. Long-term Incentive (“LTI”) Plans For RSU awards granted under the SAIP, employees receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and vests one-third each year for three years . The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period. For PSU awards granted under the SAIP, executives and management receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded varies by individual and they vest at the end of three years . The value upon vesting is based on the value of the underlying shares plus notional accrued dividends along with a multiplier that ranges from 0 to 2 depending on Enerplus’ performance compared to a peer group of both Canadian and U.S. crude oil and natural gas producers over the vesting period. Under Enerplus’ Director DSU Plan and Director RSU Plan, directors receive compensation in relation to the value of a specified number of underlying notional shares. The number of notional shares awarded is based on the annual equity retainer value. Directors may elect to receive all or a portion of their notional shares under either plan. Under the Director DSU Plan, units vest and are paid at a specified date following the director leaving the Board. Under the Director RSU Plan, units vest one-third each year for three years . The value upon vesting is based on the value of the underlying notional shares plus notional accrued dividends over the vesting period. All Director DSU and RSU grants are settled in cash. Enerplus recognizes non-cash share-based compensation expense over the vesting period of the equity-settled long-term incentive plans, net of realized forfeitures, based on the estimated grant date share price fair value of the respective awards. The grant date fair value is based on the Company’s 20 day volume weighted average price on December 31 prior to the grant date. The fair value for the PSUs is adjusted for the outcome of the performance condition. Share-based compensation charges are recorded on the Consolidated Statements of Income/(Loss) with an offset to paid-in capital. Each period, management performs an estimate of the PSU plan multiplier. Any differences that arise between the actual multiplier on plan settlement and management’s estimate is recorded to share-based compensation. On settlement of these plans, amounts previously recorded to paid-in capital are reclassified to share capital. Enerplus recognizes a liability with respect to its cash-settled long-term incentive plans based on their estimated fair value. The liability is re-measured at each reporting date and at settlement date with any changes in the fair value recorded as share-based compensation, included in general and administrative expense. ii. Stock options Enerplus’ Stock Option Plan was suspended in 2014 and is now closed. Remaining outstanding stock options expired in March 2020. |
Net Income/(Loss) Per Share | n) Net Income/(Loss) Per Share Basic net income/(loss) per common share is computed by dividing net income/(loss) by the weighted average number of common shares outstanding during the period. For the diluted net income per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income. The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all stock options and outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price. |
Contingencies | o) Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recognized when it is probable that a liability has been incurred and the amount can be reasonably estimated. Contingencies are adjusted as additional information becomes available or circumstances change. |
Accounting Changes and Recent Pronouncements Issued | p) Accounting Changes and Recent Pronouncements Issued Except for the changes below, the Company has consistently applied the accounting policies to all periods presented in these Consolidated Financial Statements, effective January 1, 2020 : ● ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350) – The change was applied prospectively and was applied to the 2020 impairment of goodwill (Refer to Note 5). ● ASC 815 – Derivatives and Hedging – relating to the net investment in foreign operations for which the U.S. dollar is the functional currency. Effective January 1, 2020 , foreign exchange gains and losses on Enerplus’ U.S. denominated debt are recorded in other comprehensive income along with translation gains and losses on Enerplus’ net investment in the U.S. Hedge accounting was applied prospectively thus the change did not impact comparative figures. ● ASC 326 – Financial Instruments – Credit Losses – modified retrospective method. The adoption of the standard had no impact on the financial statements. |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
ACCOUNTS RECEIVABLE | |
Schedule of accounts receivable | ($ thousands) December 31, 2020 December 31, 2019 Accrued revenue $ 93,147 $ 142,048 Accounts receivable – trade 16,641 37,736 Allowance for doubtful accounts (3,579) (3,665) Total accounts receivable, net of allowance for doubtful accounts $ 106,209 $ 176,119 |
PROPERTY, PLANT AND EQUIPMENT_2
PROPERTY, PLANT AND EQUIPMENT ("PP&E") (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | |
Schedule of property, plant and equipment | Accumulated Depletion, As at December 31, 2020 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 15,227,076 $ (14,651,517) $ 575,559 Other capital assets 127,527 (108,003) 19,524 Total PP&E $ 15,354,603 $ (14,759,520) $ 595,083 Accumulated Depletion, As at December 31, 2019 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 15,088,724 $ (13,541,362) $ 1,547,362 Other capital assets 125,265 (105,021) 20,244 Total PP&E $ 15,213,989 $ (13,646,383) $ 1,567,606 (1) All of the Company’s unproved properties are included in the full cost pool. |
IMPAIRMENT (Tables)
IMPAIRMENT (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
IMPAIRMENT | |
Schedule of property, plant and equipment impairment expense | ($ thousands) 2020 2019 2018 Crude oil and natural gas properties: Canada cost centre $ 134,349 $ — $ — U.S. cost centre 860,427 — — Total impairment expense $ 994,776 $ — $ — |
Schedule of 12-month average trailing benchmark prices and exchange rates used in the ceiling tests | WTI Crude Oil Edm Light Crude U.S. Henry Hub Gas Exchange Rate Period US$/bbl CDN$/bbl US$/Mcf US$/CDN 2020 $ 39.54 $ 45.56 $ 2.00 1.34 2019 55.85 66.73 2.58 1.33 2018 65.56 69.58 3.10 1.28 |
ACCOUNTS PAYABLE (Tables)
ACCOUNTS PAYABLE (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
ACCOUNTS PAYABLE | |
Schedule of accounts payable | ($ thousands) December 31, 2020 December 31, 2019 Accrued payables $ 107,254 $ 105,928 Accounts payable – trade 144,568 185,612 Total accounts payable $ 251,822 $ 291,540 |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
DEBT | |
Schedule of debt | ($ thousands) December 31, 2020 December 31, 2019 Current: Senior notes $ 103,836 $ 105,998 Long-term: Bank credit facility $ — $ — Senior notes 386,586 500,635 Total debt $ 490,422 $ 606,633 Original Remaining CDN$ Carrying Coupon Principal Principal Value Issue Date Interest Payment Dates Principal Repayment Rate ($ thousands) ($ thousands) ($ thousands) September 3, 2014 March 3 and Sept 3 5 equal annual installments beginning September 3, 2022 3.79% US$200,000 US$105,000 $ 133,613 May 15, 2012 May 15 and Nov 15 Bullet payment on May 15, 2022 4.40% US$20,000 US$20,000 25,450 May 15, 2012 May 15 and Nov 15 4 equal annual installments beginning May 15, 2021 4.40% US$355,000 US$238,400 303,364 June 18, 2009 June 18 Final installment on June 18, 2021 7.97% US$225,000 US$22,000 27,995 Total carrying value $ 490,422 |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
ASSET RETIREMENT OBLIGATION | |
Schedule of changes in asset retirement obligation | ($ thousands) December 31, 2020 December 31, 2019 Balance, beginning of year $ 138,049 $ 126,112 Change in estimates 1,331 23,362 Property acquisition and development activity 2,246 2,068 Divestments (1,030) (2,760) Settlements (17,709) (16,715) Accretion expense 7,321 5,982 Balance, end of year $ 130,208 $ 138,049 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
LEASES | |
Summary of leases | ($ thousands) December 31, 2020 December 31, 2019 Assets Operating right-of-use assets $ 32,853 $ 48,729 Liabilities Current operating lease liabilities $ 13,391 $ 17,541 Non-current operating lease liabilities 23,446 35,530 Total lease liabilities $ 36,837 $ 53,071 Weighted average remaining lease term (years) Operating leases 3.9 4.3 Weighted average discount rate Operating leases 4.2% 4.1% ($ thousands) 2020 2019 Operating lease cost $ 16,585 $ 19,546 Variable lease cost 1,753 (63) Short-term lease cost 9,512 15,332 Sublease income (1,476) (1,072) Total $ 26,374 $ 33,743 ($ thousands) 2020 2019 Cash amounts paid to settle lease liabilities: Operating cash flow used for operating leases $ 16,142 $ 18,637 Right-of-use assets obtained/(terminated) in exchange for lease obligations: Operating leases $ (1,752) $ 20,818 |
Summary of maturity of leases | Maturity of Lease Liabilities ($ thousands) Operating Leases 2021 $ 14,643 2022 8,285 2023 6,963 2024 6,202 2025 1,202 After 2025 2,696 Total lease payments $ 39,991 Less imputed interest (3,154) Total discounted lease payments $ 36,837 Current portion of lease liabilities $ 13,391 Non-current portion of lease liabilities $ 23,446 |
CRUDE OIL AND NATURAL GAS SAL_2
CRUDE OIL AND NATURAL GAS SALES (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
CRUDE OIL AND NATURAL GAS SALES | |
Tabular disclosure of revenue from oil and natural gas sales during the period | ($ thousands) 2020 2019 2018 Crude oil and natural gas sales $ 923,546 $ 1,572,955 $ 1,610,899 Royalties (1) (186,341) (318,149) (318,163) Crude oil and natural gas sales, net of royalties $ 737,205 $ 1,254,806 $ 1,292,736 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). Crude oil and natural gas revenue by country and by product for the years ended December 31, 2020 and 2019 are as follows: 2020 Total revenue, net Natural Natural gas ($ thousands) of royalties (1) Crude oil (2) gas (2) liquids (2) Other (3) Canada $ 96,498 $ 78,798 $ 12,307 $ 3,452 $ 1,942 United States 640,707 508,294 119,030 13,233 149 Total $ 737,205 $ 587,092 $ 131,337 $ 16,685 $ 2,091 2019 Total revenue, net Natural Natural gas ($ thousands) of royalties (1) Crude oil (2) gas (2) liquids (2) Other (3) Canada $ 177,299 $ 145,814 $ 21,776 $ 7,158 $ 2,551 United States 1,077,507 847,182 215,963 14,355 7 Total $ 1,254,806 $ 992,996 $ 237,739 $ 21,513 $ 2,558 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). (2) U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties. (3) Includes third party processing income. |
GENERAL AND ADMINISTRATIVE EX_2
GENERAL AND ADMINISTRATIVE EXPENSE (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
GENERAL AND ADMINISTRATIVE EXPENSE | |
Schedule of General and Administrative Expense | ($ thousands) 2020 2019 2018 General and administrative expense (1) $ 44,584 $ 49,532 $ 49,943 Share-based compensation expense 12,999 23,321 25,840 General and administrative expense $ 57,583 $ 72,853 $ 75,783 (1) Includes non-cash lease expense/(inducement) of $(288) in 2020 and $(720) in 2019. |
FOREIGN EXCHANGE (Tables)
FOREIGN EXCHANGE (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
FOREIGN EXCHANGE | |
Schedule of foreign exchange (gain)/loss | ($ thousands) 2020 2019 2018 Realized: Foreign exchange (gain)/loss $ 554 $ (87) $ 523 Translation of U.S. dollar cash held in Canada (gain)/loss (1,147) 8,794 (19,630) Unrealized: Translation of U.S. dollar debt and working capital (gain)/loss 1,931 (34,085) 58,628 Foreign exchange (gain)/loss $ 1,338 $ (25,378) $ 39,521 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
INCOME TAXES | |
Schedule of the Company's provision for income taxes | ($ thousands) 2020 2019 2018 Current tax Canada $ — $ (13,910) $ (400) United States (14,525) (19,504) (26,693) Current tax expense/(recovery) (14,525) (33,414) (27,093) Deferred tax Canada $ (24,584) $ 11,023 $ 3,915 United States (221,646) 70,252 126,389 Deferred tax expense/(recovery) (246,230) 81,275 130,304 Income tax expense/(recovery) $ (260,755) $ 47,861 $ 103,211 |
Schedule of reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes | ($ thousands) 2020 2019 2018 Income/(loss) before taxes Canada $ (13,507) $ (437,571) $ 104,204 United States (1,170,615) 225,712 377,286 Total income/(loss) before taxes (1,184,122) (211,859) 481,490 Canadian statutory rate 24.00% 26.50% 27.00% Expected income tax expense/(recovery) $ (284,189) $ (56,143) $ 130,002 Impact on taxes resulting from: Foreign and statutory rate differences $ (37,451) $ 27,446 $ (23,859) Share-based compensation 2,073 (5,398) (18,102) Capital gains and losses 17,261 3,994 7,254 Change in valuation allowance (31,195) (22,038) 6,292 Amounts in respect of prior periods 8,905 (19,451) — Non-deductible goodwill impairment and other expenses 63,841 119,451 1,624 Income tax expense/(recovery) $ (260,755) $ 47,861 $ 103,211 |
Schedule of deferred income tax asset (liability) | As at December 31 2020 2019 Deferred income tax assets Property, plant and equipment $ 177,799 $ 59,896 Tax loss carry-forwards and other credits 385,934 383,600 Capital loss carryforwards and other capital items 141,880 154,532 Asset retirement obligation 31,793 33,569 Derivative financial instruments 3,723 — Other assets 8,486 12,219 Deferred income tax assets before valuation allowance 749,615 643,816 Valuation allowance (142,614) (169,129) Deferred income tax assets, net 607,001 474,687 Deferred income tax liabilities Property, plant and equipment $ — $ (100,328) Derivative financial instruments — (1,857) Total deferred income tax liabilities — (102,185) Total deferred income tax asset $ 607,001 $ 372,502 |
Schedule of loss carryforwards and tax credits that can be utilized in future years | As at December 31 2020 Expiration Date Canada Capital losses $ 1,053,000 Indefinite Non-capital losses 284,000 2031-2039 United States Net operating losses – prior to 2018 $ 875,000 2030-2040 Net operating losses – 2018 and thereafter 316,000 Indefinite |
Schedule of changes in the balance of Enerplus' unrecognized tax benefits | ($ thousands) 2020 2019 2018 Balance, beginning of year $ — $ 13,300 $ 13,300 Increase - tax positions in prior periods 21,030 — — Settlements — (13,300) — Balance, end of year $ 21,030 $ — $ 13,300 |
Summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities | Jurisdiction Taxation Years Canada – Federal 2015-2020 United States – Federal 2017-2020 |
SHAREHOLDERS' EQUITY (Tables)
SHAREHOLDERS' EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
SHAREHOLDERS' EQUITY | |
Schedule of share capital | 2020 2019 2018 Authorized: unlimited number of common shares Shares Amount Shares Amount Shares Amount Balance, beginning of year 221,744 $ 3,088,094 239,411 $ 3,337,608 242,129 $ 3,386,946 Issued for cash: Purchase of common shares under Normal Course Issuer Bid (340) (4,731) (18,231) (253,920) (5,925) (82,596) Stock Option Plan — — — — 668 9,138 Non-cash: Share-based compensation – settled (1) 1,160 13,824 564 4,406 2,539 23,389 Stock Option Plan – exercised — — — — — 731 Cancellation of predecessor shares (16) (218) — — — — Balance, end of year 222,548 $ 3,096,969 221,744 $ 3,088,094 239,411 $ 3,337,608 (1) The amount of shares issued on LTI settlement is net of employee withholding taxes in 2020 and 2019. |
Summary of share-based compensation expense which is included in General and Administrative expense on the Consolidated Income Statements | ($ thousands) 2020 2019 2018 Cash: Long-term incentive plans expense $ (1,411) $ 689 $ 133 Non-Cash: Long-term incentive plans expense 13,014 22,324 25,917 Equity swap (gain)/loss 1,396 308 (210) Share-based compensation expense $ 12,999 $ 23,321 $ 25,840 |
Schedule of PSU, RSU and DSU activity | For the year ended December 31, 2020 Cash-settled LTI Plans Equity-settled LTI Plans Total (thousands of units) DSU PSU (1) RSU Balance, beginning of year 422 2,139 1,531 4,092 Granted 133 1,203 1,142 2,478 Vested — (652) (741) (1,393) Forfeited — (138) (107) (245) Balance, end of year 555 2,552 1,825 4,932 (1) Based on underlying awards before any effect of the performance multiplier. |
Schedule of cumulative share-based compensation expense recognized to-date | At December 31, 2020 ($ thousands, except for years) PSU (1) RSU Total Cumulative recognized share-based compensation expense $ 18,564 $ 13,474 $ 32,038 Unrecognized share-based compensation expense 7,444 5,497 12,941 Fair value $ 26,008 $ 18,971 $ 44,979 Weighted-average remaining contractual term (years) 1.8 1.4 (1) Includes estimated performance multipliers. |
Schedule of the stock option plan activity for the period | Number of Options Weighted Average Year ended December 31, 2020 (thousands) Exercise Price Options outstanding, beginning of year 2,107 $ 14.24 Exercised — — Forfeited (8) 14.85 Expired (2,099) 14.24 Options outstanding and exercisable, end of year — $ — |
Schedule of net income/(loss) per share | (thousands, except per share amounts) 2020 2019 2018 Net income/(loss) $ (923,367) $ (259,720) $ 378,279 Weighted average shares outstanding – Basic 222,503 231,334 244,076 Dilutive impact of share-based compensation (1) — — 3,185 Weighted average shares outstanding – Diluted 222,503 231,334 247,261 Net income/(loss) per share Basic $ (4.15) $ (1.12) $ 1.55 Diluted $ (4.15) $ (1.12) $ 1.53 (1) For the years ended December 31, 2020 and 2019, the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share. |
FINANCIAL INSTRUMENTS AND RIS_2
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | |
Schedule of change in fair value of derivative financial instruments | Income Gain/(Loss) 2020 2019 2018 Statement Presentation Equity Swaps $ (1,396) $ (308) $ 210 G&A expense Commodity Derivative Instruments: Oil (25,701) (70,481) 114,822 Commodity derivative Gas 3,550 (10,944) 9,234 instruments Total Unrealized Gain/(Loss) $ (23,547) $ (81,733) $ 124,266 |
Summary of the income statement effects of Enerplus' commodity derivative instruments | ($ thousands) 2020 2019 2018 Change in fair value gain/(loss) $ (22,151) $ (81,425) $ 124,056 Net realized cash gain/(loss) 130,970 15,354 (35,824) Commodity derivative instruments gain/(loss) $ 108,819 $ (66,071) $ 88,232 |
Summary of the fair value of derivative financial instruments | December 31, 2020 December 31, 2019 Assets Liabilities Assets Liabilities ($ thousands) Current Current Current Current Equity Swaps $ — $ 3,613 $ — $ 2,217 Commodity Derivative Instruments: Oil — 15,648 10,570 517 Gas 3,550 — — — Total $ 3,550 $ 19,261 $ 10,570 $ 2,734 |
Summary of management positions | Crude Oil Instruments: Instrument Type (1)(2) bbls/day US$/bbl Jan 1, 2021 – Mar 31, 2021 WTI Swap 5,000 45.55 WTI Purchased Put 15,000 40.53 WTI Sold Put 15,000 32.00 WTI Sold Call 15,000 50.29 Apr 1, 2021 – Jun 30, 2021 WTI Purchased Put 20,000 40.90 WTI Sold Put 20,000 32.00 WTI Sold Call 20,000 50.72 UHC Differential Swap 1,500 (1.80) Jul 1, 2021 – Dec 31, 2021 WTI Purchased Put 23,000 46.39 WTI Sold Put 23,000 36.39 WTI Sold Call 23,000 56.70 UHC Differential Swap 1,500 (1.80) Jan 1, 2022 – Dec 31, 2022 WTI Purchased Put 17,000 50.00 WTI Sold Put 17,000 40.00 WTI Sold Call 17,000 57.91 (1) Transactions with a common term have been aggregated and presented as the weighted average price/bbl before premiums. (2) The total average deferred premium spent on our outstanding hedges is US $0.80 /bbl from January 1, 2021 – December 31, 2021 and US $1.50 /bbl from January 1, 2022 – December 31, 2022. Natural Gas Instruments: Instrument Type MMcf/day US$/Mcf Mar 1, 2021 - Mar 31, 2021 NYMEX Swap 60,000 3.16 Apr 1, 2021 – Oct 31, 2021 NYMEX Swap 60,000 2.90 NYMEX Purchased Put 40,000 2.75 NYMEX Sold Put 40,000 2.15 NYMEX Sold Call 40,000 3.25 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
COMMITMENTS AND CONTINGENCIES | |
Schedule of minimum annual commitments | Minimum Annual Commitment Each Year ($ thousands) Total 2021 2022 2023 2024 2025 Thereafter Senior notes (1) $ 490,422 $ 103,836 $ 128,014 $ 102,564 $ 102,564 $ 26,722 $ 26,722 Transportation commitments 289,993 44,539 30,393 29,358 29,088 29,101 127,514 Processing commitments 9,489 1,519 1,519 1,519 1,519 1,519 1,894 Total commitments (2)(3) $ 789,904 $ 149,894 $ 159,926 $ 133,441 $ 133,172 $ 57,343 $ 156,131 (1) Interest payments have not been included. (2) Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment. (3) US$ commitments have been converted to CDN$ using the December 31, 2020 foreign exchange rate of 1.2725 . |
GEOGRAPHICAL INFORMATION (Table
GEOGRAPHICAL INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
GEOGRAPHICAL INFORMATION | |
Schedule of geographical information | As at and for the year ended December 31, 2020 ($ thousands) Canada U.S. Total Crude oil and natural gas sales, net of royalties $ 96,498 $ 640,707 $ 737,205 Depletion, depreciation and accretion 46,784 246,372 293,156 Property, plant and equipment 112,195 482,888 595,083 Deferred income tax asset 210,615 396,386 607,001 As at and for the year ended December 31, 2019 ($ thousands) Canada U.S. Total Crude oil and natural gas sales, net of royalties $ 177,299 $ 1,077,507 $ 1,254,806 Depletion, depreciation and accretion 59,936 296,894 356,830 Property, plant and equipment 259,514 1,308,092 1,567,606 Deferred income tax asset 185,880 186,622 372,502 Goodwill — 194,015 194,015 Long term income tax receivable — 13,852 13,852 As at and for the year ended December 31, 2018 ($ thousands) Canada U.S. Total Crude oil and natural gas sales, net of royalties $ 198,263 $ 1,094,473 $ 1,292,736 Depletion, depreciation and accretion 58,333 245,941 304,274 Property, plant and equipment 262,159 1,044,912 1,307,071 Deferred income tax asset 196,903 268,221 465,124 Goodwill 451,121 203,678 654,799 Long term income tax receivable — 27,195 27,195 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
SUPPLEMENTAL CASH FLOW INFORMATION | |
Schedule of net change in non-cash operating working capital | ($ thousands) December 31, 2020 December 31, 2019 December 31, 2018 Accounts receivable $ 112,041 $ 8,493 $ (45,385) Other assets (5,611) 4,475 (3,026) Accounts payable (515) (11,005) 44,952 $ 105,915 $ 1,963 $ (3,459) |
Schedule of changes in other non-cash working capital | ($ thousands) December 31, 2020 December 31, 2019 December 31, 2018 Non-cash financing activities (1) $ 8 $ (178) $ (26) Non-cash investing activities (2) $ (37,509) $ 17,682 $ (3,753) (1) Relates to changes in dividends payable and included in dividends on the Consolidated Statements of Cash Flows. (2) Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Consolidated Statements of Cash Flows. |
Schedule of supplementary cash flow information | ($ thousands) December 31, 2020 December 31, 2019 December 31, 2018 Income taxes paid/(received) $ (58,361) $ (71,890) $ (481) Interest paid $ 28,758 $ 33,991 $ 36,161 |
SIGNIFICANT ACCOUNTING POLICI_3
SIGNIFICANT ACCOUNTING POLICIES - Transportation (Details) | 12 Months Ended |
Dec. 31, 2020agreement | |
Transportation | |
Number of agreement types common in the industry | 2 |
SIGNIFICANT ACCOUNTING POLICI_4
SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) | Dec. 31, 2020 |
Oil and Natural Gas Properties | |
Discount rate applied to estimated future net cash flows from proved oil and gas reserves (as a percent) | 10.00% |
SIGNIFICANT ACCOUNTING POLICI_5
SIGNIFICANT ACCOUNTING POLICIES - Financial Instruments (Details) | 12 Months Ended |
Dec. 31, 2020category | |
Financial Instruments | |
Number of categories in which financial instruments are classified | 5 |
SIGNIFICANT ACCOUNTING POLICI_6
SIGNIFICANT ACCOUNTING POLICIES - Share-Based Compensation (Details) | 12 Months Ended |
Dec. 31, 2020 | |
Share-Based Compensation | |
Authorized percentage to issue outstanding common shares from treasury (as a percent) | 4.50% |
Volume weighted average price prior to the grant date, period | 20 days |
RSU | |
Share-Based Compensation | |
Award vesting percentage (as a percent) | 33.33% |
Award vesting period | 3 years |
PSU | |
Share-Based Compensation | |
Award vesting period | 3 years |
Multiplier, low end of range | 0 |
Multiplier, high end of range | 2 |
SIGNIFICANT ACCOUNTING POLICI_7
SIGNIFICANT ACCOUNTING POLICIES - Accounting Changes and Recent Pronouncements Issued - Recently Adopted Accounting Standards and Future Accounting Changes (Details) | Dec. 31, 2020 |
Accounting Standards Update 2017-04 | |
SIGNIFICANT ACCOUNTING POLICIES | |
Change in Accounting Principle, Accounting Standards Update, Adopted | true |
Change in Accounting Principle, Accounting Standards Update, Adoption Date | Jan. 1, 2020 |
Accounting Standards Update 2016-13 | |
SIGNIFICANT ACCOUNTING POLICIES | |
Change in Accounting Principle, Accounting Standards Update, Adopted | true |
Change in Accounting Principle, Accounting Standards Update, Adoption Date | Jan. 1, 2020 |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Accounts Receivable | ||
Accrued revenue | $ 93,147 | $ 142,048 |
Accounts receivable - trade | 16,641 | 37,736 |
Allowance for doubtful accounts | (3,579) | (3,665) |
Total accounts receivable, net of allowance for doubtful accounts | $ 106,209 | $ 176,119 |
PROPERTY, PLANT AND EQUIPMENT_3
PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Tabular Disclosure (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Crude oil and natural gas properties | |||
Crude oil and natural gas properties, cost | $ 15,227,076 | $ 15,088,724 | |
Crude oil and natural gas properties, depreciation, and impairment | (14,651,517) | (13,541,362) | |
Crude oil and natural gas properties, net book value | 575,559 | 1,547,362 | |
Other capital assets | |||
Other capital assets, cost | 127,527 | 125,265 | |
Other capital assets, accumulated depletion, depreciation, and impairment | (108,003) | (105,021) | |
Other capital assets, net book value | 19,524 | 20,244 | |
Property, plant and equipment | |||
Total PP&E, cost | 15,354,603 | 15,213,989 | |
Total PP&E, accumulated depletion, depreciation, and impairment | (14,759,520) | (13,646,383) | |
Property, plant and equipment | $ 595,083 | $ 1,567,606 | $ 1,307,071 |
PROPERTY, PLANT AND EQUIPMENT_4
PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Acquisitions (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Oil and Gas Properties and Land | ||
Property, plant and equipment | ||
Property, plant and equipment, additions | $ 10.1 | $ 24.4 |
PROPERTY, PLANT AND EQUIPMENT_5
PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Divestments (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Property, plant and equipment | ||
Property divestments | $ 6.1 | $ 9.6 |
IMPAIRMENT - Impairment of PP&E
IMPAIRMENT - Impairment of PP&E - Impairment Expense (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2020CAD ($) | |
Impairment | |
Impairment of PP&E | $ 994,776 |
Canada | |
Impairment | |
Impairment of PP&E | 134,349 |
U.S. | |
Impairment | |
Impairment of PP&E | $ 860,427 |
IMPAIRMENT - Impairment of PP_2
IMPAIRMENT - Impairment of PP&E - Ceiling Test (Details) | Dec. 31, 2020$ / Mcf$ / bbl$ / bbl$ / $ | Dec. 31, 2019$ / Mcf$ / bbl$ / bbl$ / $ | Dec. 31, 2018$ / bbl$ / bbl$ / Mcf$ / $ |
Impairment | |||
WTI Crude Oil US$/bbl (in dollars per barrel) | 39.54 | 55.85 | 65.56 |
Edm Light Crude CDN$/bbl (in Canadian dollar per barrel) | 45.56 | 66.73 | 69.58 |
U.S. Henry Hub Gas US$/Mcf (in dollars per Mcf) | $ / Mcf | 2 | 2.58 | 3.10 |
Exchange Rate US$/CDN$ (in Canadian dollars per US dollars) | $ / $ | 1.34 | 1.33 | 1.28 |
IMPAIRMENT - Impairment of Good
IMPAIRMENT - Impairment of Goodwill - General Information (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Impairment | |||
Goodwill impairment | $ 202,767 | $ 451,121 | $ 0 |
Goodwill | 0 | 194,015 | $ 654,799 |
Canadian Reporting Unit | |||
Impairment | |||
Goodwill impairment | $ 451,100 | ||
United States Reporting Unit | |||
Impairment | |||
Goodwill impairment | $ 202,800 |
IMPAIRMENT - Impairment of Go_2
IMPAIRMENT - Impairment of Goodwill - Fair Value Assumptions (Details) | Dec. 31, 2020 |
Measurement Input, Discount Rate | |
Fair Value Assumptions | |
Goodwill, measurement input | 0.15 |
ACCOUNTS PAYABLE (Details)
ACCOUNTS PAYABLE (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Accounts Payable | ||
Accrued payables | $ 107,254 | $ 105,928 |
Accounts payable - trade | 144,568 | 185,612 |
Total accounts payable | $ 251,822 | $ 291,540 |
DEBT - Total Debt (Details)
DEBT - Total Debt (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Debt | ||
Long-term debt, current portion | $ 103,836 | $ 105,998 |
Long-term debt, non-current portion | 386,586 | 500,635 |
Total debt | 490,422 | 606,633 |
Line of Credit | ||
Debt | ||
Long-term debt, non-current portion | 0 | 0 |
Senior notes | ||
Debt | ||
Long-term debt, current portion | 103,836 | 105,998 |
Long-term debt, non-current portion | 386,586 | $ 500,635 |
Total debt | $ 490,422 |
DEBT - Bank Credit Facility (De
DEBT - Bank Credit Facility (Details) - Bank Credit Facility - Line of Credit $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($) | |
Debt | |
Unsecured, covenant-based bank credit facility | $ 600 |
Standby fees on undrawn portion of the facility as a percentage on drawn pricing (as a percent) | 20.00% |
Minimum | Canada Bankers' Acceptances Rate | |
Debt | |
Basis points over bankers' acceptance rates (as a percent) | 1.25% |
Maximum | Canada Bankers' Acceptances Rate | |
Debt | |
Basis points over bankers' acceptance rates (as a percent) | 3.15% |
DEBT - Senior Notes - General I
DEBT - Senior Notes - General Information (Details) $ in Thousands, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2020CAD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019CAD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2018USD ($) | |
Debt | ||||||
Bullet repayment | $ 114,010 | $ 59,429 | $ 29,044 | |||
7.97% senior notes maturing June 18, 2021 | Senior notes | ||||||
Debt | ||||||
Principal repayment amount | $ 22 | $ 22 | $ 22 | |||
4.40% senior notes maturing May 15, 2020 | Senior notes | ||||||
Debt | ||||||
Principal repayment amount | $ 59.6 | |||||
4.40% senior notes maturing May 15, 2022 | Senior notes | ||||||
Debt | ||||||
Bullet repayment | $ 30,000 |
DEBT - Senior Notes - Tabular D
DEBT - Senior Notes - Tabular Disclosure (Details) $ in Thousands, $ in Thousands | Dec. 31, 2020CAD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019CAD ($) |
Debt | |||
Carrying Value | $ 490,422 | $ 606,633 | |
Senior notes | |||
Debt | |||
Carrying Value | $ 490,422 | ||
Senior notes | 3.79% senior notes maturing September 2022 | |||
Debt | |||
Coupon Rate (as a percent) | 3.79% | 3.79% | |
Original Principal | $ 200,000 | ||
Remaining Principal | $ 105,000 | ||
Carrying Value | $ 133,613 | ||
Senior notes | 4.40% senior notes maturing May 15, 2022 | |||
Debt | |||
Coupon Rate (as a percent) | 4.40% | 4.40% | |
Original Principal | $ 20,000 | ||
Remaining Principal | $ 20,000 | ||
Carrying Value | $ 25,450 | ||
Senior notes | 4.40% senior notes maturing May 15, 2020 | |||
Debt | |||
Coupon Rate (as a percent) | 4.40% | 4.40% | |
Original Principal | $ 355,000 | ||
Remaining Principal | $ 238,400 | ||
Carrying Value | $ 303,364 | ||
Senior notes | 7.97% senior notes maturing June 18, 2021 | |||
Debt | |||
Coupon Rate (as a percent) | 7.97% | 7.97% | |
Original Principal | $ 225,000 | ||
Remaining Principal | $ 22,000 | ||
Carrying Value | $ 27,995 |
ASSET RETIREMENT OBLIGATION - T
ASSET RETIREMENT OBLIGATION - Tabular Disclosure (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in asset retirement obligation | ||
Balance, beginning of year | $ 138,049 | $ 126,112 |
Change in estimates | 1,331 | 23,362 |
Property acquisition and development activity | 2,246 | 2,068 |
Divestments | (1,030) | (2,760) |
Settlements | (17,709) | (16,715) |
Accretion expense | 7,321 | 5,982 |
Balance, end of year | $ 130,208 | $ 138,049 |
ASSET RETIREMENT OBLIGATION - A
ASSET RETIREMENT OBLIGATION - Additional Information (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation | |||
Asset retirement obligation | $ 130,208 | $ 138,049 | |
Total undiscounted liability | $ 348,400 | $ 138,000 | $ 344,700 |
Risk free rate for calculating asset retirement obligation (as a percent) | 5.35% | 5.50% | |
Inflation rate for calculating asset retirement obligation (as a percent) | 0.90% | 1.80% |
LEASES - Assets and Liabilities
LEASES - Assets and Liabilities (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Leases | ||
Operating right-of-use assets | $ 32,853 | $ 48,729 |
Current operating lease liabilities | 13,391 | 17,541 |
Non-current operating lease liabilities | 23,446 | 35,530 |
Total lease liabilities | $ 36,837 | $ 53,071 |
LEASES - Weighted Average Remai
LEASES - Weighted Average Remaining Lease Term and Discount Rate (Details) | Dec. 31, 2020 | Dec. 31, 2019 |
Leases | ||
Weighted average remaining lease term (years), operating leases | 3 years 10 months 24 days | 4 years 3 months 18 days |
Weighted average discount rate, operating leases | 4.20% | 4.10% |
LEASES - Lease Expense (Details
LEASES - Lease Expense (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Lease expense | ||
Operating lease cost | $ 16,585 | $ 19,546 |
Variable lease cost | 1,753 | (63) |
Short-term lease cost | 9,512 | 15,332 |
Sublease income | (1,476) | (1,072) |
Total | $ 26,374 | $ 33,743 |
LEASES - Maturities of Lease Li
LEASES - Maturities of Lease Liabilities (Details) $ in Thousands | Dec. 31, 2020CAD ($) |
Maturity of Lease Liabilities | |
2021 | $ 14,643 |
2022 | 8,285 |
2023 | 6,963 |
2024 | 6,202 |
2025 | 1,202 |
After 2025 | 2,696 |
Total lease payments | $ 39,991 |
LEASES - Gross Difference (Deta
LEASES - Gross Difference (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Gross Difference | ||
Total lease payments | $ 39,991 | |
Less: Present value discount | (3,154) | |
Total discounted lease payments | 36,837 | $ 53,071 |
Current portion of lease liabilities | 13,391 | 17,541 |
Non-current operating lease liabilities | $ 23,446 | $ 35,530 |
LEASES - Supplemental Informati
LEASES - Supplemental Information (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Leases | ||
Cash amounts paid to settle lease liabilities, operating cash flow used for operating leases | $ 16,142 | $ 18,637 |
Right-of-use assets obtained/(terminated) in exchange for lease obligations, operating leases | $ (1,752) | $ 20,818 |
CRUDE OIL AND NATURAL GAS SAL_3
CRUDE OIL AND NATURAL GAS SALES - Crude Oil and Natural Gas Sales, Net of Royalties (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Revenues | |||
Crude oil and natural gas sales | $ 923,546 | $ 1,572,955 | $ 1,610,899 |
Royalties | (186,341) | (318,149) | (318,163) |
Crude oil and natural gas sales, net of royalties | $ 737,205 | $ 1,254,806 | $ 1,292,736 |
Type of revenue | us-gaap:OilAndGasMember | us-gaap:OilAndGasMember | us-gaap:OilAndGasMember |
CRUDE OIL AND NATURAL GAS SAL_4
CRUDE OIL AND NATURAL GAS SALES - Revenue by Country and by Product (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | $ 737,205 | $ 1,254,806 | $ 1,292,736 |
Crude Oil | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 587,092 | 992,996 | |
Natural gas | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 131,337 | 237,739 | |
Natural gas liquids | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 16,685 | 21,513 | |
Other | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 2,091 | 2,558 | |
Canada | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 96,498 | 177,299 | 198,263 |
Canada | Crude Oil | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 78,798 | 145,814 | |
Canada | Natural gas | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 12,307 | 21,776 | |
Canada | Natural gas liquids | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 3,452 | 7,158 | |
Canada | Other | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 1,942 | 2,551 | |
U.S. | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 640,707 | 1,077,507 | $ 1,094,473 |
U.S. | Crude Oil | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 508,294 | 847,182 | |
U.S. | Natural gas | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 119,030 | 215,963 | |
U.S. | Natural gas liquids | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | 13,233 | 14,355 | |
U.S. | Other | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales, net of royalties | $ 149 | $ 7 |
GENERAL AND ADMINISTRATIVE EX_3
GENERAL AND ADMINISTRATIVE EXPENSE - Tabular Disclosure (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
GENERAL AND ADMINISTRATIVE EXPENSE | |||
General and administrative expense | $ 44,584 | $ 49,532 | $ 49,943 |
Share-based compensation expense | 12,999 | 23,321 | 25,840 |
General and administrative expense | $ 57,583 | $ 72,853 | $ 75,783 |
GENERAL AND ADMINISTRATIVE EX_4
GENERAL AND ADMINISTRATIVE EXPENSE - Additional Information (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
GENERAL AND ADMINISTRATIVE EXPENSE | ||
Non-cash lease expense (inducement) | $ (288) | $ (720) |
FOREIGN EXCHANGE (Details)
FOREIGN EXCHANGE (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
FOREIGN EXCHANGE | |||
Foreign exchange (gain)/loss | $ 554 | $ (87) | $ 523 |
Translation of U.S. dollar cash held in Canada (gain)/loss | (1,147) | 8,794 | (19,630) |
Translation of U.S. dollar debt and working capital (gain)/loss | 1,931 | (34,085) | 58,628 |
Foreign exchange (gain)/loss | $ 1,338 | $ (25,378) | $ 39,521 |
INCOME TAXES - Provision (Detai
INCOME TAXES - Provision (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Current tax expense/(recovery) | |||
Canada | $ (13,910) | $ (400) | |
United States | $ (14,525) | (19,504) | (26,693) |
Current Tax expense/(recovery) | (14,525) | (33,414) | (27,093) |
Deferred Tax expense/(recovery) | |||
Canada | (24,584) | 11,023 | 3,915 |
United States | (221,646) | 70,252 | 126,389 |
Deferred Tax expense/(recovery) | (246,230) | 81,275 | 130,304 |
Income Tax expense/(recovery) | $ (260,755) | $ 47,861 | $ 103,211 |
INCOME TAXES - Income (Loss) Be
INCOME TAXES - Income (Loss) Before Taxes (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Expenses | |||
Canada | $ (13,507) | $ (437,571) | $ 104,204 |
United States | (1,170,615) | 225,712 | 377,286 |
Income/(Loss) Before Taxes | $ (1,184,122) | $ (211,859) | $ 481,490 |
INCOME TAXES - Reconciliation (
INCOME TAXES - Reconciliation (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes | |||
Canadian statutory rate (as a percent) | 24.00% | 26.50% | 27.00% |
Expected income tax expense/(recovery) | $ (284,189) | $ (56,143) | $ 130,002 |
Foreign and statutory rate differences | (37,451) | 27,446 | (23,859) |
Share-based compensation | 2,073 | (5,398) | (18,102) |
Non-taxable capital (gains)/losses | 17,261 | 3,994 | 7,254 |
Change in valuation allowance | (31,195) | (22,038) | 6,292 |
Amounts in respect of prior periods | 8,905 | (19,451) | |
Non-deductible goodwill impairment and other expenses | 63,841 | 119,451 | 1,624 |
Income Tax expense/(recovery) | $ (260,755) | $ 47,861 | $ 103,211 |
INCOME TAXES - Deferred Tax Ass
INCOME TAXES - Deferred Tax Assets (Liability) (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Deferred income tax assets | ||
Property, plant and equipment | $ 177,799 | $ 59,896 |
Tax loss carryforwards and other credits | 385,934 | 383,600 |
Capital loss carryforwards and other capital items | 141,880 | 154,532 |
Asset retirement obligation | 31,793 | 33,569 |
Derivative financial instruments | 3,723 | |
Deferred Tax Assets, Derivative Instruments | 3,723 | |
Other assets | 8,486 | 12,219 |
Deferred income tax asset before valuation allowance | 749,615 | 643,816 |
Valuation allowance | (142,614) | (169,129) |
Deferred income tax assets, net | 607,001 | 474,687 |
Deferred income tax liabilities | ||
Property, plant and equipment | (100,328) | |
Derivative financial instruments | (1,857) | |
Total deferred income tax liabilities | (102,185) | |
Total deferred income tax asset | $ 607,001 | $ 372,502 |
INCOME TAXES - Additional Infor
INCOME TAXES - Additional Information (Details) $ in Millions | Dec. 31, 2020CAD ($) |
INCOME TAXES | |
Amount reclassified | $ 14.5 |
INCOME TAXES - Operating Loss C
INCOME TAXES - Operating Loss Carryforwards (Details) $ in Thousands | Dec. 31, 2020CAD ($) |
Canada | |
Operating Loss Carryforwards | |
Operating loss carryforward | $ 1,053,000 |
United States | Earliest Tax Year | |
Operating Loss Carryforwards | |
Operating loss carryforward | 875,000 |
United States | Latest Tax Year | |
Operating Loss Carryforwards | |
Operating loss carryforward | $ 316,000 |
INCOME TAXES - Tax Credit Carry
INCOME TAXES - Tax Credit Carryforwards (Details) $ in Thousands | Dec. 31, 2020CAD ($) |
Canada | |
Tax Credit Carryforwards | |
Tax credit carryforward | $ 284,000 |
INCOME TAXES - Unrecognized Tax
INCOME TAXES - Unrecognized Tax Benefits - Tabular Disclosure (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Changes in the balance of unrecognized tax benefits | |||
Balance, beginning of year | $ 0 | $ 13,300 | $ 13,300 |
Increase - tax positions in prior periods | 21,030 | 0 | 0 |
Settlements | 0 | (13,300) | 0 |
Balance, end of year | $ 21,030 | $ 0 | $ 13,300 |
INCOME TAXES - Unrecognized T_2
INCOME TAXES - Unrecognized Tax Benefits - Additional Information (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Income Taxes | ||||
Unrecognized tax benefits | $ 21,030 | $ 0 | $ 13,300 | $ 13,300 |
Unrecognized tax benefits, if recognized, would affect the effective income tax rate | $ 21,030 |
SHAREHOLDERS' EQUITY - Share Ca
SHAREHOLDERS' EQUITY - Share Capital - Tabular Disclosure (Details) $ in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2020CAD ($)shares | Dec. 31, 2019CAD ($)shares | Dec. 31, 2019USD ($)shares | Dec. 31, 2018CAD ($)shares | |
Increase (decrease) in equity | ||||
Balance, beginning of year | $ | $ 1,471,558 | $ 2,000,989 | ||
Balance, beginning of year (in shares) | shares | 222,000,000 | |||
Purchase of common shares under Normal Course Issuer Bid | $ (2,500) | $ (178.8) | ||
Purchase of common shares under Normal Course Issuer Bid (in shares) | shares | (340,434) | (18,231,401) | (18,231,401) | |
Balance, end of year | $ | $ 535,680 | $ 1,471,558 | $ 2,000,989 | |
Balance, end of year (in shares) | shares | 223,000,000 | 222,000,000 | 222,000,000 | |
Share Capital | ||||
Increase (decrease) in equity | ||||
Balance, beginning of year | $ | $ 3,088,094 | $ 3,337,608 | $ 3,386,946 | |
Balance, beginning of year (in shares) | shares | 221,744,000 | 239,411,000 | 239,411,000 | 242,129,000 |
Purchase of common shares under Normal Course Issuer Bid | $ (4,731) | $ (253,920) | $ (253.9) | $ (82,596) |
Purchase of common shares under Normal Course Issuer Bid (in shares) | shares | (340,000) | (18,231,000) | (18,231,000) | (5,925,000) |
Stock Option Plan | $ | $ (218) | $ 9,138 | ||
Stock Option Plan (in shares) | shares | 668,000 | |||
Stock issue costs (net of tax $2,621) | $ | (4,731) | $ (253,920) | $ (82,596) | |
Share-based compensation - settled | $ | $ 13,824 | $ 4,406 | $ 23,389 | |
Share-based compensation - settled (in shares) | shares | 1,160,000 | 564,000 | 564,000 | 2,539,000 |
Stock Option Plan - exercised | $ | $ 731 | |||
Cancellation of predecessor shares | $ | $ (218) | |||
Cancellation of predecessor shares (in shares) | shares | (16,000) | |||
Balance, end of year | $ | $ 3,096,969 | $ 3,088,094 | $ 3,337,608 | |
Balance, end of year (in shares) | shares | 222,548,000 | 221,744,000 | 221,744,000 | 239,411,000 |
SHAREHOLDERS' EQUITY - Share _2
SHAREHOLDERS' EQUITY - Share Capital - Shares Authorized (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Share capital | ||
Share capital, shares authorized, unlimited | Unlimited | Unlimited |
Share capital, par value (in CAD per share) | $ 0 | $ 0 |
SHAREHOLDERS' EQUITY - Share _3
SHAREHOLDERS' EQUITY - Share Capital - Dividends (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Dividends | |||
Dividend paid per common share (in CAD per share) | $ 0.12 | $ 0.12 | $ 0.12 |
Dividends declared | $ 26.7 | $ 27.7 | $ 29.3 |
SHAREHOLDERS' EQUITY - Share _4
SHAREHOLDERS' EQUITY - Share Capital - Share Repurchases (Details) $ / shares in Units, $ in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2020CAD ($)$ / sharesshares | Dec. 31, 2019CAD ($)$ / sharesshares | Dec. 31, 2019USD ($)shares | Dec. 31, 2018CAD ($)shares | |
Share capital | ||||
Shares purchased for cancellation (in shares) | 340,434 | 18,231,401 | 18,231,401 | |
Average price per share (in CAD per share) | $ / shares | $ 7.44 | $ 9.80 | ||
Purchase of common shares under Normal Course Issuer Bid | $ 2,500 | $ 178.8 | ||
Share Capital | ||||
Share capital | ||||
Shares purchased for cancellation (in shares) | 340,000 | 18,231,000 | 18,231,000 | 5,925,000 |
Purchase of common shares under Normal Course Issuer Bid | $ 4,731 | $ 253,920 | $ 253.9 | $ 82,596 |
Accumulated Deficit | ||||
Share capital | ||||
Purchase of common shares under Normal Course Issuer Bid | $ (2,195) | $ (75,127) | $ (75.1) | $ (3,569) |
SHAREHOLDERS' EQUITY - Share-Ba
SHAREHOLDERS' EQUITY - Share-Based Compensation (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation | |||
Share-based compensation expense | $ 12,999 | $ 23,321 | $ 25,840 |
Cash Settled DSU | |||
Share-based Compensation | |||
Share-based compensation expense | (1,411) | 689 | 133 |
Equity-settled Long-term Incentive Plans | |||
Share-based Compensation | |||
Share-based compensation expense | 13,014 | 22,324 | 25,917 |
Equity Swaps | |||
Share-based Compensation | |||
Share-based compensation expense | $ 1,396 | $ 308 | $ (210) |
SHAREHOLDERS' EQUITY - Long-ter
SHAREHOLDERS' EQUITY - Long-term Incentive Plans - Activity (Details) shares in Thousands | 12 Months Ended |
Dec. 31, 2020shares | |
Number of units | |
Balance, beginning of year (in shares) | 4,092 |
Granted (in shares) | 2,478 |
Vested (in shares) | (1,393) |
Forfeited (in shares) | (245) |
Balance, end of year (in shares) | 4,932 |
Cash Settled DSU | |
Number of units | |
Balance, beginning of year (in shares) | 422 |
Granted (in shares) | 133 |
Balance, end of year (in shares) | 555 |
PSU | |
Number of units | |
Balance, beginning of year (in shares) | 2,139 |
Granted (in shares) | 1,203 |
Vested (in shares) | (652) |
Forfeited (in shares) | (138) |
Balance, end of year (in shares) | 2,552 |
RSU | |
Number of units | |
Balance, beginning of year (in shares) | 1,531 |
Granted (in shares) | 1,142 |
Vested (in shares) | (741) |
Forfeited (in shares) | (107) |
Balance, end of year (in shares) | 1,825 |
SHAREHOLDERS' EQUITY - Cash-set
SHAREHOLDERS' EQUITY - Cash-settled LTI Plans (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation | |||
Accounts payable | $ 251,822 | $ 291,540 | |
Cash Settled DSU | |||
Share-based Compensation | |||
Cash share-based compensation (recovery) expense | (1,400) | 700 | $ 100 |
Accounts payable | $ 2,200 | $ 3,900 |
SHAREHOLDERS' EQUITY - Cumulati
SHAREHOLDERS' EQUITY - Cumulative Share-based Compensation Expense (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Share-Based Compensation | ||
Cash withholding taxes | $ 7,232 | $ 4,952 |
Equity-settled Long-term Incentive Plans | ||
Share-Based Compensation | ||
Cumulative recognized share-based compensation expense | 32,038 | |
Unrecognized share-based compensation expense | 12,941 | |
Fair value | 44,979 | |
PSU | ||
Share-Based Compensation | ||
Cumulative recognized share-based compensation expense | 18,564 | |
Unrecognized share-based compensation expense | 7,444 | |
Fair value | $ 26,008 | |
Weighted-average remaining contractual term (years) | 1 year 9 months 18 days | |
RSU | ||
Share-Based Compensation | ||
Cumulative recognized share-based compensation expense | $ 13,474 | |
Unrecognized share-based compensation expense | 5,497 | |
Fair value | $ 18,971 | |
Weighted-average remaining contractual term (years) | 1 year 4 months 24 days |
SHAREHOLDERS' EQUITY - Stock Op
SHAREHOLDERS' EQUITY - Stock Option Plan - Activity (Details) shares in Thousands | 12 Months Ended |
Dec. 31, 2020$ / sharesshares | |
Number of Options | |
Options outstanding, Beginning of year (in shares) | shares | 2,107 |
Exercised (in shares) | shares | 0 |
Forfeited (in shares) | shares | (8) |
Expired (in shares) | shares | (2,099) |
Options outstanding, End of year (in shares) | shares | 0 |
Weighted Average Exercise Price | |
Options outstanding, Beginning of year (in dollars per share) | $ / shares | $ 14.24 |
Exercised (in dollars per share) | $ / shares | 0 |
Forfeited (in dollars per share) | $ / shares | 14.85 |
Expired (in dollars per share) | $ / shares | 14.24 |
Options outstanding, End of year (in dollars per share) | $ / shares | $ 0 |
SHAREHOLDERS' EQUITY - Net Inco
SHAREHOLDERS' EQUITY - Net Income/(Loss) (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Basic and diluted net income/(loss) per share | |||
Net income/(loss) | $ (923,367) | $ (259,720) | $ 378,279 |
Net income/(loss) - basic | (923,367) | (259,720) | 378,279 |
Net income/(loss) - diluted | $ (923,367) | $ (259,720) | $ 378,279 |
Weighted average shares outstanding | |||
Weighted average shares outstanding - Basic (in shares) | 222,503 | 231,334 | 244,076 |
Dilutive impact of share-based compensation (in shares) | 3,185 | ||
Weighted average shares outstanding - Diluted (in shares) | 222,503 | 231,334 | 247,261 |
Net income/(loss) per share | |||
Basic (in CAD per share) | $ (4.15) | $ (1.12) | $ 1.55 |
Diluted (in CAD per share) | $ (4.15) | $ (1.12) | $ 1.53 |
FINANCIAL INSTRUMENTS AND RIS_3
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value Measurements (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Fair Value Measurements | ||
Transfers between hierarchy levels | $ 0 | |
Senior notes | Carrying Value | ||
Fair Value Measurements | ||
Long-term debt, fair value | 490.4 | $ 606.6 |
Senior notes | Fair Value | ||
Fair Value Measurements | ||
Long-term debt, fair value | $ 494.1 | $ 613.8 |
FINANCIAL INSTRUMENTS AND RIS_4
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Change in Fair Value (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Change in fair value | |||
Total Gain/(Loss) | $ (23,547) | $ (81,733) | $ 124,266 |
Equity Swaps | |||
Change in fair value | |||
Total Gain/(Loss) | (1,396) | (308) | 210 |
Commodity Derivative Instruments | |||
Change in fair value | |||
Unrealized Gain (Loss) on Commodity Contracts | (22,151) | (81,425) | 124,056 |
Commodity Derivative Instruments | Crude Oil | |||
Change in fair value | |||
Unrealized Gain (Loss) on Commodity Contracts | (25,701) | (70,481) | 114,822 |
Commodity Derivative Instruments | Gas | |||
Change in fair value | |||
Unrealized Gain (Loss) on Commodity Contracts | $ 3,550 | $ (10,944) | $ 9,234 |
FINANCIAL INSTRUMENTS AND RIS_5
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Derivatives (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Derivative Financial Instruments | |||
Commodity derivative instruments gain/(loss) | $ 108,819 | $ (66,071) | $ 88,232 |
Commodity Derivative Instruments | |||
Derivative Financial Instruments | |||
Change in fair value gain/(loss) | (22,151) | (81,425) | 124,056 |
Net realized cash gain/(loss) | 130,970 | 15,354 | (35,824) |
Commodity derivative instruments gain/(loss) | $ 108,819 | $ (66,071) | $ 88,232 |
FINANCIAL INSTRUMENTS AND RIS_6
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Assets | ||
Assets | $ 3,550 | $ 10,570 |
Liabilities | ||
Liabilities | 19,261 | 2,734 |
Equity Swaps | ||
Liabilities | ||
Liabilities | 3,613 | 2,217 |
Commodity Derivative Instruments | Crude Oil | ||
Assets | ||
Assets | 10,570 | |
Liabilities | ||
Liabilities | 15,648 | $ 517 |
Commodity Derivative Instruments | Gas | ||
Assets | ||
Assets | $ 3,550 |
FINANCIAL INSTRUMENTS AND RIS_7
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - General Information (Details) | 12 Months Ended |
Dec. 31, 2020 | |
Commodity Derivative Instruments | |
Risk Management | |
Maximum percentage of forecasted production volumes net of royalties considered to enter into commodity contracts | 80.00% |
FINANCIAL INSTRUMENTS AND RIS_8
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - Crude Oil Instruments (Details) | 12 Months Ended |
Dec. 31, 2020bbl / dMMcf / d$ / bbl$ / Mcf | |
January 1, 2021 to December 31, 2021, West Texas Intermediate | |
Risk Management | |
Total average deferred premium on outstanding hedges | 0.80 |
January 1, 2021 to March 31, 2021, West Texas Intermediate | Swap | Crude Oil | |
Risk Management | |
Volume | bbl / d | 5,000 |
Weighted average price | 45.55 |
April 1, 2021 to June 30, 2021, West Texas Intermediate | Differential swap | Crude Oil | |
Risk Management | |
Volume | bbl / d | 1,500 |
Weighted average price (negative price) | (1.80) |
July 1, 2021 to December 31, 2021, West Texas Intermediate | Differential swap | Crude Oil | |
Risk Management | |
Volume | bbl / d | 1,500 |
Weighted average price (negative price) | (1.80) |
January 1, 2022 to December 31, 2022, West Texas Intermediate | |
Risk Management | |
Total average deferred premium on outstanding hedges | 1.50 |
March 1, 2021 to March 31, 2021, New York Mercantile Exchange | Swap | Natural Gas | |
Risk Management | |
Volume | MMcf / d | 60,000 |
Weighted average price | $ / Mcf | 3.16 |
April 1, 2021 to October 31, 2021, New York Mercantile Exchange | Swap | Natural Gas | |
Risk Management | |
Volume | MMcf / d | 60,000 |
Weighted average price | $ / Mcf | 2.90 |
Purchased | January 1, 2021 to March 31, 2021, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 15,000 |
Weighted average price | 40.53 |
Purchased | April 1, 2021 to June 30, 2021, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 20,000 |
Weighted average price | 40.90 |
Purchased | July 1, 2021 to December 31, 2021, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 23,000 |
Weighted average price | 46.39 |
Purchased | January 1, 2022 to December 31, 2022, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 17,000 |
Weighted average price | 50 |
Purchased | April 1, 2021 to October 31, 2021, New York Mercantile Exchange | Put | Natural Gas | |
Risk Management | |
Volume | MMcf / d | 40,000 |
Weighted average price | $ / Mcf | 2.75 |
Sold | January 1, 2021 to March 31, 2021, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 15,000 |
Weighted average price | 32 |
Sold | January 1, 2021 to March 31, 2021, West Texas Intermediate | Call | Crude Oil | |
Risk Management | |
Volume | bbl / d | 15,000 |
Weighted average price | 50.29 |
Sold | April 1, 2021 to June 30, 2021, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 20,000 |
Weighted average price | 32 |
Sold | April 1, 2021 to June 30, 2021, West Texas Intermediate | Call | Crude Oil | |
Risk Management | |
Volume | bbl / d | 20,000 |
Weighted average price | 50.72 |
Sold | July 1, 2021 to December 31, 2021, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 23,000 |
Weighted average price | 36.39 |
Sold | July 1, 2021 to December 31, 2021, West Texas Intermediate | Call | Crude Oil | |
Risk Management | |
Volume | bbl / d | 23,000 |
Weighted average price | 56.70 |
Sold | January 1, 2022 to December 31, 2022, West Texas Intermediate | Put | Crude Oil | |
Risk Management | |
Volume | bbl / d | 17,000 |
Weighted average price | 40 |
Sold | January 1, 2022 to December 31, 2022, West Texas Intermediate | Call | Crude Oil | |
Risk Management | |
Volume | bbl / d | 17,000 |
Weighted average price | 57.91 |
Sold | April 1, 2021 to October 31, 2021, New York Mercantile Exchange | Put | Natural Gas | |
Risk Management | |
Volume | MMcf / d | 40,000 |
Weighted average price | $ / Mcf | 2.15 |
Sold | April 1, 2021 to October 31, 2021, New York Mercantile Exchange | Call | Natural Gas | |
Risk Management | |
Volume | MMcf / d | 40,000 |
Weighted average price | $ / Mcf | 3.25 |
FINANCIAL INSTRUMENTS AND RIS_9
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Credit Risk (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | ||
Allowance for doubtful accounts | $ 3,579 | $ 3,665 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Commitments - Senior Notes (Details) - CAD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Senior notes | ||
Total debt | $ 490,422 | $ 606,633 |
2021 | 103,836 | |
2022 | 128,014 | |
2023 | 102,564 | |
2024 | 102,564 | |
2025 | 26,722 | |
Thereafter | $ 26,722 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - Commitments - Other Commitments (Details) $ in Thousands | Dec. 31, 2020CAD ($) |
Transportation commitments | |
Other Commitments | |
Total | $ 289,993 |
2021 | 44,539 |
2022 | 30,393 |
2023 | 29,358 |
2024 | 29,088 |
2025 | 29,101 |
Thereafter | 127,514 |
Processing commitments | |
Other Commitments | |
Total | 9,489 |
2021 | 1,519 |
2022 | 1,519 |
2023 | 1,519 |
2024 | 1,519 |
2025 | 1,519 |
Thereafter | $ 1,894 |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES - Commitments - Total Commitments (Details) $ in Thousands | Dec. 31, 2020CAD ($) |
Total Commitments | |
Total | $ 789,904 |
2021 | 149,894 |
2022 | 159,926 |
2023 | 133,441 |
2024 | 133,172 |
2025 | 57,343 |
Thereafter | $ 156,131 |
COMMITMENTS AND CONTINGENCIES_4
COMMITMENTS AND CONTINGENCIES - Commitments - Exchange Rate (Details) | Dec. 31, 2020$ / $ |
Commitments | |
Exchange Rate US$/CDN$ (in Canadian dollars per US dollars) | 1.2725 |
GEOGRAPHICAL INFORMATION (Detai
GEOGRAPHICAL INFORMATION (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Geographical Information | |||
Crude oil and natural gas sales, net of royalties | $ 737,205 | $ 1,254,806 | $ 1,292,736 |
Depletion, depreciation and accretion | 293,156 | 356,830 | 304,274 |
Property, plant and equipment | 595,083 | 1,567,606 | 1,307,071 |
Deferred income tax asset | 607,001 | 372,502 | 465,124 |
Goodwill | 0 | 194,015 | 654,799 |
Long term income tax receivable | 13,852 | 27,195 | |
Canada | |||
Geographical Information | |||
Crude oil and natural gas sales, net of royalties | 96,498 | 177,299 | 198,263 |
Depletion, depreciation and accretion | 46,784 | 59,936 | 58,333 |
Property, plant and equipment | 112,195 | 259,514 | 262,159 |
Deferred income tax asset | 210,615 | 185,880 | 196,903 |
Goodwill | 451,121 | ||
U.S. | |||
Geographical Information | |||
Crude oil and natural gas sales, net of royalties | 640,707 | 1,077,507 | 1,094,473 |
Depletion, depreciation and accretion | 246,372 | 296,894 | 245,941 |
Property, plant and equipment | 482,888 | 1,308,092 | 1,044,912 |
Deferred income tax asset | $ 396,386 | 186,622 | 268,221 |
Goodwill | 194,015 | 203,678 | |
Long term income tax receivable | $ 13,852 | $ 27,195 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Operating Working Capital (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Changes in Non-Cash Operating Working Capital | |||
Accounts receivable | $ 112,041 | $ 8,493 | $ (45,385) |
Other current assets | (5,611) | 4,475 | (3,026) |
Accounts payable | (515) | (11,005) | 44,952 |
Changes in non-cash operating working capital | $ 105,915 | $ 1,963 | $ (3,459) |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Other Non-Cash Working Capital (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Changes in Other Non-Cash Working Capital | |||
Non-cash financing activities | $ 8 | $ (178) | $ (26) |
Non-cash investing activities | $ (37,509) | $ 17,682 | $ (3,753) |
SUPPLEMENTAL CASH FLOW INFORM_5
SUPPLEMENTAL CASH FLOW INFORMATION - Other (Details) - CAD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Other | |||
Income taxes paid/(received) | $ (58,361) | $ (71,890) | $ (481) |
Interest paid | $ 28,758 | $ 33,991 | $ 36,161 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) $ / shares in Units, $ in Thousands, $ in Millions | Feb. 03, 2021CAD ($)$ / sharesshares | Jan. 25, 2021USD ($) | Mar. 10, 2021USD ($) | Dec. 31, 2018CAD ($) |
Common shares issued | ||||
Proceeds from the issuance of shares (net of issue costs) | $ 9,138 | |||
Subsequent Event | ||||
Common shares issued | ||||
Proceeds from the issuance of shares (net of issue costs) | $ 132,300 | |||
Common shares issued (in shares) | shares | 33,062,500 | |||
Share price (in CAD per share) | $ / shares | $ 4 | |||
Subsequent Event | Unsecured Debt | Three-year senior unsecured term loan | ||||
Debt | ||||
Debt instrument, issuance date | Jan. 25, 2021 | |||
Debt instrument, term | 3 years | |||
Principal amount of debt | $ 400 | |||
Subsequent Event | Bruin E&P HoldCo, LLC | ||||
Business acquisition, date of acquisition | ||||
Purchase agreement date | Jan. 25, 2021 | |||
Subsequent Event | Bruin E&P HoldCo, LLC | Forecast | ||||
Business combination, consideration transferred | ||||
Consideration | $ 465 |