Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2021shares | |
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, 2021 |
Current Fiscal Year End Date | --12-31 |
Document Fiscal Year Focus | 2021 |
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 | 243,852,379 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity Emerging Growth Company | false |
Auditor Name | KPMG LLP |
Auditor Location | Calgary, Canada |
Auditor Firm ID | 85 |
ICFR Auditor Attestation Flag | true |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Business Contact [Member] | |
Document Information [Line Items] | |
Contact Personnel Name | Enerplus Resources (USA) Inc |
Entity Address, Address Line One | US Bank Tower, Suite 2200 |
Entity Address, Address Line Two | 950 - 17th Street |
Entity Address, City or Town | Denver |
Entity Address, State or Province | CO |
Entity Address, Postal Zip Code | 80202-2805 |
City Area Code | 720 |
Local Phone Number | 279-5500 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Current assets | ||
Cash and cash equivalents | $ 61,348 | $ 89,945 |
Accounts receivable | 227,988 | 83,596 |
Other current assets | 10,956 | 5,609 |
Derivative financial assets | 5,668 | 2,790 |
Total Current Assets | 305,960 | 181,940 |
Property, plant and equipment: | ||
Crude oil and natural gas properties (full cost method) | 1,253,505 | 452,302 |
Other capital assets | 13,887 | 11,499 |
Property, plant and equipment | 1,267,392 | 463,801 |
Other long-term assets | 9,756 | 3,845 |
Right-of-use assets | 26,118 | 25,818 |
Deferred income tax asset | 380,858 | 477,014 |
Total Assets | 1,990,084 | 1,152,418 |
Current liabilities | ||
Accounts payable | 367,008 | 197,895 |
Dividends payable | 1,749 | |
Current portion of long-term debt | 100,600 | 81,600 |
Derivative financial liabilities | 143,200 | 15,136 |
Current portion of lease liabilities | 10,618 | 10,523 |
Total Current Liabilities | 621,426 | 306,903 |
Long-term debt | 601,171 | 303,800 |
Asset retirement obligation | 132,814 | 102,325 |
Derivative financial liabilities | 7,098 | |
Lease liabilities | 18,265 | 18,425 |
Total Non-current Liabilities | 759,348 | 424,550 |
Total Liabilities | 1,380,774 | 731,453 |
Shareholders' Equity | ||
Share capital - authorized unlimited common shares, no par value Issued and outstanding: December 31, 2021 - 244 million shares; December 31, 2020 - 223 million shares | 3,094,061 | 3,113,829 |
Paid-in capital | 50,881 | 49,382 |
Accumulated deficit | (2,238,325) | (2,447,735) |
Accumulated other comprehensive loss | (297,307) | (294,511) |
Total Shareholders' Equity | 609,310 | 420,965 |
Total Liabilities & Shareholders' Equity | 1,990,084 | 1,152,418 |
Commitments and Contingencies |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Share capital | ||
Share capital, shares authorized, unlimited | Unlimited | Unlimited |
Share capital, par value (in dollars per share) | $ 0 | $ 0 |
Share capital, shares issued (in shares) | 244 | 223 |
Share capital, shares outstanding (in shares) | 224 | 223 |
Consolidated Statements of Inco
Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Revenues | |||
Crude oil and natural gas sales | $ 1,482,575 | $ 553,739 | $ 945,894 |
Type of revenue | Oil and Gas [Member] | Oil and Gas [Member] | Oil and Gas [Member] |
Commodity derivative instruments gain/(loss) | $ (274,432) | $ 75,742 | $ (47,930) |
Total | 1,208,143 | 629,481 | 897,964 |
Expenses | |||
Production taxes | 101,953 | 37,417 | 62,662 |
General and administrative | 56,807 | 43,097 | 54,920 |
Depletion, depreciation and accretion | 271,336 | 218,118 | 269,046 |
Asset impairment | 3,420 | 751,723 | 0 |
Goodwill impairment | 149,217 | 347,283 | |
Interest | 27,395 | 20,737 | 25,580 |
Foreign exchange (gain)/loss | (6,908) | 1,232 | (16,420) |
Transaction costs and other expense/(income) | (2,487) | 4,489 | (5,695) |
Total | 872,258 | 1,521,808 | 1,065,960 |
Income/(Loss) Before Taxes | 335,885 | (892,327) | (167,996) |
Current income tax expense/(recovery) | 2,689 | (10,716) | (25,246) |
Deferred income tax expense/(recovery) | 98,755 | (188,260) | 61,650 |
Net Income/(Loss) | 234,441 | (693,351) | (204,400) |
Other Comprehensive Income/(Loss) | |||
Unrealized gain/(loss) on foreign currency translation | (6,893) | (2,169) | 11,995 |
Foreign exchange gain/(loss) on net investment hedge, net of tax | 4,097 | 1,780 | 0 |
Total Comprehensive Income/(Loss) | $ 231,645 | $ (693,740) | $ (192,405) |
Net Income/(Loss) per Share | |||
Basic (in dollars per share) | $ 0.93 | $ (3.12) | $ (0.88) |
Diluted (in dollars per share) | $ 0.90 | $ (3.12) | $ (0.88) |
Operating | |||
Expenses | |||
Costs of goods sold | $ 292,433 | $ 197,097 | $ 219,343 |
Transportation | |||
Expenses | |||
Costs of goods sold | $ 128,309 | $ 98,681 | $ 109,241 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands | Share Capital | Paid-in Capital | Accumulated Deficit | Accumulated Other Comprehensive Income/(Loss) | Total |
Balance, beginning of year at Dec. 31, 2018 | $ 3,294,496 | $ 46,626 | $ (1,567,680) | $ (306,117) | |
Increase (decrease) in equity | |||||
Purchase of common shares under Normal Course Issuer Bid | (190,917) | 56,632 | $ (134,300) | ||
Share-based compensation - tax withholdings settled in cash | (3,705) | ||||
Share-based compensation - treasury settled | 3,296 | (3,296) | |||
Share-based compensation - non-cash | 16,814 | ||||
Net income/(loss) | (204,400) | (204,400) | |||
Dividends declared | (20,907) | (20,900) | |||
Unrealized gain/(loss) on foreign currency translation | 11,995 | 11,995 | |||
Foreign exchange gain/(loss) on net investment hedge, net of tax | 0 | ||||
Balance, end of year at Dec. 31, 2019 | 3,106,875 | 56,439 | (1,736,355) | (294,122) | 1,132,837 |
Increase (decrease) in equity | |||||
Purchase of common shares under Normal Course Issuer Bid | (3,582) | 1,775 | (1,900) | ||
Share-based compensation - tax withholdings settled in cash | (5,567) | ||||
Share-based compensation - treasury settled | 10,694 | (10,694) | |||
Share-based compensation - non-cash | 9,204 | ||||
Net income/(loss) | (693,351) | (693,351) | |||
Cancellation of predecessor shares | (158) | 158 | |||
Dividends declared | (19,962) | (20,000) | |||
Unrealized gain/(loss) on foreign currency translation | (2,169) | (2,169) | |||
Foreign exchange gain/(loss) on net investment hedge, net of tax | 1,780 | 1,780 | |||
Balance, end of year at Dec. 31, 2020 | 3,113,829 | 49,382 | (2,447,735) | (294,511) | 420,965 |
Increase (decrease) in equity | |||||
Issue of shares (net of tax effected issue costs) | 99,516 | ||||
Purchase of common shares under Normal Course Issuer Bid | (128,686) | 5,504 | (123,200) | ||
Share-based compensation - tax withholdings settled in cash | (3,551) | ||||
Share-based compensation - treasury settled | 9,402 | (9,402) | |||
Share-based compensation - non-cash | 14,452 | ||||
Net income/(loss) | 234,441 | 234,441 | |||
Dividends declared | (30,535) | (30,500) | |||
Unrealized gain/(loss) on foreign currency translation | (6,893) | (6,893) | |||
Foreign exchange gain/(loss) on net investment hedge, net of tax | 4,097 | 4,097 | |||
Balance, end of year at Dec. 31, 2021 | $ 3,094,061 | $ 50,881 | $ (2,238,325) | $ (297,307) | $ 609,310 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) | Feb. 24, 2022$ / shares | Dec. 31, 2021$ / shares | Dec. 31, 2021$ / shares | Dec. 31, 2020$ / shares | Dec. 31, 2020$ / shares | Dec. 31, 2019$ / shares | Dec. 31, 2019$ / shares |
Dividends declared | |||||||
Dividends declared per share | (per share) | $ 0.033 | $ 0.15 | $ 0.12 | $ 0.12 | $ 0.09 | $ 0.12 | $ 0.09 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating Activities | |||
Net income/(loss) | $ 234,441 | $ (693,351) | $ (204,400) |
Non-cash items add/(deduct): | |||
Depletion, depreciation and accretion | 271,336 | 218,118 | 269,046 |
Asset impairment | 3,420 | 751,723 | 0 |
Goodwill impairment | 149,217 | 347,283 | |
Changes in fair value of derivative instruments | 109,536 | 18,074 | 59,750 |
Deferred income tax expense/(recovery) | 98,755 | (188,260) | 61,650 |
Foreign exchange (gain)/loss on debt and working capital | (8,055) | 1,363 | (21,899) |
Share-based compensation and general and administrative | 13,424 | 9,508 | 17,356 |
Other expense/(income) | (4,594) | ||
Amortization of debt issuance costs | 1,093 | 0 | |
Foreign exchange (gain)/loss on U.S. dollar cash held in parent company | (2,330) | (902) | 6,825 |
Other income reclassified to Investing Activities | (4,593) | ||
Asset retirement obligation expenditures | (12,951) | (13,275) | (12,646) |
Changes in non-cash operating working capital | (94,643) | 83,669 | (3,197) |
Cash flow from/(used in) operating activities | 604,839 | 335,884 | 519,768 |
Financing Activities | |||
Proceeds from bank term loan/bank credit facility | 400,000 | ||
Debt issue costs | (4,621) | ||
Repayment of senior notes | (81,600) | (81,600) | (44,444) |
Proceeds from the issuance of shares | 98,339 | ||
Purchase of common shares under Normal Course Issuer Bid | (123,182) | (1,807) | (134,285) |
Share-based compensation - tax withholdings settled in cash | (3,551) | (5,567) | (3,705) |
Dividends | (32,284) | (19,897) | (21,003) |
Cash flow from/(used in) financing activities | 253,101 | (108,871) | (203,437) |
Investing Activities | |||
Capital and office expenditures | (271,131) | (248,990) | (454,521) |
Bruin acquisition | (420,249) | ||
Dunn County acquisition | (305,076) | ||
Property and land acquisitions | (9,846) | (7,491) | (18,409) |
Property divestments | 108,193 | 4,456 | 7,210 |
Other expense/(income) | 4,593 | ||
Cash flow from/(used in) investing activities | (893,516) | (252,025) | (465,720) |
Effect of exchange rate changes on cash and cash equivalents | 6,979 | (1,786) | (295) |
Change in cash and cash equivalents | (28,597) | (26,798) | (149,684) |
Cash and cash equivalents, beginning of year | 89,945 | 116,743 | 266,427 |
Cash and cash equivalents, end of year | $ 61,348 | $ 89,945 | $ 116,743 |
REPORTING ENTITY
REPORTING ENTITY | 12 Months Ended |
Dec. 31, 2021 | |
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 United States (“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’ corporate offices are located in Calgary, Alberta, Canada and Denver, Colorado, United States. |
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2021 | |
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 and Functional Currency In the fourth quarter of 2021, the Company elected to change its reporting currency from Canadian dollars to U.S. dollars since the majority of its crude oil and natural gas properties are located in the U.S., and to facilitate a more direct comparison to other U.S. exploration and development companies. The change in reporting currency is a voluntary change which is accounted for retrospectively. All prior periods have been restated to U.S. dollars using the procedures outlined below: ● Consolidated Statements of Income/(Loss) and Consolidated Statements of Cash Flows have been translated into U.S. dollars using average foreign exchange rates for the relevant period. ● Assets and liabilities in the Consolidated Balance Sheets have been translated into U.S. dollars at the closing foreign exchange rates on the respective balance sheet dates. ● The shareholders’ equity section of the Consolidated Balance Sheets has been translated into U.S. dollars using historical foreign exchange rates. ● Earnings per share disclosures have also been restated to U.S. dollars to reflect the change in reporting currency. Dividends are disclosed in Canadian dollars with the U.S. dollar equivalent disclosed in parentheses as dividends were declared in Canadian dollars. The functional currency of the parent entity has been and continues to be Canadian dollars and the functional currency of the U.S. subsidiaries continues to be U.S. dollars. All references to $ or US$ are to U.S. dollars and references to CDN$ are to Canadian dollars. All financial information presented in U.S. and 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 those that relate to: 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. Inflation and discount rates impacting various items within the Company’s financial statements are also subject to management estimation. When estimating the present value of future cash flows, the discount rate implicitly considers the potential impacts, if any, due to climate change factors. Enerplus uses the most current information available and exercises judgment in making 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. 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, with limited exceptions, at the acquisition date. b) Revenue 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. 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. 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, in which case the Company would be the principal and the revenue is recognized on a gross basis. Any associated fees are recorded as an expense. 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. All references to crude oil and natural gas revenue or production in the Consolidated Financial Statements are net of royalties. c) Transportation Enerplus generally sells crude oil and natural gas under two types of agreements which are common in 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). 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 or any other factors, as it is prescribed under U.S. GAAP. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain, and as such, it is difficult to determine the impact on estimated future net cash flows of such a transition. 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 certain circumstances, where the carrying value of the full cost centre exceeds the ceiling test limitation, the Company may seek a temporary waiver from the SEC to exclude certain amounts from the full cost ceiling limitation. The Company must demonstrate that the fair value of the excluded properties clearly exceeds the carrying value. Under full cost accounting rules, divestments 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 is recognized. e) Other Capital Assets Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, and computer equipment. 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) Other Long-term Assets Other Long-term Assets include Company-owned line fill in third party pipelines and long-term receivables. Line fill is recorded at lower of cost and net realizable value. g) Cash and Cash Equivalents Cash and cash equivalents include cash and highly liquid investments with maturities of less than 90 days. h) 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. 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. i) Asset Retirement Obligations Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning, reclamation, 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). j) Leases Enerplus determines if an arrangement is an operating or finance lease, as defined under U.S. GAAP, 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. These leases are included in right-of-use (“ROU”) assets and lease liabilities 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 such leases. Lease liabilities are recognized at the lease commencement date based on the present value of remaining lease payments over the lease term, taking into consideration conditions such as incentives and termination penalties, as appropriate. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for payments made prior to lease commencement or initial direct costs, if any. When calculating the present value, Enerplus uses the rate implicit in the lease, or uses its incremental borrowing rate for a similar term and risk profile based on the information available at the commencement date. 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 can contain both lease and non-lease components, which are accounted for separately. For certain equipment leases, a portfolio approach is applied to account for the ROU assets and liabilities. k) 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. l) 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 and cash equivalents, accounts receivable, accounts payable, bank credit facilities, and term loan reported on the Consolidated Balance Sheets approximates their fair value. The fair value of the senior notes are considered a level 2 fair value measurement and details are disclosed in Note 17. The Company uses the current expected credit loss model in valuing 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 that is held in the parent entity as a hedge of its net investment in operations for which the U.S. dollar is the functional currency. As a non-derivative financial instrument, it 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 the fair value of the net investment in the U.S. subsidiary. If effective, the unrealized foreign exchange gains and losses arising from the translation of the U.S. denominated debt are recorded in Other Comprehensive Income/(Loss) (“OCI”), net of tax, to the extent the net investment in the U.S. subsidiary supports the U.S. denominated debt. Prior to January 1, 2020, the Company did not apply hedge accounting to the net investment in operations with a U.S. dollar functional currency, and unrealized gains and losses were recognized in net income/loss at the end of each 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, 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. m) Foreign Currency i. Foreign currency transactions Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars in Canada and U.S. dollars in the U.S) 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 currency translation For financial statement presentation, assets and liabilities of Enerplus’ Canadian operations, which have a Canadian dollar functional currency, are translated into U.S. 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. n) 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 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. o) 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 outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price. p) 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. q) Government Assistance In 2020, the Alberta, Saskatchewan, and British Columbia provincial governments created programs and provided funding to support the clean-up of inactive or abandoned crude oil and natural gas wells. Enerplus applied for and benefited from these programs in 2021. The programs provide funding directly to oil field service contractors engaged by companies to perform abandonment, remediation, and reclamation work. As work is completed, the contractors submit invoices to the provincial government for reimbursement for the pre-approved funding amounts. Enerplus recognizes the assistance as the abandonment, remediation, and reclamation work is completed by the contractor. The benefit of the funding received by the contractor is reflected as a reduction of asset retirement obligation and recorded as other income in the Consolidated Statements of Income/(Loss). r) 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, 2021 : ● ASU 2021-05 – Leases (Topic 842): Lessors – Certain leases with Variable Lease Payments. The adoption of this standard had no impact on the financial statements. |
ACQUISITIONS & DIVESTMENT
ACQUISITIONS & DIVESTMENT | 12 Months Ended |
Dec. 31, 2021 | |
ACQUISITIONS & DIVESTMENT | |
ACQUISITIONS & DIVESTMENT | 3) ACQUISITIONS & DIVESTMENT a) Bruin E&P HoldCo, LLC Acquisition On January 25, 2021 , Enerplus Resources (USA) Corporation, an indirect wholly-owned subsidiary of Enerplus entered into a purchase agreement to acquire all of the equity interests of Bruin E&P HoldCo, LLC (“Bruin”) for total cash consideration of $465.0 million, subject to certain purchase price adjustments. Bruin was a private company that held crude oil and natural gas interests in certain properties located in the Williston Basin , North Dakota. The effective date of the acquisition was January 1, 2021 and the acquisition was completed on March 10, 2021. The acquisition was funded through a new three-year $400 million term loan provided by a syndicate of financial institutions as well as a portion of the proceeds raised through a bought deal offering of common shares of the Company, which was completed on February 3, 2021. A total of 33,062,500 common shares were issued at a price of CDN $4.00 per common share for gross proceeds of approximately $103.4 million (net proceeds of $99.5 million). The acquisition contributed $319.2 million to crude oil and natural gas revenues and $111.4 million to consolidated earnings before tax from the acquisition date to December 31, 2021. Transaction costs of $5.0 million were incurred for the year ended December 31, 2021. If the transaction had occurred on January 1, 2021, the combined entity’s unaudited pro-forma crude oil and natural gas revenues for the year ended December 31, 2021 would be $1,538.7 million (2020 – $775.2 million). For the year ended December 31, 2021 the combined entity would have had net income of $197.8 million (2020 – net loss of $1,332.7 million). The unaudited pro-forma information may not be indicative of the results that actually would have occurred if the events reflected therein had been in effect on the dates indicated or of the results that may be obtained in the future. No pro forma adjustments were made to reflect operating synergies that resulted from the transaction. Purchase Price Equation The transaction was accounted for as an acquisition of a business. The purchase price is measured as the fair value of the assets transferred, equity instruments issued, and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The purchase price equation was determined following the closing date, during which time the value of the net assets and liabilities acquired was revised as indicated in the agreement and is reflected in the purchase price equation as follows: ($ thousands) At March 10, 2021 Consideration Purchase Price $ 465,000 Purchase price adjustments (44,751) Total consideration $ 420,249 Fair value of identifiable assets and liabilities of Bruin Other current assets 1,667 Property, plant and equipment 542,190 Right of use assets 1,892 Accounts payable (25,257) Asset retirement obligation (21,964) Commodity contract liabilities (76,387) Lease liabilities (1,892) Total identifiable net assets $ 420,249 The estimated fair value of the acquired property, plant and equipment was based on the after-tax cash-flows and associated proved and probable reserves discounted using an estimated weighted average cost of capital. The determination of proved and probable reserves involves numerous estimates and assumptions (see Note 2). b) Dunn County Acquisition On April 8, 2021, the Company announced it had entered into a purchase agreement to acquire assets in Dunn County, North Dakota from Hess Bakken Investments II, LLC for total cash consideration of $312.0 million, subject to customary purchase price adjustments. The acquisition was funded using the Company’s existing cash balance with the remaining portion funded through borrowing on its bank credit facility. The effective date of the acquisition was March 1, 2021 and the acquisition closed on April 30, 2021. The acquisition was recorded as an asset acquisition as of the close date of April 30, 2021 with the results of operations from these assets reflected in the Consolidated Financial Statements thereafter. After purchase price adjustments, the purchase consideration including capitalized transaction costs was $306.8 million. c) Sleeping Giant and Russian Creek Divestment On August 30, 2021, the Company announced it had entered into a definitive agreement to sell its interests in the Sleeping Giant field in Montana and the Russian Creek area in North Dakota in the Williston Basin, for total cash consideration of $115.0 million, subject to customary purchase price adjustments. After purchase price adjustments and transaction costs, adjusted proceeds were $107.8 million. In addition, Enerplus may receive up to $5.0 million in contingent payments if the WTI oil price averages over $65 per barrel in 2022 and over $60 per barrel in 2023, with amounts payable on January 31, 2023 and January 31, 2024, respectively. The disposition closed on November 2, 2021. The fair value of the contingent payments have been recorded as part of Other Long-Term assets. |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 12 Months Ended |
Dec. 31, 2021 | |
ACCOUNTS RECEIVABLE | |
ACCOUNTS RECEIVABLE | 4) ACCOUNTS RECEIVABLE ($ thousands) December 31, 2021 December 31, 2020 Accrued revenue $ 208,160 $ 73,201 Accounts receivable – trade 23,697 13,208 Allowance for doubtful accounts (3,869) (2,813) Total accounts receivable, net of allowance for doubtful accounts $ 227,988 $ 83,596 |
PROPERTY, PLANT AND EQUIPMENT (
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | 12 Months Ended |
Dec. 31, 2021 | |
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | |
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | 5) PROPERTY, PLANT AND EQUIPMENT (“PP&E”) Accumulated Depletion, At December 31, 2021 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 13,075,987 $ (11,822,482) $ 1,253,505 Other capital assets 103,355 (89,468) 13,887 Total PP&E $ 13,179,342 $ (11,911,950) $ 1,267,392 Accumulated Depletion, At December 31, 2020 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 11,966,258 $ (11,513,956) $ 452,302 Other capital assets 96,373 (84,874) 11,499 Total PP&E $ 12,062,631 $ (11,598,830) $ 463,801 (1) All of the Company’s unproved properties are included in the full cost pool. Acquisitions: For the years ended December 31, 2021 and 2020, Enerplus acquired property and land totaling $857.1 million and $7.5 million, respectively. Refer to Note 3 for details regarding the Bruin and Dunn County acquisitions during 2021. Divestments: For the years ended December 31, 2021 and 2020, Enerplus disposed of properties for proceeds of $112.7 million and $4.5 million, respectively. Refer to Note 3 for details regarding the divestment of the Sleeping Giant and Russian Creek assets during 2021. |
IMPAIRMENT
IMPAIRMENT | 12 Months Ended |
Dec. 31, 2021 | |
IMPAIRMENT | |
IMPAIRMENT | 6) IMPAIRMENT a) Impairment of PP&E ($ thousands) 2021 2020 2019 Crude oil and natural gas properties: U.S. cost centre $ — $ 650,780 $ — Canada cost centre 3,420 100,943 — Total impairment expense $ 3,420 $ 751,723 $ — For the year ended December 31, 2021, Enerplus recorded asset impairment of $3.4 million (2020 – $751.7 million; 2019 – nil). The primary factors that affect ceiling values include first-day-of-the-month commodity prices, reserves, capital expenditure levels and timing, acquisition and divestment activity, and production levels. At March 31, 2021, Enerplus’ crude oil and natural gas properties in the U.S. cost centre exceeded the ceiling test limitation by approximately $265 million, primarily due to the difference in the ceiling value using SEC prices for the assets acquired in the Bruin acquisition compared to the carrying value, which more closely represented fair market value, based on forward prices. Given the short duration between closing the acquisition and the ceiling test calculation at March 31, 2021, Enerplus requested and received a temporary exemption from the SEC to exclude the properties acquired from Bruin in the full cost ceiling test for the duration of 2021. The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling test at December 31, WTI Crude Oil Edm Light Crude U.S. Henry Hub Gas Exchange Rate Period $/bbl CDN$/bbl $/Mcf CDN$/US$ 2021 $ 66.55 $ 78.15 $ 3.64 0.80 2020 39.54 45.56 2.00 0.75 2019 55.85 66.73 2.58 0.75 b) Impairment of Goodwill At December 31, 2021 and 2020, there was no goodwill remaining on the Company’s Consolidated Balance Sheets. During the year ended December 31, 2020, Enerplus recorded goodwill impairment of $149.2 million relating to its U.S. reporting unit. This was due to lower commodity prices in 2020, which resulted in a reduction in the fair value of the U.S. reporting unit. For the year ended December 31, 2019, Enerplus recorded goodwill impairment of $347.3 million relating to the Canadian reporting unit as a result of the cumulative impact of Canadian asset divestments, the shut-in of uneconomic natural gas production in Canada and lower forecasted commodity prices. |
OTHER LONG-TERM ASSETS
OTHER LONG-TERM ASSETS | 12 Months Ended |
Dec. 31, 2021 | |
OTHER LONG-TERM ASSETS | |
OTHER LONG-TERM ASSETS | 7) OTHER LONG-TERM ASSETS Included in Other Long-term Assets is Company-owned line fill in third party pipelines, amounting to $5.3 million (December 31, 2020 – $3.8 million) and a long-term receivable amounting to $4.5 million (December 31, 2020 – nil) relating to the fair value of contingent consideration associated with the Sleeping Giant and Russian Creek divestment. The fair value is adjusted at each reporting period. See Note 3 for further details. |
ACCOUNTS PAYABLE
ACCOUNTS PAYABLE | 12 Months Ended |
Dec. 31, 2021 | |
ACCOUNTS PAYABLE | |
ACCOUNTS PAYABLE | 8) ACCOUNTS PAYABLE ($ thousands) December 31, 2021 December 31, 2020 Accrued payables $ 106,222 $ 84,286 Accounts payable – trade 260,786 113,609 Total accounts payable $ 367,008 $ 197,895 |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2021 | |
DEBT | |
DEBT | 9) DEBT ($ thousands) December 31, 2021 December 31, 2020 Current: Senior notes $ 100,600 $ 81,600 Long-term: Term loan 397,971 — Senior notes 203,200 303,800 Total debt $ 701,771 $ 385,400 Term Loan Upon closing the Bruin acquisition on March 10, 2021 , Enerplus entered into a three-year senior unsecured $400 million term loan. The drawn fees align with those of Enerplus’ bank credit facility, which range between 125 and 315 basis points over bankers’ acceptance or LIBOR rates. The term loan includes financial and other covenants consistent with Enerplus’ bank credit facility and ranks equally with the bank credit facility and outstanding senior notes. Debt issuance costs of $2.8 million have been netted against the term loan and are being amortized over the three-year term. Subsequent to December 31, 2021, the Company converted its $400 million term loan into a revolving credit facility with no other amendments. Bank Credit Facility During 2021, Enerplus increased and extended its senior, unsecured, covenant-based bank credit facility to $900 million from $600 million with a maturity of October 31, 2025 . Debt issuance costs of $1.8 million have been netted against the bank credit facility and are being amortized over the four and a half year term. As part of the extension, the Company transitioned the facility to a sustainability-linked credit facility incorporating environmental, social and governance (“ESG”)-linked incentive pricing terms which reduce or increase the borrowing costs by up to 5 basis points as Enerplus’ sustainability performance targets (“SPT”) are exceeded or missed. The SPTs are based on the following ESG goals of the Company: ● GHG Emissions : continuous progress toward Enerplus’ stated goal of a 50% reduction in corporate Scope 1 and 2 greenhouse gas emissions intensity by 2030, using 2019 as a baseline and measurement based on Enerplus’ annual internal targets; ● Water Management : achieve a 50% reduction in freshwater usage in corporate well completions by 2025 or earlier compared to 2019, with progress to be measured on an annual basis over the life of the credit facility; and ● Health & Safety : achieve and maintain a 25% reduction in the Company’s Lost Time Injury Frequency, based on a trailing 3-year average, relative to a 2019 baseline. For the year ended December 31, 2021, total amortization of debt issuance costs amounted to $1.1 million (December 31, 2020 – nil). Senior Notes During 2021, Enerplus made its final $22.0 million principal repayment on its 2009 senior notes, and its second $59.6 million principal repayment on its 2012 senior notes . The terms and rates of the Company’s outstanding senior notes are detailed below: Original Remaining Coupon Principal Principal Issue Date Interest Payment Dates Principal Repayment Rate ($ thousands) ($ thousands) September 3, 2014 March 3 and Sept 3 5 equal annual installments beginning September 3, 2022 3.79% $200,000 $105,000 May 15, 2012 May 15 and Nov 15 Bullet payment on May 15, 2022 4.40% $20,000 $20,000 May 15, 2012 May 15 and Nov 15 3 equal annual installments beginning May 15, 2022 4.40% $355,000 $178,800 Total carrying value at December 31, 2021 $ 303,800 |
ASSET RETIREMENT OBLIGATION ("A
ASSET RETIREMENT OBLIGATION ("ARO") | 12 Months Ended |
Dec. 31, 2021 | |
ASSET RETIREMENT OBLIGATION ("ARO") | |
ASSET RETIREMENT OBLIGATION ("ARO") | 10) ASSET RETIREMENT OBLIGATION (“ARO”) ($ thousands) December 31, 2021 December 31, 2020 Balance, beginning of year $ 102,325 $ 106,274 Change in estimates 26,586 3,020 Property acquisition and development activity 1,304 1,615 Bruin acquisition (Note 3) 21,964 — Dunn County acquisition (Note 3) 5,880 — Divestments (Note 3) (13,525) (758) Settlements (12,951) (13,275) Government assistance (4,594) — Accretion expense 5,825 5,449 Balance, end of year $ 132,814 $ 102,325 Enerplus has estimated the present value of its asset retirement obligation to be $132.8 million at December 31, 2021 based on a total undiscounted, uninflated liability of $303.3 million (December 31, 2020 – $102.3 million and $273.8 million, respectively). Enerplus’ asset retirement obligation expenditures are mainly expected to be incurred between 2036 and 2051. In 2021, Enerplus benefited from provincial government assistance to support the clean-up of inactive or abandoned crude oil and natural gas wells. These programs provide funding directly to oil field service contractors engaged by Enerplus to perform abandonment, remediation, and reclamation work. The funding received by the contractor is reflected as a reduction to ARO. For the year ended December 31, 2021, Enerplus benefited from $4.6 million (2020 – nil) in government assistance, which has been recorded as part of Other income in the Consolidated Statements of Income/(Loss). |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2021 | |
LEASES | |
LEASES | 11) LEASES The Company has entered into various lease contracts related to office space, drilling rig commitments, vehicles and other equipment. Leases are entered into and exited in coordination with specific business requirements which include the assessment of the appropriate term for the related leased assets. Short-term leases with a lease term of 12 months or less are not recorded on the Consolidated Balance Sheets. Such items are charged to operating expenses or general and administrative expenses, as appropriate, in the Consolidated Statements of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with U.S. GAAP. ($ thousands) December 31, 2021 December 31, 2020 Assets Operating right-of-use assets $ 26,118 $ 25,818 Liabilities Current operating lease liabilities $ 10,618 $ 10,523 Non-current operating lease liabilities 18,265 18,425 Total lease liabilities $ 28,883 $ 28,948 Weighted average remaining lease term (years) Operating leases 3.3 3.9 Weighted average discount rate Operating leases 3.4% 4.2% The Company’s lease contract expenditures/(income) for the years ended December 31, 2021 and 2020 are as follows: ($ thousands) 2021 2020 Operating lease cost $ 11,378 $ 12,368 Variable lease cost 633 1,308 Short-term lease cost 3,469 7,093 Sublease income (1,083) (1,101) Total $ 14,397 $ 19,668 Variable lease payments are determined through analysis of day rate fees under applicable rig contracts. The amounts in the table above are recorded as part of general and administrative or operating expenses or property, plant, and equipment depending on the nature of the contract to which they relate. Although Enerplus has various leases containing extensions and/or termination options, none were determined to be reasonably certain to be exercised. As a result, none of these options are recognized as part of the ROU assets or lease liabilities at December 31, 2021 or 2020. Maturities of lease liabilities, all of which are classified as operating leases at December 31, 2021, are as follows: ($ thousands) Operating Leases 2022 $ 11,419 2023 10,211 2024 5,870 2025 987 2026 966 After 2026 1,153 Total lease payments $ 30,606 Less imputed interest (1,723) Total discounted lease payments $ 28,883 Current portion of lease liabilities $ 10,618 Non-current portion of lease liabilities $ 18,265 Supplemental information related to leases is as follows: ($ thousands) 2021 2020 Cash amounts paid to settle lease liabilities: Operating cash flow used for operating leases $ 11,571 $ 12,038 Right-of-use assets obtained/(terminated): Operating leases $ 10,030 $ (1,306) |
CRUDE OIL AND NATURAL GAS SALES
CRUDE OIL AND NATURAL GAS SALES | 12 Months Ended |
Dec. 31, 2021 | |
CRUDE OIL AND NATURAL GAS SALES | |
CRUDE OIL AND NATURAL GAS SALES | 12) CRUDE OIL AND NATURAL GAS SALES Crude oil and natural gas revenue by country and by product for the years ended December 31, 2021 and 2020 are as follows: 2021 Natural Natural gas ($ thousands) Total revenue Crude oil (1) gas (1) liquids (1) Other (2) United States $ 1,355,255 $ 1,055,748 $ 219,552 $ 79,930 $ 25 Canada 127,320 111,070 11,127 4,348 775 Total $ 1,482,575 $ 1,166,818 $ 230,679 $ 84,278 $ 800 2020 Natural Natural gas ($ thousands) Total revenue Crude oil (1) gas (1) liquids (1) Other (2) United States $ 480,822 $ 380,074 $ 92,453 $ 8,182 $ 113 Canada 72,917 59,642 9,239 2,591 1,445 Total $ 553,739 $ 439,716 $ 101,692 $ 10,773 $ 1,558 (1) 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. (2) Includes third party processing income. |
GENERAL AND ADMINISTRATIVE EXPE
GENERAL AND ADMINISTRATIVE EXPENSE | 12 Months Ended |
Dec. 31, 2021 | |
GENERAL AND ADMINISTRATIVE EXPENSE | |
GENERAL AND ADMINISTRATIVE EXPENSE | 13) GENERAL AND ADMINISTRATIVE EXPENSE ($ thousands) 2021 2020 2019 General and administrative expense (1) $ 38,013 $ 33,347 $ 37,360 Share-based compensation expense 18,794 9,750 17,560 General and administrative expense $ 56,807 $ 43,097 $ 54,920 (1) Includes non-cash lease credit of $365 in 2021, $212 in 2020, and an expense of $542 in 2019. |
FOREIGN EXCHANGE
FOREIGN EXCHANGE | 12 Months Ended |
Dec. 31, 2021 | |
FOREIGN EXCHANGE | |
FOREIGN EXCHANGE | 14) FOREIGN EXCHANGE ($ thousands) 2021 2020 2019 Realized: Foreign exchange (gain)/loss $ 3,477 $ 771 $ (1,346) Foreign exchange (gain)/loss on U.S. dollar cash held in parent company (2,330) (902) 6,825 Unrealized: Foreign exchange (gain)/loss on U.S. dollar debt and working capital in parent company (8,055) 1,363 (21,899) Foreign exchange (gain)/loss $ (6,908) $ 1,232 $ (16,420) |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2021 | |
INCOME TAXES | |
INCOME TAXES | 15) INCOME TAXES Enerplus’ provision for income tax is as follows: ($ thousands) 2021 2020 2019 Current tax United States $ 2,700 $ (10,716) $ (14,774) Canada (11) — (10,472) Current tax expense/(recovery) 2,689 (10,716) (25,246) Deferred tax United States $ 148,920 $ (167,835) $ 53,020 Canada (50,165) (20,425) 8,630 Deferred tax expense/(recovery) 98,755 (188,260) 61,650 Income tax expense/(recovery) $ 101,444 $ (198,976) $ 36,404 The following provides a reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes: ($ thousands) 2021 2020 2019 Income/(loss) before taxes United States $ 544,464 $ (877,406) $ 170,346 Canada (208,579) (14,921) (338,342) Total income/(loss) before taxes 335,885 (892,327) (167,996) Canadian statutory rate 24.00% 24.00% 26.50% Expected income tax expense/(recovery) $ 80,612 $ (214,158) $ (44,519) Impact on taxes resulting from: Foreign and statutory rate differences $ 19,297 $ (27,918) $ 21,329 Share-based compensation 1,878 1,671 (4,068) Non-taxable capital (gains)/losses (105) 14,341 3,007 Change in valuation allowance (560) (25,918) (16,598) Amounts in respect of prior periods 322 5,845 (14,669) Non-deductible goodwill impairment and other expenses — 47,161 91,922 Income tax expense/(recovery) $ 101,444 $ (198,976) $ 36,404 In 2020, the Alberta corporate income tax rate change resulted in a decrease to the Canadian statutory rate by 2.5%. The deferred income tax asset consists of the following: At December 31 2021 2020 Deferred income tax assets Property, plant and equipment $ 125,312 $ 139,724 Tax loss carry-forwards and other credits 225,463 303,288 Capital loss carry-forwards and other capital items 107,681 111,497 Asset retirement obligation 32,896 24,985 Derivative financial instruments 28,907 2,926 Other assets 19,270 6,668 Deferred income tax assets before valuation allowance 539,529 589,088 Valuation allowance (112,847) (112,074) Deferred income tax assets, net 426,682 477,014 Deferred income tax liabilities Property, plant and equipment $ (45,824) $ — Total deferred income tax liabilities (45,824) — Total deferred income tax asset $ 380,858 $ 477,014 Loss carry-forwards available for tax reporting purposes: At December 31 ($ thousands) 2021 Expiration Date United States Federal Net operating losses – prior to 2018 $ 476,000 2032-2037 Net operating losses – 2018 and thereafter 256,000 Indefinite Canada Federal Capital losses $ 848,000 Indefinite Non-capital losses 137,000 2031-2041 Changes in the balance of Enerplus’ unrecognized tax benefits are as follows: ($ thousands) 2021 2020 2019 Balance, beginning of year $ 15,485 $ — $ 9,753 Increase – tax positions in prior periods — 15,485 — Settlements — — (9,753) Balance, end of year $ 15,485 $ 15,485 $ — If recognized, all of Enerplus’ unrecognized tax benefits at December 31, 2021 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 United States – Federal 2018-2021 Canada – Federal 2017-2021 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, 2021 | |
SHAREHOLDERS' EQUITY | |
SHAREHOLDERS' EQUITY | 16) SHAREHOLDERS’ EQUITY a) Share Capital 2021 2020 2019 (thousands) Shares Amount Shares Amount Shares Amount Balance, beginning of year 222,548 $ 3,113,829 221,744 $ 3,106,875 239,411 $ 3,294,496 Issued/(Purchased) for cash: Issue of shares (net of tax effected issue costs) 33,062 99,516 — — — — Purchase of common shares under Normal Course Issuer Bid (12,898) (128,686) (340) (3,582) (18,231) (190,917) Non-cash: Share-based compensation – treasury settled (1) 1,140 9,402 1,160 10,694 564 3,296 Cancellation of predecessor shares — — (16) (158) — — Balance, end of year 243,852 $ 3,094,061 222,548 $ 3,113,829 221,744 $ 3,106,875 (1) The amount of shares issued on LTI settlement is net of employee withholding taxes. The Company is authorized to issue an unlimited number of common shares without par value. For the year ended December 31, 2021, Enerplus declared dividends of CDN$0.15 ($0.12) per weighted average common share totaling $30.5 million (2020 – CDN$0.12 ($0.09) per share and $20.0 million; December 31, 2019 – CDN$0.12 ($0.09) per share and $20.9 million). Subsequent to December 31, 2021, the Board of Directors approved a first quarter dividend payment of $0.033 per share to be paid in March 2022. For the year ended December 31, 2021, Enerplus issued 33,062,500 common shares at a price of CDN$4.00 per common share for gross proceeds of $103.4 million (net $99.5 million, after $5.1 million in issue costs, net of $1.2 million in tax) pursuant to a bought deal prospectus offering under its base shelf prospectus. On June 23, 2021, the Company filed a short form base shelf prospectus (the “Shelf Prospectus”) with securities regulatory authorities in each of the provinces and territories of Canada and a Registration Statement with the U.S. Securities Exchange Commission. The Shelf Prospectus allows Enerplus to offer and issue up to an aggregate amount of CDN$2.0 billion common shares, preferred shares, warrants, subscription receipts and units by way of one or more prospectus supplements during the 25-month period that the Shelf Prospectus remains valid. On August 12, 2021 Enerplus received approval from the Toronto Stock Exchange (“TSX”) to commence a Normal Course Issuer Bid (“NCIB”) to purchase up to 10% of the public float (within the meaning under TSX rules) during a 12-month period. As a result, 12,897,721 common shares were repurchased and cancelled under the NCIB at an average price of $9.55 (CDN$12.06) per share, for total consideration of $123.2 million. Of the amount paid, $128.7 million was charged to share capital and $5.5 million was credited to accumulated deficit. At December 31, 2021, 12,668,090 common shares are available for repurchase under the current NCIB. For the year ended December 31, 2020, the Company repurchased 340,434 common shares under the former NCIB at an average price of $5.63 (CDN$7.44) per share, for total consideration of $1.9 million. Of the amount paid, $3.6 million was charged to share capital and $1.7 For the year ended December 31, 2019, the Company repurchased 18,231,401 common shares under the former NCIB at an average price of $7.36 (CDN$9.80) per share, for total consideration of $134.3 million. Of the amount paid, $190.9 million was charged to share capital and $56.6 million was credited to accumulated deficit. Subsequent to December 31, 2021 and up to and including February 23, 2022, the Company repurchased 2,257,400 common shares under the current NCIB at an average price of $11.58 (CDN$14.67) per share, for total consideration of $26.1 million. b) Share-based Compensation The following table summarizes Enerplus' share-based compensation expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss): ($ thousands) 2021 2020 2019 Cash: Long-term incentive plans (recovery)/expense $ 6,875 $ (934) $ 512 Non-Cash: Long-term incentive plans expense 13,789 9,720 16,814 Equity swap (gain)/loss (1,870) 964 234 Share-based compensation expense $ 18,794 $ 9,750 $ 17,560 LTI Plans The following tables summarize the PSU, RSU and DSU activity for the year ended December 31, 2021: For the year ended December 31, 2021 Cash-settled LTI Plans Equity-settled LTI Plans Total (thousands of units) DSU PSU (1) RSU Balance, beginning of year 555 2,552 1,825 4,932 Granted 269 2,158 2,207 4,634 Vested (235) (728) (890) (1,853) Forfeited — — (77) (77) Balance, end of year 589 3,982 3,065 7,636 (1) Based on underlying awards before any effect of the performance multiplier. Cash-settled LTI Plans For the year ended December 31, 2021, the Company recorded a cash share-based compensation expense of $6.9 million (2020 – recovery of $0.9 million; 2019 – expense of $0.5 million). At December 31, 2021, a liability of $6.3 million (December 31, 2020 – $1.7 million) with respect to the Director DSU Plan was recorded as part of Accounts Payable on the Consolidated Balance Sheets. Equity-settled LTI Plans The following table summarizes the cumulative share-based compensation expense recognized to date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms. At December 31, 2021 ($ thousands, except for years) PSU (1) RSU Total Cumulative recognized share-based compensation expense $ 12,791 $ 10,554 $ 23,345 Unrecognized share-based compensation expense 9,050 4,303 13,353 Fair value $ 21,841 $ 14,857 $ 36,698 Weighted-average remaining contractual term (years) 1.9 1.5 (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, 2021 cash withholding taxes of $3.6 million were paid (2020 – $5.6 million; 2019 – $3.7 million). c) Basic and Diluted Net Income/(Loss) Per Share Net income/(loss) per share has been determined as follows: (thousands, except per share amounts) 2021 2020 2019 Net income/(loss) $ 234,441 $ (693,351) $ (204,400) Weighted average shares outstanding – Basic 251,909 222,503 231,334 Dilutive impact of share-based compensation (1) 7,942 — — Weighted average shares outstanding – Diluted 259,851 222,503 231,334 Net income/(loss) per share Basic $ 0.93 $ (3.12) $ (0.88) Diluted $ 0.90 $ (3.12) $ (0.88) (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, 2021 | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | 17) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT a) Fair Value Measurements At December 31, 2021, the carrying value of cash and cash equivalents, accounts receivable, and accounts payable approximated their fair value due to the short-term nature of these instruments. The fair values of the bank credit facility and term loan approximate their carrying values as they bear interest at floating rates and the credit spread approximates current market rates. At December 31, 2021, the senior notes had a carrying value of $303.8 million and a fair value of $304.1 million (December 31, 2020 – $385.4 million and $388.2 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. The fair value of derivative contracts, senior notes, term loan, and credit facility are considered level 2 fair value measurements. 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 are recorded at amounts that represent the fair values of these instruments. At December 31, 2021, Enerplus has equity, commodity, and contingent consideration contracts. See Note 7 regarding the contingent consideration contract. The following tables summarize the change in fair value associated with equity and commodity contracts for the respective years: Income Gain/(Loss) 2021 2020 2019 Statement Presentation Equity Swaps $ 1,870 $ (964) $ (234) G&A expense Commodity Contracts: Oil (111,655) (19,891) (51,479) Commodity derivative Gas 249 2,781 (8,037) instruments Total Unrealized Gain/(Loss) $ (109,536) $ (18,074) $ (59,750) The following table summarizes the effect of Enerplus’ commodity contracts on the Consolidated Statements of Income/(Loss): ($ thousands) 2021 2020 2019 Unrealized change in fair value gain/(loss) $ (111,406) $ (17,110) $ (59,516) Net realized cash gain/(loss) (163,026) 92,852 11,586 Commodity contracts gain/(loss) $ (274,432) $ 75,742 $ (47,930) The following table summarizes the presentation of fair values on the Consolidated Balance Sheets: December 31, 2021 December 31, 2020 Assets Liabilities Assets Liabilities ($ thousands) Current Current Long-term Current Current Equity Swaps $ — 969 $ — $ — $ 2,839 Commodity Contracts: Oil 1,771 141,364 7,098 — 12,297 Gas 3,897 867 — 2,790 — Total $ 5,668 143,200 $ 7,098 $ 2,790 $ 15,136 The fair value of commodity contracts and the equity swaps is estimated based on commodity and option pricing models that incorporate various factors including forecasted commodity prices, volatility and the credit risk of the entities party to the contract. Changes and variability 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. On March 10, 2021, the outstanding crude oil commodity contracts acquired with the Bruin acquisition were recorded at fair value. Realized and unrealized gains and losses on the acquired contracts are recognized in the Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the closing date of the Bruin acquisition. At December 31, 2021, the fair value of Enerplus’ commodity contracts totaled a net liability of $143.7 million. Of this total net liability, $40.2 million related to Bruin contracts, with $22.8 million remaining from the original $76.4 million liability acquired from Bruin. c) Risk Management In the normal course of operations, Enerplus is exposed to various market risks, including commodity prices, foreign exchange, interest rates, equity prices, credit risk, liquidity risk, and the risks associated with environmental/climate change risk, social and governance regulation, and compliance. i) Market Risk Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk. Commodity Price Risk: Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes. The following tables summarize Enerplus’ price risk management positions at February 24, 2022: Crude Oil Instruments: Instrument Type (1)(2) bbls/day US$/bbl Jan 1, 2022 – Jun 30, 2022 WTI Purchased Put 12,500 75.00 WTI Sold Put 12,500 58.00 WTI Sold Call 12,500 87.63 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 WTI Sold Swap (3) 3,828 42.35 WTI Purchased Swap 3,828 66.52 Jan 1, 2023 – Jun 30, 2023 WTI Purchased Put 10,000 76.50 WTI Sold Put 10,000 60.00 WTI Sold Call 10,000 107.38 Jan 1, 2023 – Oct 31, 2023 WTI Sold Swap (3) 250 42.10 WTI Purchased Swap 250 64.85 WTI Purchased Put (3) 2,000 5.00 WTI Sold Call (3) 2,000 75.00 Nov 1, 2023 – Dec 31, 2023 WTI Purchased Put (3) 2,000 5.00 WTI Sold Call (3) 2,000 75.00 (1) The total average deferred premium spent on the Company’s outstanding crude oil contracts is $1.50 /bbl from January 1, 2022 - December 31, 2022 and $1.25 /bbl from January 1, 2023 – June 30, 2023. (2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes. (3) Upon closing of the Bruin Acquisition, Bruin’s outstanding crude oil contracts were recorded at a fair value liability of $76.4 million. At December 31, 2021, the balance was a liability of $22.8 million on the Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the date of closing of the Bruin Acquisition . Natural Gas Instruments: Instrument Type (1) MMcf/day $/Mcf Jan 1, 2022 – Feb 28, 2022 NYMEX Purchased Put 40.00 3.43 NYMEX Sold Call 40.00 6.00 Mar 1, 2022 – Mar 31, 2022 NYMEX Swap 60.00 4.50 NYMEX Purchased Put 40.00 3.43 NYMEX Sold Call 40.00 6.00 Apr 1, 2022 – Oct 31, 2022 NYMEX Swap 40.00 3.40 NYMEX Purchased Put 60.00 3.77 NYMEX Sold Call 60.00 4.50 (1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf. Foreign Exchange Risk & Net Investment Hedge: Enerplus is exposed to foreign exchange risk as it relates to certain activity transacted in Canadian or United States dollars. Enerplus has a U.S. dollar reporting currency, however Enerplus’ parent company has a Canadian functional currency. Activity in the Canadian parent company that is transacted in U.S. dollars will result in realized and unrealized foreign exchange gains and losses that will be recorded on the Consolidated Statements of Income/(Loss). Enerplus may designate certain U.S. dollar denominated debt held in the parent entity as a hedge of its net investment in its U.S. subsidiary, which has a U.S. dollar functional currency. 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 by the cumulative translation gain or loss on the net investment in the foreign subsidiary. At December 31, 2021, $303.8 million of senior notes and the $400 million term loan were designated as net investment hedges (2020 – $385.4 million of senior notes). For the year ended December 31, 2021, Other Comprehensive Income/(Loss) included an unrealized gain of $4.1 million on Enerplus’ U.S denominated senior notes and term loan (2020 – $1.8 million gain and 2019 – nil). Interest Rate Risk: The Company’s senior notes bear interest at fixed rates while the term loan and bank credit facility bear interest at floating rates. At December 31, 2021, approximately 43% of Enerplus’ debt was based on fixed interest rates and 57% on floating interest rates (December 31, 2020 – 100% fixed), with weighted average interest rates of 4.2% and 1.9%, respectively (December 31, 2020 – 4.4%). At December 31, 2021 and 2020, 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 16. Enerplus has entered into various equity swaps maturing in 2022 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 has appropriate policies and procedures in place to manage its credit risk; however, given the volatility in commodity prices, Enerplus is subject to an increased risk of financial loss due to non-performance or insolvency of its counterparties. 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. The Company’s maximum credit exposure consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At December 31, 2021, approximately 83% of Enerplus’ marketing receivables were with companies considered investment grade (December 31, 2020 – 82%). 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, 2021 was $3.9 million (December 31, 2020 – $2.8 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 crude 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, 2021, Enerplus was in full compliance with all covenants under the bank credit facility, term loan and outstanding senior notes. If the Company breaches or anticipates breaching its covenants, the Company may be required to repay, refinance, or renegotiate the terms of the debt. iv) Climate Change Risk The following provides certain considerations as to the impact of climate change on the amounts recorded in the financial statements for the year ended December 31, 2021. The below is not a comprehensive list or analysis of all climate change impacts and risks. In addition, the focus is with respect to the impact of climate change on amounts recognized in the Company’s financial statements as at and for the year ended December 31, 2021. Changing regulation Emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving. The Canadian Securities Administrators have issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters. Impact of climate events and change on amounts recorded in the 2021 financial statements Reserves: The Company engages a third party external reserve engineer to review the reserve report. Enerplus considers the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in its assessment of economic recovery of crude oil and natural gas reserves. The reserve report includes anticipated impacts from emissions related taxes, most notably the reserve report includes estimated carbon tax related to the Company’s operations. Ceiling test: Given the prescriptive nature of the ceiling test and depletion calculations, climate change risk is only considered in the determination of reserves, which will impact the ceiling test and depletion calculations. At December 31, 2021, no impairment was recorded as a result of the ceiling test completed. See Note 6 for further detail. Expenditures on property, plant and equipment: The Company incurs capital expenditures related to emissions reduction initiatives. The extent of spending on projects directly linked to reducing the climate impact of the Company’s operations will vary, however, management anticipates funding future projects through cash flow from operations and bank credit facilities. Current assets and current liabilities: These amounts are short term in nature and management is not aware of any material impacts on these items related to climate change and climate events. The Company did not experience credit losses on its accounts receivable during 2021. Access to Capital : There is risk that access to capital may be restricted to the oil and gas industry. Management plans to continue to monitor and adjust the capital structure where necessary. During 2021, Enerplus transitioned its bank credit facility to a SLL facility with three sustainability performance targets. See Note 9 for further detail. Physical effects of climate events (i.e. fire, flood, extreme weather) on the financial results The Company’s financial results for 2021 were not impacted by a climate event. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2021 | |
COMMITMENTS AND CONTINGENCIES | |
COMMITMENTS AND CONTINGENCIES | 18) COMMITMENTS AND CONTINGENCIES a) Commitments Enerplus has the following minimum annual commitments, excluding operating leases which are recorded in the lease liability (see Note 11): Minimum Annual Commitment Each Year ($ thousands) Total 2022 2023 2024 2025 2026 Thereafter Senior notes (1) $ 303,800 $ 100,600 $ 80,600 $ 80,600 $ 21,000 $ 21,000 $ — Term Loan (1) 400,000 — — 400,000 — — — Transportation commitments 545,636 72,241 72,802 73,201 74,014 74,464 178,914 Processing commitments 6,311 1,202 1,202 1,206 1,202 1,202 297 Service Workover Rigs Commitments 9,828 7,884 1,944 — — — — Total commitments (2)(3) $ 1,265,575 $ 181,927 $ 156,548 $ 555,007 $ 96,216 $ 96,666 $ 179,211 (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) CDN$ commitments have been converted to US$ using the December 31, 2021 foreign exchange rate of 0.79 . 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, 2021 | |
GEOGRAPHICAL INFORMATION | |
GEOGRAPHICAL INFORMATION | 19) GEOGRAPHICAL INFORMATION As at and for the year ended December 31, 2021 ($ thousands) U.S. Canada Total Crude oil and natural gas sales $ 1,355,255 $ 127,320 $ 1,482,575 Depletion, depreciation and accretion 246,949 24,387 271,336 Property, plant and equipment 1,179,070 88,322 1,267,392 Deferred income tax asset 162,582 218,276 380,858 As at and for the year ended December 31, 2020 ($ thousands) U.S. Canada Total Crude oil and natural gas sales $ 480,822 $ 72,917 $ 553,739 Depletion, depreciation and accretion 183,226 34,892 218,118 Property, plant and equipment 375,634 88,167 463,801 Deferred income tax asset 311,502 165,512 477,014 As at and for the year ended December 31, 2019 ($ thousands) U.S. Canada Total Crude oil and natural gas sales $ 812,370 $ 133,524 $ 945,894 Depletion, depreciation and accretion 223,874 45,172 269,046 Property, plant and equipment 1,007,001 199,782 1,206,783 Deferred income tax asset 143,666 143,094 286,760 Goodwill 149,357 — 149,357 Long term income tax receivable 10,664 — 10,664 |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2021 | |
SUPPLEMENTAL CASH FLOW INFORMATION | |
SUPPLEMENTAL CASH FLOW INFORMATION | 20) SUPPLEMENTAL CASH FLOW INFORMATION a) Changes in Non-Cash Operating Working Capital ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Accounts receivable $ (144,413) $ 84,685 $ (255) Other assets (7,583) (3,333) 3,177 Accounts payable - operating 57,353 2,317 (6,119) Non-cash operating activities $ (94,643) $ 83,669 $ (3,197) b) Changes in Non-Cash Financing Working Capital ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Dividends payable $ (1,749) $ 65 $ (96) Non-cash financing activities $ (1,749) $ 65 $ (96) c) Changes in Non-Cash Investing Working Capital ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Accounts payable - investing (1) $ 32,793 $ (28,390) $ 15,724 Non-cash investing activities (1) $ 32,793 $ (28,390) $ 15,724 (1) 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, with the exclusion of the Bruin and Dunn County acquisitions. See Note 3. During the year ended December 31, 2021, Enerplus, received a $4.6 million distribution associated with a privately held investment. This distribution is recorded within Transaction costs and other expense/(income) on the Consolidated Statements of Income/(Loss), and reflected as an investing activity on the Consolidated Statements of Cash Flows. d) Cash Income taxes and Interest payments ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Income taxes paid/(received) $ 5,500 $ (42,716) $ (53,674) Interest paid $ 25,808 $ 21,276 $ 25,517 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2021 | |
SUBSEQUENT EVENTS | |
SUBSEQUENT EVENTS | 21) SUBSEQUENT EVENT On February 2, 2022, the Company announced its plan to initiate a divestment process for its Canadian assets. Production from its Canadian assets averaged approximately 7,200 BOE/day in 2021. |
SIGNIFICANT ACCOUNTING POLICI_2
SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
SIGNIFICANT ACCOUNTING POLICIES | |
Basis of Preparation | 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 and Functional Currency In the fourth quarter of 2021, the Company elected to change its reporting currency from Canadian dollars to U.S. dollars since the majority of its crude oil and natural gas properties are located in the U.S., and to facilitate a more direct comparison to other U.S. exploration and development companies. The change in reporting currency is a voluntary change which is accounted for retrospectively. All prior periods have been restated to U.S. dollars using the procedures outlined below: ● Consolidated Statements of Income/(Loss) and Consolidated Statements of Cash Flows have been translated into U.S. dollars using average foreign exchange rates for the relevant period. ● Assets and liabilities in the Consolidated Balance Sheets have been translated into U.S. dollars at the closing foreign exchange rates on the respective balance sheet dates. ● The shareholders’ equity section of the Consolidated Balance Sheets has been translated into U.S. dollars using historical foreign exchange rates. ● Earnings per share disclosures have also been restated to U.S. dollars to reflect the change in reporting currency. Dividends are disclosed in Canadian dollars with the U.S. dollar equivalent disclosed in parentheses as dividends were declared in Canadian dollars. The functional currency of the parent entity has been and continues to be Canadian dollars and the functional currency of the U.S. subsidiaries continues to be U.S. dollars. All references to $ or US$ are to U.S. dollars and references to CDN$ are to Canadian dollars. All financial information presented in U.S. and 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 those that relate to: 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. Inflation and discount rates impacting various items within the Company’s financial statements are also subject to management estimation. When estimating the present value of future cash flows, the discount rate implicitly considers the potential impacts, if any, due to climate change factors. Enerplus uses the most current information available and exercises judgment in making 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. |
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, with limited exceptions, at the acquisition date. |
Revenue | b) Revenue 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. 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. 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, in which case the Company would be the principal and the revenue is recognized on a gross basis. Any associated fees are recorded as an expense. 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. All references to crude oil and natural gas revenue or production in the Consolidated Financial Statements are net of royalties. |
Transportation | c) Transportation Enerplus generally sells crude oil and natural gas under two types of agreements which are common in 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). |
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 or any other factors, as it is prescribed under U.S. GAAP. The ultimate period in which global energy markets can fully transition from carbon-based sources to alternative energy is highly uncertain, and as such, it is difficult to determine the impact on estimated future net cash flows of such a transition. 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 certain circumstances, where the carrying value of the full cost centre exceeds the ceiling test limitation, the Company may seek a temporary waiver from the SEC to exclude certain amounts from the full cost ceiling limitation. The Company must demonstrate that the fair value of the excluded properties clearly exceeds the carrying value. Under full cost accounting rules, divestments 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 is 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, and computer equipment. 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) Other Long-term Assets Other Long-term Assets include Company-owned line fill in third party pipelines and long-term receivables. Line fill is recorded at lower of cost and net realizable value. |
Cash and Cash Equivalents | g) Cash and Cash Equivalents Cash and cash equivalents include cash and highly liquid investments with maturities of less than 90 days. |
Goodwill | h) 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. 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 | i) Asset Retirement Obligations Enerplus’ crude oil and natural gas operating activities give rise to dismantling, decommissioning, reclamation, 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 | j) Leases Enerplus determines if an arrangement is an operating or finance lease, as defined under U.S. GAAP, 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. These leases are included in right-of-use (“ROU”) assets and lease liabilities 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 such leases. Lease liabilities are recognized at the lease commencement date based on the present value of remaining lease payments over the lease term, taking into consideration conditions such as incentives and termination penalties, as appropriate. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for payments made prior to lease commencement or initial direct costs, if any. When calculating the present value, Enerplus uses the rate implicit in the lease, or uses its incremental borrowing rate for a similar term and risk profile based on the information available at the commencement date. 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 can contain both lease and non-lease components, which are accounted for separately. For certain equipment leases, a portfolio approach is applied to account for the ROU assets and liabilities. |
Income Tax | k) 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 | l) 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 and cash equivalents, accounts receivable, accounts payable, bank credit facilities, and term loan reported on the Consolidated Balance Sheets approximates their fair value. The fair value of the senior notes are considered a level 2 fair value measurement and details are disclosed in Note 17. The Company uses the current expected credit loss model in valuing 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 that is held in the parent entity as a hedge of its net investment in operations for which the U.S. dollar is the functional currency. As a non-derivative financial instrument, it 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 the fair value of the net investment in the U.S. subsidiary. If effective, the unrealized foreign exchange gains and losses arising from the translation of the U.S. denominated debt are recorded in Other Comprehensive Income/(Loss) (“OCI”), net of tax, to the extent the net investment in the U.S. subsidiary supports the U.S. denominated debt. Prior to January 1, 2020, the Company did not apply hedge accounting to the net investment in operations with a U.S. dollar functional currency, and unrealized gains and losses were recognized in net income/loss at the end of each 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, 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 | m) Foreign Currency i. Foreign currency transactions Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars in Canada and U.S. dollars in the U.S) 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 currency translation For financial statement presentation, assets and liabilities of Enerplus’ Canadian operations, which have a Canadian dollar functional currency, are translated into U.S. 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 | n) 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 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. |
Net Income/(Loss) Per Share | o) 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 outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price. |
Contingencies | p) 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. |
Government Assistance | q) Government Assistance In 2020, the Alberta, Saskatchewan, and British Columbia provincial governments created programs and provided funding to support the clean-up of inactive or abandoned crude oil and natural gas wells. Enerplus applied for and benefited from these programs in 2021. The programs provide funding directly to oil field service contractors engaged by companies to perform abandonment, remediation, and reclamation work. As work is completed, the contractors submit invoices to the provincial government for reimbursement for the pre-approved funding amounts. Enerplus recognizes the assistance as the abandonment, remediation, and reclamation work is completed by the contractor. The benefit of the funding received by the contractor is reflected as a reduction of asset retirement obligation and recorded as other income in the Consolidated Statements of Income/(Loss). |
Accounting Changes and Recent Pronouncements Issued | r) 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, 2021 : ● ASU 2021-05 – Leases (Topic 842): Lessors – Certain leases with Variable Lease Payments. The adoption of this standard had no impact on the financial statements. |
ACQUISITIONS & DIVESTMENT (Tabl
ACQUISITIONS & DIVESTMENT (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
ACQUISITIONS & DIVESTMENT | |
Schedule of purchase price equation | ($ thousands) At March 10, 2021 Consideration Purchase Price $ 465,000 Purchase price adjustments (44,751) Total consideration $ 420,249 Fair value of identifiable assets and liabilities of Bruin Other current assets 1,667 Property, plant and equipment 542,190 Right of use assets 1,892 Accounts payable (25,257) Asset retirement obligation (21,964) Commodity contract liabilities (76,387) Lease liabilities (1,892) Total identifiable net assets $ 420,249 |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
ACCOUNTS RECEIVABLE | |
Schedule of accounts receivable | ($ thousands) December 31, 2021 December 31, 2020 Accrued revenue $ 208,160 $ 73,201 Accounts receivable – trade 23,697 13,208 Allowance for doubtful accounts (3,869) (2,813) Total accounts receivable, net of allowance for doubtful accounts $ 227,988 $ 83,596 |
PROPERTY, PLANT AND EQUIPMENT_2
PROPERTY, PLANT AND EQUIPMENT ("PP&E") (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
PROPERTY, PLANT AND EQUIPMENT ("PP&E") | |
Schedule of property, plant and equipment | Accumulated Depletion, At December 31, 2021 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 13,075,987 $ (11,822,482) $ 1,253,505 Other capital assets 103,355 (89,468) 13,887 Total PP&E $ 13,179,342 $ (11,911,950) $ 1,267,392 Accumulated Depletion, At December 31, 2020 Depreciation, ($ thousands) Cost and Impairment Net Book Value Crude oil and natural gas properties (1) $ 11,966,258 $ (11,513,956) $ 452,302 Other capital assets 96,373 (84,874) 11,499 Total PP&E $ 12,062,631 $ (11,598,830) $ 463,801 (1) All of the Company’s unproved properties are included in the full cost pool. |
IMPAIRMENT (Tables)
IMPAIRMENT (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
IMPAIRMENT | |
Schedule of property, plant and equipment impairment expense | ($ thousands) 2021 2020 2019 Crude oil and natural gas properties: U.S. cost centre $ — $ 650,780 $ — Canada cost centre 3,420 100,943 — Total impairment expense $ 3,420 $ 751,723 $ — |
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 $/bbl CDN$/bbl $/Mcf CDN$/US$ 2021 $ 66.55 $ 78.15 $ 3.64 0.80 2020 39.54 45.56 2.00 0.75 2019 55.85 66.73 2.58 0.75 |
ACCOUNTS PAYABLE (Tables)
ACCOUNTS PAYABLE (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
ACCOUNTS PAYABLE | |
Schedule of accounts payable | ($ thousands) December 31, 2021 December 31, 2020 Accrued payables $ 106,222 $ 84,286 Accounts payable – trade 260,786 113,609 Total accounts payable $ 367,008 $ 197,895 |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
DEBT | |
Schedule of debt | ($ thousands) December 31, 2021 December 31, 2020 Current: Senior notes $ 100,600 $ 81,600 Long-term: Term loan 397,971 — Senior notes 203,200 303,800 Total debt $ 701,771 $ 385,400 Original Remaining Coupon Principal Principal Issue Date Interest Payment Dates Principal Repayment Rate ($ thousands) ($ thousands) September 3, 2014 March 3 and Sept 3 5 equal annual installments beginning September 3, 2022 3.79% $200,000 $105,000 May 15, 2012 May 15 and Nov 15 Bullet payment on May 15, 2022 4.40% $20,000 $20,000 May 15, 2012 May 15 and Nov 15 3 equal annual installments beginning May 15, 2022 4.40% $355,000 $178,800 Total carrying value at December 31, 2021 $ 303,800 |
ASSET RETIREMENT OBLIGATION (_2
ASSET RETIREMENT OBLIGATION ("ARO") (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
ASSET RETIREMENT OBLIGATION ("ARO") | |
Schedule of changes in asset retirement obligation | ($ thousands) December 31, 2021 December 31, 2020 Balance, beginning of year $ 102,325 $ 106,274 Change in estimates 26,586 3,020 Property acquisition and development activity 1,304 1,615 Bruin acquisition (Note 3) 21,964 — Dunn County acquisition (Note 3) 5,880 — Divestments (Note 3) (13,525) (758) Settlements (12,951) (13,275) Government assistance (4,594) — Accretion expense 5,825 5,449 Balance, end of year $ 132,814 $ 102,325 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
LEASES | |
Summary of leases | ($ thousands) December 31, 2021 December 31, 2020 Assets Operating right-of-use assets $ 26,118 $ 25,818 Liabilities Current operating lease liabilities $ 10,618 $ 10,523 Non-current operating lease liabilities 18,265 18,425 Total lease liabilities $ 28,883 $ 28,948 Weighted average remaining lease term (years) Operating leases 3.3 3.9 Weighted average discount rate Operating leases 3.4% 4.2% ($ thousands) 2021 2020 Operating lease cost $ 11,378 $ 12,368 Variable lease cost 633 1,308 Short-term lease cost 3,469 7,093 Sublease income (1,083) (1,101) Total $ 14,397 $ 19,668 ($ thousands) 2021 2020 Cash amounts paid to settle lease liabilities: Operating cash flow used for operating leases $ 11,571 $ 12,038 Right-of-use assets obtained/(terminated): Operating leases $ 10,030 $ (1,306) |
Summary of maturity of leases | ($ thousands) Operating Leases 2022 $ 11,419 2023 10,211 2024 5,870 2025 987 2026 966 After 2026 1,153 Total lease payments $ 30,606 Less imputed interest (1,723) Total discounted lease payments $ 28,883 Current portion of lease liabilities $ 10,618 Non-current portion of lease liabilities $ 18,265 |
CRUDE OIL AND NATURAL GAS SAL_2
CRUDE OIL AND NATURAL GAS SALES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
CRUDE OIL AND NATURAL GAS SALES | |
Tabular disclosure of revenue from oil and natural gas sales during the period | 2021 Natural Natural gas ($ thousands) Total revenue Crude oil (1) gas (1) liquids (1) Other (2) United States $ 1,355,255 $ 1,055,748 $ 219,552 $ 79,930 $ 25 Canada 127,320 111,070 11,127 4,348 775 Total $ 1,482,575 $ 1,166,818 $ 230,679 $ 84,278 $ 800 2020 Natural Natural gas ($ thousands) Total revenue Crude oil (1) gas (1) liquids (1) Other (2) United States $ 480,822 $ 380,074 $ 92,453 $ 8,182 $ 113 Canada 72,917 59,642 9,239 2,591 1,445 Total $ 553,739 $ 439,716 $ 101,692 $ 10,773 $ 1,558 (1) 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. (2) Includes third party processing income. |
GENERAL AND ADMINISTRATIVE EX_2
GENERAL AND ADMINISTRATIVE EXPENSE (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
GENERAL AND ADMINISTRATIVE EXPENSE | |
Schedule of General and Administrative Expense | ($ thousands) 2021 2020 2019 General and administrative expense (1) $ 38,013 $ 33,347 $ 37,360 Share-based compensation expense 18,794 9,750 17,560 General and administrative expense $ 56,807 $ 43,097 $ 54,920 (1) Includes non-cash lease credit of $365 in 2021, $212 in 2020, and an expense of $542 in 2019. |
FOREIGN EXCHANGE (Tables)
FOREIGN EXCHANGE (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
FOREIGN EXCHANGE | |
Schedule of foreign exchange (gain)/loss | ($ thousands) 2021 2020 2019 Realized: Foreign exchange (gain)/loss $ 3,477 $ 771 $ (1,346) Foreign exchange (gain)/loss on U.S. dollar cash held in parent company (2,330) (902) 6,825 Unrealized: Foreign exchange (gain)/loss on U.S. dollar debt and working capital in parent company (8,055) 1,363 (21,899) Foreign exchange (gain)/loss $ (6,908) $ 1,232 $ (16,420) |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
INCOME TAXES | |
Schedule of the Company's provision for income taxes | ($ thousands) 2021 2020 2019 Current tax United States $ 2,700 $ (10,716) $ (14,774) Canada (11) — (10,472) Current tax expense/(recovery) 2,689 (10,716) (25,246) Deferred tax United States $ 148,920 $ (167,835) $ 53,020 Canada (50,165) (20,425) 8,630 Deferred tax expense/(recovery) 98,755 (188,260) 61,650 Income tax expense/(recovery) $ 101,444 $ (198,976) $ 36,404 |
Schedule of reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes | ($ thousands) 2021 2020 2019 Income/(loss) before taxes United States $ 544,464 $ (877,406) $ 170,346 Canada (208,579) (14,921) (338,342) Total income/(loss) before taxes 335,885 (892,327) (167,996) Canadian statutory rate 24.00% 24.00% 26.50% Expected income tax expense/(recovery) $ 80,612 $ (214,158) $ (44,519) Impact on taxes resulting from: Foreign and statutory rate differences $ 19,297 $ (27,918) $ 21,329 Share-based compensation 1,878 1,671 (4,068) Non-taxable capital (gains)/losses (105) 14,341 3,007 Change in valuation allowance (560) (25,918) (16,598) Amounts in respect of prior periods 322 5,845 (14,669) Non-deductible goodwill impairment and other expenses — 47,161 91,922 Income tax expense/(recovery) $ 101,444 $ (198,976) $ 36,404 |
Schedule of deferred income tax asset (liability) | At December 31 2021 2020 Deferred income tax assets Property, plant and equipment $ 125,312 $ 139,724 Tax loss carry-forwards and other credits 225,463 303,288 Capital loss carry-forwards and other capital items 107,681 111,497 Asset retirement obligation 32,896 24,985 Derivative financial instruments 28,907 2,926 Other assets 19,270 6,668 Deferred income tax assets before valuation allowance 539,529 589,088 Valuation allowance (112,847) (112,074) Deferred income tax assets, net 426,682 477,014 Deferred income tax liabilities Property, plant and equipment $ (45,824) $ — Total deferred income tax liabilities (45,824) — Total deferred income tax asset $ 380,858 $ 477,014 |
Schedule of loss carryforwards and tax credits that can be utilized in future years | At December 31 ($ thousands) 2021 Expiration Date United States Federal Net operating losses – prior to 2018 $ 476,000 2032-2037 Net operating losses – 2018 and thereafter 256,000 Indefinite Canada Federal Capital losses $ 848,000 Indefinite Non-capital losses 137,000 2031-2041 |
Schedule of changes in the balance of Enerplus' unrecognized tax benefits | ($ thousands) 2021 2020 2019 Balance, beginning of year $ 15,485 $ — $ 9,753 Increase – tax positions in prior periods — 15,485 — Settlements — — (9,753) Balance, end of year $ 15,485 $ 15,485 $ — |
Summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities | Jurisdiction Taxation Years United States – Federal 2018-2021 Canada – Federal 2017-2021 |
SHAREHOLDERS' EQUITY (Tables)
SHAREHOLDERS' EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
SHAREHOLDERS' EQUITY | |
Schedule of share capital | 2021 2020 2019 (thousands) Shares Amount Shares Amount Shares Amount Balance, beginning of year 222,548 $ 3,113,829 221,744 $ 3,106,875 239,411 $ 3,294,496 Issued/(Purchased) for cash: Issue of shares (net of tax effected issue costs) 33,062 99,516 — — — — Purchase of common shares under Normal Course Issuer Bid (12,898) (128,686) (340) (3,582) (18,231) (190,917) Non-cash: Share-based compensation – treasury settled (1) 1,140 9,402 1,160 10,694 564 3,296 Cancellation of predecessor shares — — (16) (158) — — Balance, end of year 243,852 $ 3,094,061 222,548 $ 3,113,829 221,744 $ 3,106,875 (1) The amount of shares issued on LTI settlement is net of employee withholding taxes. |
Summary of share-based compensation expense which is included in General and Administrative expense on the Consolidated Income Statements | ($ thousands) 2021 2020 2019 Cash: Long-term incentive plans (recovery)/expense $ 6,875 $ (934) $ 512 Non-Cash: Long-term incentive plans expense 13,789 9,720 16,814 Equity swap (gain)/loss (1,870) 964 234 Share-based compensation expense $ 18,794 $ 9,750 $ 17,560 |
Schedule of PSU, RSU and DSU activity | For the year ended December 31, 2021 Cash-settled LTI Plans Equity-settled LTI Plans Total (thousands of units) DSU PSU (1) RSU Balance, beginning of year 555 2,552 1,825 4,932 Granted 269 2,158 2,207 4,634 Vested (235) (728) (890) (1,853) Forfeited — — (77) (77) Balance, end of year 589 3,982 3,065 7,636 (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, 2021 ($ thousands, except for years) PSU (1) RSU Total Cumulative recognized share-based compensation expense $ 12,791 $ 10,554 $ 23,345 Unrecognized share-based compensation expense 9,050 4,303 13,353 Fair value $ 21,841 $ 14,857 $ 36,698 Weighted-average remaining contractual term (years) 1.9 1.5 (1) Includes estimated performance multipliers. |
Schedule of net income/(loss) per share | (thousands, except per share amounts) 2021 2020 2019 Net income/(loss) $ 234,441 $ (693,351) $ (204,400) Weighted average shares outstanding – Basic 251,909 222,503 231,334 Dilutive impact of share-based compensation (1) 7,942 — — Weighted average shares outstanding – Diluted 259,851 222,503 231,334 Net income/(loss) per share Basic $ 0.93 $ (3.12) $ (0.88) Diluted $ 0.90 $ (3.12) $ (0.88) (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, 2021 | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | |
Schedule of change in fair value of derivative financial instruments | Income Gain/(Loss) 2021 2020 2019 Statement Presentation Equity Swaps $ 1,870 $ (964) $ (234) G&A expense Commodity Contracts: Oil (111,655) (19,891) (51,479) Commodity derivative Gas 249 2,781 (8,037) instruments Total Unrealized Gain/(Loss) $ (109,536) $ (18,074) $ (59,750) |
Summary of the income statement effects of Enerplus' commodity derivative instruments | ($ thousands) 2021 2020 2019 Unrealized change in fair value gain/(loss) $ (111,406) $ (17,110) $ (59,516) Net realized cash gain/(loss) (163,026) 92,852 11,586 Commodity contracts gain/(loss) $ (274,432) $ 75,742 $ (47,930) |
Summary of the fair value of derivative financial instruments | December 31, 2021 December 31, 2020 Assets Liabilities Assets Liabilities ($ thousands) Current Current Long-term Current Current Equity Swaps $ — 969 $ — $ — $ 2,839 Commodity Contracts: Oil 1,771 141,364 7,098 — 12,297 Gas 3,897 867 — 2,790 — Total $ 5,668 143,200 $ 7,098 $ 2,790 $ 15,136 |
Summary of management positions | Crude Oil Instruments: Instrument Type (1)(2) bbls/day US$/bbl Jan 1, 2022 – Jun 30, 2022 WTI Purchased Put 12,500 75.00 WTI Sold Put 12,500 58.00 WTI Sold Call 12,500 87.63 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 WTI Sold Swap (3) 3,828 42.35 WTI Purchased Swap 3,828 66.52 Jan 1, 2023 – Jun 30, 2023 WTI Purchased Put 10,000 76.50 WTI Sold Put 10,000 60.00 WTI Sold Call 10,000 107.38 Jan 1, 2023 – Oct 31, 2023 WTI Sold Swap (3) 250 42.10 WTI Purchased Swap 250 64.85 WTI Purchased Put (3) 2,000 5.00 WTI Sold Call (3) 2,000 75.00 Nov 1, 2023 – Dec 31, 2023 WTI Purchased Put (3) 2,000 5.00 WTI Sold Call (3) 2,000 75.00 (1) The total average deferred premium spent on the Company’s outstanding crude oil contracts is $1.50 /bbl from January 1, 2022 - December 31, 2022 and $1.25 /bbl from January 1, 2023 – June 30, 2023. (2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes. (3) Upon closing of the Bruin Acquisition, Bruin’s outstanding crude oil contracts were recorded at a fair value liability of $76.4 million. At December 31, 2021, the balance was a liability of $22.8 million on the Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the date of closing of the Bruin Acquisition . Natural Gas Instruments: Instrument Type (1) MMcf/day $/Mcf Jan 1, 2022 – Feb 28, 2022 NYMEX Purchased Put 40.00 3.43 NYMEX Sold Call 40.00 6.00 Mar 1, 2022 – Mar 31, 2022 NYMEX Swap 60.00 4.50 NYMEX Purchased Put 40.00 3.43 NYMEX Sold Call 40.00 6.00 Apr 1, 2022 – Oct 31, 2022 NYMEX Swap 40.00 3.40 NYMEX Purchased Put 60.00 3.77 NYMEX Sold Call 60.00 4.50 (1) Transactions with a common term have been aggregated and presented at weighted average prices/Mcf. |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
COMMITMENTS AND CONTINGENCIES | |
Schedule of minimum annual commitments | Minimum Annual Commitment Each Year ($ thousands) Total 2022 2023 2024 2025 2026 Thereafter Senior notes (1) $ 303,800 $ 100,600 $ 80,600 $ 80,600 $ 21,000 $ 21,000 $ — Term Loan (1) 400,000 — — 400,000 — — — Transportation commitments 545,636 72,241 72,802 73,201 74,014 74,464 178,914 Processing commitments 6,311 1,202 1,202 1,206 1,202 1,202 297 Service Workover Rigs Commitments 9,828 7,884 1,944 — — — — Total commitments (2)(3) $ 1,265,575 $ 181,927 $ 156,548 $ 555,007 $ 96,216 $ 96,666 $ 179,211 (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) CDN$ commitments have been converted to US$ using the December 31, 2021 foreign exchange rate of 0.79 . |
GEOGRAPHICAL INFORMATION (Table
GEOGRAPHICAL INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
GEOGRAPHICAL INFORMATION | |
Schedule of geographical information | As at and for the year ended December 31, 2021 ($ thousands) U.S. Canada Total Crude oil and natural gas sales $ 1,355,255 $ 127,320 $ 1,482,575 Depletion, depreciation and accretion 246,949 24,387 271,336 Property, plant and equipment 1,179,070 88,322 1,267,392 Deferred income tax asset 162,582 218,276 380,858 As at and for the year ended December 31, 2020 ($ thousands) U.S. Canada Total Crude oil and natural gas sales $ 480,822 $ 72,917 $ 553,739 Depletion, depreciation and accretion 183,226 34,892 218,118 Property, plant and equipment 375,634 88,167 463,801 Deferred income tax asset 311,502 165,512 477,014 As at and for the year ended December 31, 2019 ($ thousands) U.S. Canada Total Crude oil and natural gas sales $ 812,370 $ 133,524 $ 945,894 Depletion, depreciation and accretion 223,874 45,172 269,046 Property, plant and equipment 1,007,001 199,782 1,206,783 Deferred income tax asset 143,666 143,094 286,760 Goodwill 149,357 — 149,357 Long term income tax receivable 10,664 — 10,664 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
SUPPLEMENTAL CASH FLOW INFORMATION | |
Schedule of net change in non-cash operating working capital | ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Accounts receivable $ (144,413) $ 84,685 $ (255) Other assets (7,583) (3,333) 3,177 Accounts payable - operating 57,353 2,317 (6,119) Non-cash operating activities $ (94,643) $ 83,669 $ (3,197) |
Schedule of changes in other non-cash working capital | b) Changes in Non-Cash Financing Working Capital ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Dividends payable $ (1,749) $ 65 $ (96) Non-cash financing activities $ (1,749) $ 65 $ (96) c) Changes in Non-Cash Investing Working Capital ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Accounts payable - investing (1) $ 32,793 $ (28,390) $ 15,724 Non-cash investing activities (1) $ 32,793 $ (28,390) $ 15,724 (1) 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, with the exclusion of the Bruin and Dunn County acquisitions. See Note 3. |
Schedule of supplementary cash flow information | ($ thousands) December 31, 2021 December 31, 2020 December 31, 2019 Income taxes paid/(received) $ 5,500 $ (42,716) $ (53,674) Interest paid $ 25,808 $ 21,276 $ 25,517 |
SIGNIFICANT ACCOUNTING POLICI_3
SIGNIFICANT ACCOUNTING POLICIES - Transportation (Details) | 12 Months Ended |
Dec. 31, 2021agreement | |
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, 2021 |
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, 2021category | |
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, 2021 | |
Share-Based Compensation | |
Authorized percentage to issue outstanding common shares from treasury (as a percent) | 4.50% |
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) - Accounting Standards Update 2021-05 | Dec. 31, 2021 |
SIGNIFICANT ACCOUNTING POLICIES | |
Change in Accounting Principle, Accounting Standards Update, Adopted | true |
Change in Accounting Principle, Accounting Standards Update, Adoption Date | Jan. 1, 2021 |
ACQUISITIONS & DIVESTMENT - Bus
ACQUISITIONS & DIVESTMENT - Business Combination - General Information (Details) - Bruin E&P HoldCo, LLC $ in Thousands | Mar. 10, 2021USD ($) |
Acquisition, date of acquisition | |
Purchase agreement date | Jan. 25, 2021 |
Effective date | Jan. 1, 2021 |
Acquisition, additional information | |
Equity interest acquired (as a percent) | 100.00% |
Acquisition, cash consideration | |
Total cash consideration subject to certain purchase price adjustments | $ 465,000 |
ACQUISITIONS & DIVESTMENT - B_2
ACQUISITIONS & DIVESTMENT - Business Combination - Debt Issued (Details) - Unsecured Debt - Three-year senior unsecured term loan $ in Millions | Mar. 10, 2021USD ($) |
Debt | |
Debt instrument, term | 3 years |
Principal amount of debt | $ 400 |
ACQUISITIONS & DIVESTMENT - B_3
ACQUISITIONS & DIVESTMENT - Business Combination - Shares Issued (Details) - Feb. 03, 2021 $ in Millions | USD ($)shares | $ / shares |
Common shares issued | ||
Common shares issued (in shares) | shares | 33,062,500 | |
Share price (in CAD per share) | $ / shares | $ 4 | |
Gross proceeds | $ 103.4 | |
Net proceeds | 99.5 | |
Payment of stock issuance costs | 5.1 | |
Tax | $ 1.2 |
ACQUISITIONS & DIVESTMENT - B_4
ACQUISITIONS & DIVESTMENT - Business Combination - Additional Information (Details) - Bruin E&P HoldCo, LLC $ in Millions | 12 Months Ended |
Dec. 31, 2021USD ($) | |
Acquisition, pro forma information | |
Crude oil and natural gas revenues from the acquisition date | $ 319.2 |
Consolidated earnings before tax from the acquisition date | 111.4 |
Acquisition, additional information | |
Transaction costs | $ 5 |
ACQUISITIONS & DIVESTMENT - B_5
ACQUISITIONS & DIVESTMENT - Business Combination - Pro Forma Information (Details) - Bruin E&P HoldCo, LLC - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Acquisition, pro forma information | ||
Crude oil and natural gas revenues | $ 1,538.7 | $ 775.2 |
Net income (loss) | $ 197.8 | $ (1,332.7) |
ACQUISITIONS & DIVESTMENT - B_6
ACQUISITIONS & DIVESTMENT - Business Combination - Consideration Transferred (Details) - Bruin E&P HoldCo, LLC $ in Thousands | Mar. 10, 2021USD ($) |
Acquisition, consideration | |
Purchase price | $ 465,000 |
Purchase price adjustments | (44,751) |
Total consideration | $ 420,249 |
ACQUISITIONS & DIVESTMENT - B_7
ACQUISITIONS & DIVESTMENT - Business Combination - Fair Value of identifiable Assets and Liabilities (Details) - Bruin E&P HoldCo, LLC $ in Thousands | Mar. 10, 2021USD ($) |
Acquisition, fair value of identifiable assets and liabilities | |
Other current assets | $ 1,667 |
Property, plant and equipment | 542,190 |
Right of use assets | 1,892 |
Accounts payable | (25,257) |
Asset retirement obligation | (21,964) |
Commodity contract liabilities | (76,387) |
Lease liabilities | (1,892) |
Total identifiable net assets | $ 420,249 |
ACQUISITIONS & DIVESTMENT - Ass
ACQUISITIONS & DIVESTMENT - Asset Acquisition - General Information (Details) - Assets in Dunn County, North Dakota | Apr. 30, 2021 |
Asset acquisition | |
Purchase agreement date | Apr. 8, 2021 |
Effective date | Mar. 1, 2021 |
ACQUISITIONS & DIVESTMENT - A_2
ACQUISITIONS & DIVESTMENT - Asset Acquisition - Consideration Transferred (Details) - Assets in Dunn County, North Dakota $ in Millions | Apr. 30, 2021USD ($) |
Asset acquisition, consideration | |
Total cash consideration subject to customary purchase price adjustments | $ 312 |
Asset acquisition, consideration transferred | $ 306.8 |
ACQUISITIONS & DIVESTMENT - Div
ACQUISITIONS & DIVESTMENT - Divestment - General Information (Details) - Sleeping Giant Field in Montana and Russian Creek Area in North Dakota - Disposal Group, Disposed of by Sale, Not Discontinued Operations $ in Millions | Nov. 02, 2021USD ($) |
Divestment | |
Total cash consideration subject to customary purchase price adjustments | $ 115 |
Divestment, consideration | $ 107.8 |
ACQUISITIONS & DIVESTMENT - D_2
ACQUISITIONS & DIVESTMENT - Divestment - Contingent Payments (Details) - Sleeping Giant Field in Montana and Russian Creek Area in North Dakota - Disposal Group, Disposed of by Sale, Not Discontinued Operations $ in Millions | Dec. 31, 2021$ / bbl | Nov. 02, 2021USD ($) |
Divestment | ||
Contingent consideration | $ | $ 5 | |
WTI Oil Price average minimum in 2022 (in dollars per barrel) | 65 | |
WTI Oil Price average minimum in 2023 (in dollars per barrel) | 60 |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Accounts Receivable | ||
Accrued revenue | $ 208,160 | $ 73,201 |
Accounts receivable - trade | 23,697 | 13,208 |
Allowance for doubtful accounts | (3,869) | (2,813) |
Total accounts receivable, net of allowance for doubtful accounts | $ 227,988 | $ 83,596 |
PROPERTY, PLANT AND EQUIPMENT_3
PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Tabular Disclosure (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Crude oil and natural gas properties | |||
Crude oil and natural gas properties, cost | $ 13,075,987 | $ 11,966,258 | |
Crude oil and natural gas properties, depreciation, and impairment | (11,822,482) | (11,513,956) | |
Crude oil and natural gas properties, net book value | 1,253,505 | 452,302 | |
Other capital assets | |||
Other capital assets, cost | 103,355 | 96,373 | |
Other capital assets, accumulated depletion, depreciation, and impairment | (89,468) | (84,874) | |
Other capital assets, net book value | 13,887 | 11,499 | |
Property, plant and equipment | |||
Total PP&E, cost | 13,179,342 | 12,062,631 | |
Total PP&E, accumulated depletion, depreciation, and impairment | (11,911,950) | (11,598,830) | |
Property, plant and equipment | $ 1,267,392 | $ 463,801 | $ 1,206,783 |
PROPERTY, PLANT AND EQUIPMENT_4
PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Acquisitions (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Oil and Gas Properties and Land | ||
Property, plant and equipment | ||
Property, plant and equipment, additions | $ 857.1 | $ 7.5 |
PROPERTY, PLANT AND EQUIPMENT_5
PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Divestments (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Property, plant and equipment | ||
Property divestments | $ 112.7 | $ 4.5 |
IMPAIRMENT - Impairment of PP&E
IMPAIRMENT - Impairment of PP&E - Tabular Disclosure (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Impairment | |||
Impairment of PP&E | $ 3,420 | $ 751,723 | $ 0 |
Canada | |||
Impairment | |||
Impairment of PP&E | $ 3,420 | 100,943 | |
U.S. | |||
Impairment | |||
Impairment of PP&E | $ 650,780 |
IMPAIRMENT - Impairment of PP_2
IMPAIRMENT - Impairment of PP&E - General Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Impairment | |||
Asset impairment | $ 3,420 | $ 751,723 | $ 0 |
Ceiling test limitation | $ 265,000 |
IMPAIRMENT - Impairment of PP_3
IMPAIRMENT - Impairment of PP&E - Ceiling Test (Details) | Dec. 31, 2021$ / Mcf$ / bbl$ / $ | Dec. 31, 2020$ / Mcf$ / bbl$ / $ | Dec. 31, 2019$ / Mcf$ / bbl$ / $ |
Impairment | |||
WTI Crude Oil US$/bbl (in dollars per barrel) | 66.55 | 39.54 | 55.85 |
Edm Light Crude CDN$/bbl (in Canadian dollar per barrel) | 78.15 | 45.56 | 66.73 |
U.S. Henry Hub Gas US$/Mcf (in dollars per Mcf) | $ / Mcf | 3.64 | 2 | 2.58 |
Exchange Rate US$/CDN$ (in Canadian dollars per US dollars) | $ / $ | 0.80 | 0.75 | 0.75 |
IMPAIRMENT - Impairment of Good
IMPAIRMENT - Impairment of Goodwill (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2021 | |
Impairment | |||
Goodwill | $ 0 | $ 149,357 | $ 0 |
Goodwill impairment | 149,217 | 347,283 | |
Canadian Reporting Unit | |||
Impairment | |||
Goodwill impairment | $ 347,300 | ||
United States Reporting Unit | |||
Impairment | |||
Goodwill impairment | $ 149,200 |
OTHER LONG-TERM ASSETS (Details
OTHER LONG-TERM ASSETS (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
OTHER LONG-TERM ASSETS | ||
Line fill in third party pipelines | $ 5,300 | $ 3,800 |
Contingent consideration | $ 4,500 | $ 0 |
ACCOUNTS PAYABLE (Details)
ACCOUNTS PAYABLE (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Accounts Payable | ||
Accrued payables | $ 106,222 | $ 84,286 |
Accounts payable - trade | 260,786 | 113,609 |
Total accounts payable | $ 367,008 | $ 197,895 |
DEBT - Total Debt (Details)
DEBT - Total Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Debt | ||
Long-term debt, current portion | $ 100,600 | $ 81,600 |
Long-term debt, non-current portion | 601,171 | 303,800 |
Total debt | 701,771 | 385,400 |
Senior Notes | ||
Debt | ||
Long-term debt, current portion | 100,600 | 81,600 |
Long-term debt, non-current portion | 203,200 | 303,800 |
Total debt | 303,800 | 385,400 |
Unsecured Debt | ||
Debt | ||
Long-term debt, non-current portion | 397,971 | $ 0 |
Total debt | $ 400,000 |
DEBT - Term Loan (Details)
DEBT - Term Loan (Details) - Unsecured Debt - Three-year senior unsecured term loan $ in Millions | Mar. 10, 2021USD ($) |
Debt | |
Debt instrument, issuance date | Mar. 10, 2021 |
Debt instrument, term | 3 years |
Principal amount of debt | $ 400 |
Debt issuance costs, gross | $ 2.8 |
London Interbank Offered Rate (LIBOR) | Minimum | |
Debt | |
Debt instrument, basis spread on variable rate (as a percent) | 1.25% |
London Interbank Offered Rate (LIBOR) | Maximum | |
Debt | |
Debt instrument, basis spread on variable rate (as a percent) | 3.15% |
Canada Bankers' Acceptances Rate | Minimum | |
Debt | |
Debt instrument, basis spread on variable rate (as a percent) | 1.25% |
Canada Bankers' Acceptances Rate | Maximum | |
Debt | |
Debt instrument, basis spread on variable rate (as a percent) | 3.15% |
DEBT - Revolving Credit Facilit
DEBT - Revolving Credit Facility (Details) $ in Millions | Feb. 24, 2022USD ($) |
Line of Credit | Revolving Credit Facility | Subsequent Event | |
Debt | |
Line of credit facility, maximum borrowing capacity | $ 400 |
DEBT - Bank Credit Facility (De
DEBT - Bank Credit Facility (Details) - Line of Credit - Bank Credit Facility - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Debt | ||
Line of credit facility, maximum borrowing capacity | $ 900 | $ 600 |
Line of credit facility, expiration date | Oct. 31, 2025 | |
Debt issuance costs, gross | $ 1.8 | |
Debt instrument, term | 4 years 6 months | |
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduce or increase borrowing costs (as a percent) | 0.05% | |
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduction in Scope 1 and Scope 2 greenhouse gas emissions intensity by 2030 (as a percent) | 50.00% | |
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduction in freshwater usage in well completions by 2025 (as a percent) | 50.00% | |
Line of credit facility, sustainability-linked, Environmental, Social and Governance, incentive pricing terms, reduction in Lost Time Injury Frequency based on three-year trailing average (as a percent) | 25.00% |
DEBT - Amortization of Debt Iss
DEBT - Amortization of Debt Issuance Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Debt | ||
Amortization of debt issuance costs | $ 1,093 | $ 0 |
DEBT - Senior Notes - General I
DEBT - Senior Notes - General Information (Details) - Senior Notes - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Senior Notes, 7.97 Percent, Issued June 18, 2009 | ||
Debt | ||
Principal repayment amount | $ 22 | $ 22 |
Senior Notes, 4.40 Percent, Issued May 15, 2012, Annual Installments | ||
Debt | ||
Principal repayment amount | $ 59.6 | $ 59.6 |
DEBT - Senior Notes - Tabular D
DEBT - Senior Notes - Tabular Disclosure (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Debt | ||
Remaining principal / carrying value | $ 701,771 | $ 385,400 |
Senior Notes | ||
Debt | ||
Remaining principal / carrying value | $ 303,800 | $ 385,400 |
Senior Notes | Senior Notes, 3.79 Percent, Issued September 3, 2014 | ||
Debt | ||
Coupon rate (as a percent) | 3.79% | |
Original principal | $ 200,000 | |
Remaining principal / carrying value | $ 105,000 | |
Senior Notes | Senior Notes, 4.40 Percent, Issued May 15, 2012, Bullet Payment | ||
Debt | ||
Coupon rate (as a percent) | 4.40% | |
Original principal | $ 20,000 | |
Remaining principal / carrying value | $ 20,000 | |
Senior Notes | Senior Notes, 4.40 Percent, Issued May 15, 2012, Annual Installments | ||
Debt | ||
Coupon rate (as a percent) | 4.40% | |
Original principal | $ 355,000 | |
Remaining principal / carrying value | $ 178,800 |
ASSET RETIREMENT OBLIGATION (_3
ASSET RETIREMENT OBLIGATION ("ARO") - Tabular Disclosure (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Changes in asset retirement obligation | ||
Balance, beginning of year | $ 102,325 | $ 106,274 |
Change in estimates | 26,586 | 3,020 |
Property acquisition and development activity | 1,304 | 1,615 |
Bruin acquisition | 21,964 | |
Dunn County acquisition | 5,880 | |
Divestments | (13,525) | (758) |
Settlements | (12,951) | (13,275) |
Government assistance | (4,594) | 0 |
Accretion expense | 5,825 | 5,449 |
Balance, end of year | $ 132,814 | $ 102,325 |
ASSET RETIREMENT OBLIGATION (_4
ASSET RETIREMENT OBLIGATION ("ARO") - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation | |||
Asset retirement obligation | $ 132,814 | $ 102,325 | |
Total undiscounted liability | 303,300 | 102,300 | $ 273,800 |
Government assistance | $ 4,594 | $ 0 |
LEASES - Assets and Liabilities
LEASES - Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Leases | ||
Operating right-of-use assets | $ 26,118 | $ 25,818 |
Current operating lease liabilities | 10,618 | 10,523 |
Non-current operating lease liabilities | 18,265 | 18,425 |
Total lease liabilities | $ 28,883 | $ 28,948 |
LEASES - Weighted Average Remai
LEASES - Weighted Average Remaining Lease Term and Discount Rate (Details) | Dec. 31, 2021 | Dec. 31, 2020 |
Leases | ||
Weighted average remaining lease term (years), operating leases | 3 years 3 months 18 days | 3 years 10 months 24 days |
Weighted average discount rate, operating leases | 3.40% | 4.20% |
LEASES - Lease Expense (Details
LEASES - Lease Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Lease expense | ||
Operating lease cost | $ 11,378 | $ 12,368 |
Variable lease cost | 633 | 1,308 |
Short-term lease cost | 3,469 | 7,093 |
Sublease income | (1,083) | (1,101) |
Total | $ 14,397 | $ 19,668 |
LEASES - Maturities of Lease Li
LEASES - Maturities of Lease Liabilities (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Maturity of Lease Liabilities | |
2022 | $ 11,419 |
2023 | 10,211 |
2024 | 5,870 |
2025 | 987 |
2026 | 966 |
After 2026 | 1,153 |
Total lease payments | $ 30,606 |
LEASES - Gross Difference (Deta
LEASES - Gross Difference (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Gross Difference | ||
Total lease payments | $ 30,606 | |
Less: Present value discount | (1,723) | |
Total discounted lease payments | 28,883 | $ 28,948 |
Current portion of lease liabilities | 10,618 | 10,523 |
Non-current operating lease liabilities | $ 18,265 | $ 18,425 |
LEASES - Supplemental Informati
LEASES - Supplemental Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Leases | ||
Cash amounts paid to settle lease liabilities, operating cash flow used for operating leases | $ 11,571 | $ 12,038 |
Right-of-use assets obtained/(terminated) in exchange for lease obligations, operating leases | $ 10,030 | $ (1,306) |
CRUDE OIL AND NATURAL GAS SAL_3
CRUDE OIL AND NATURAL GAS SALES (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | $ 1,482,575 | $ 553,739 | $ 945,894 |
Crude Oil | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 1,166,818 | 439,716 | |
Natural Gas | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 230,679 | 101,692 | |
Natural Gas Liquids | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 84,278 | 10,773 | |
Other | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 800 | 1,558 | |
Canada | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 127,320 | 72,917 | 133,524 |
Canada | Crude Oil | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 111,070 | 59,642 | |
Canada | Natural Gas | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 11,127 | 9,239 | |
Canada | Natural Gas Liquids | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 4,348 | 2,591 | |
Canada | Other | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 775 | 1,445 | |
U.S. | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 1,355,255 | 480,822 | $ 812,370 |
U.S. | Crude Oil | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 1,055,748 | 380,074 | |
U.S. | Natural Gas | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 219,552 | 92,453 | |
U.S. | Natural Gas Liquids | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | 79,930 | 8,182 | |
U.S. | Other | |||
Oil and natural gas revenue by country and by product | |||
Crude oil and natural gas sales | $ 25 | $ 113 |
GENERAL AND ADMINISTRATIVE EX_3
GENERAL AND ADMINISTRATIVE EXPENSE - Tabular Disclosure (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
GENERAL AND ADMINISTRATIVE EXPENSE | |||
General and administrative expense excluding share-based compensation | $ 38,013 | $ 33,347 | $ 37,360 |
Share-based compensation expense | 18,794 | 9,750 | 17,560 |
General and administrative expense | $ 56,807 | $ 43,097 | $ 54,920 |
GENERAL AND ADMINISTRATIVE EX_4
GENERAL AND ADMINISTRATIVE EXPENSE - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
GENERAL AND ADMINISTRATIVE EXPENSE | |||
Non-cash lease credit | $ 365 | $ 212 | $ 542 |
FOREIGN EXCHANGE (Details)
FOREIGN EXCHANGE (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
FOREIGN EXCHANGE | |||
Foreign exchange (gain)/loss | $ 3,477 | $ 771 | $ (1,346) |
Foreign exchange (gain)/loss on U.S. dollar cash held in parent company | (2,330) | (902) | 6,825 |
Foreign exchange (gain)/loss on U.S. dollar debt and working capital in parent company | (8,055) | 1,363 | (21,899) |
Foreign exchange (gain)/loss | $ (6,908) | $ 1,232 | $ (16,420) |
INCOME TAXES - Provision (Detai
INCOME TAXES - Provision (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current tax expense/(recovery) | |||
United States | $ 2,700 | $ (10,716) | $ (14,774) |
Canada | (11) | (10,472) | |
Current Tax expense/(recovery) | 2,689 | (10,716) | (25,246) |
Deferred Tax expense/(recovery) | |||
United States | 148,920 | (167,835) | 53,020 |
Canada | (50,165) | (20,425) | 8,630 |
Deferred tax expense/(recovery) | 98,755 | (188,260) | 61,650 |
Income tax expense/(recovery) | $ 101,444 | $ (198,976) | $ 36,404 |
INCOME TAXES - Income (Loss) Be
INCOME TAXES - Income (Loss) Before Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Expenses | |||
United States | $ 544,464 | $ (877,406) | $ 170,346 |
Canada | (208,579) | (14,921) | (338,342) |
Income/(Loss) Before Taxes | $ 335,885 | $ (892,327) | $ (167,996) |
INCOME TAXES - Reconciliation (
INCOME TAXES - Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes | |||
Canadian statutory rate (as a percent) | 24.00% | 24.00% | 26.50% |
Expected income tax expense/(recovery) | $ 80,612 | $ (214,158) | $ (44,519) |
Foreign and statutory rate differences | 19,297 | (27,918) | 21,329 |
Share-based compensation | 1,878 | 1,671 | (4,068) |
Non-taxable capital (gains)/losses | (105) | 14,341 | 3,007 |
Change in valuation allowance | (560) | (25,918) | (16,598) |
Amounts in respect of prior periods | 322 | 5,845 | (14,669) |
Non-deductible goodwill impairment and other expenses | 47,161 | 91,922 | |
Income tax expense/(recovery) | $ 101,444 | $ (198,976) | $ 36,404 |
INCOME TAXES - Deferred Tax Ass
INCOME TAXES - Deferred Tax Assets (Liability) (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Deferred income tax assets | ||
Property, plant and equipment | $ 125,312 | $ 139,724 |
Tax loss carryforwards and other credits | 225,463 | 303,288 |
Capital loss carryforwards and other capital items | 107,681 | 111,497 |
Asset retirement obligation | 32,896 | 24,985 |
Derivative financial instruments | 28,907 | 2,926 |
Other assets | 19,270 | 6,668 |
Deferred income tax asset before valuation allowance | 539,529 | 589,088 |
Valuation allowance | (112,847) | (112,074) |
Deferred income tax assets, net | 426,682 | 477,014 |
Deferred income tax liabilities | ||
Property, plant and equipment | (45,824) | |
Total deferred income tax liabilities | (45,824) | |
Total deferred income tax asset | $ 380,858 | $ 477,014 |
INCOME TAXES - Operating Loss C
INCOME TAXES - Operating Loss Carryforwards (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Canada | |
Operating Loss Carryforwards | |
Operating loss carryforward | $ 848,000 |
United States | Earliest Tax Year | |
Operating Loss Carryforwards | |
Operating loss carryforward | 476,000 |
United States | Latest Tax Year | |
Operating Loss Carryforwards | |
Operating loss carryforward | $ 256,000 |
INCOME TAXES - Tax Credit Carry
INCOME TAXES - Tax Credit Carryforwards (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Canada | |
Tax Credit Carryforwards | |
Tax credit carryforward | $ 137,000 |
INCOME TAXES - Unrecognized Tax
INCOME TAXES - Unrecognized Tax Benefits - Tabular Disclosure (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in the balance of unrecognized tax benefits | |||
Balance, beginning of year | $ 15,485 | $ 0 | $ 9,753 |
Increase - tax positions in prior periods | 0 | 15,485 | 0 |
Settlements | 0 | 0 | (9,753) |
Balance, end of year | $ 15,485 | $ 15,485 | $ 0 |
INCOME TAXES - Unrecognized T_2
INCOME TAXES - Unrecognized Tax Benefits - Additional Information (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Income Taxes | ||||
Unrecognized tax benefits | $ 15,485 | $ 15,485 | $ 0 | $ 9,753 |
Unrecognized tax benefits, if recognized, would affect the effective income tax rate | $ 15,485 |
SHAREHOLDERS' EQUITY - Share Ca
SHAREHOLDERS' EQUITY - Share Capital - Tabular Disclosure (Details) - USD ($) $ in Thousands | Feb. 03, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Increase (decrease) in equity | ||||
Balance, beginning of year | $ 420,965 | $ 1,132,837 | ||
Balance, beginning of year (in shares) | 223,000,000 | |||
Issue of shares (net of tax effected issue costs) (in shares) | 33,062,500 | |||
Purchase of common shares under Normal Course Issuer Bid | $ (123,200) | $ (1,900) | $ (134,300) | |
Purchase of common shares under Normal Course Issuer Bid (in shares) | (12,897,721) | (340,434) | (18,231,401) | |
Balance, end of year | $ 609,310 | $ 420,965 | $ 1,132,837 | |
Balance, end of year (in shares) | 244,000,000 | 223,000,000 | ||
Share Capital | ||||
Increase (decrease) in equity | ||||
Balance, beginning of year | $ 3,113,829 | $ 3,106,875 | $ 3,294,496 | |
Balance, beginning of year (in shares) | 222,548,000 | 221,744,000 | 239,411,000 | |
Issue of shares (net of tax effected issue costs) | $ 99,516 | |||
Issue of shares (net of tax effected issue costs) (in shares) | 33,062,000 | |||
Purchase of common shares under Normal Course Issuer Bid | $ (128,686) | $ (3,582) | $ (190,917) | |
Purchase of common shares under Normal Course Issuer Bid (in shares) | (12,898,000) | (340,000) | (18,231,000) | |
Share-based compensation - treasury settled | $ 9,402 | $ 10,694 | $ 3,296 | |
Share-based compensation - treasury settled (in shares) | 1,140,000 | 1,160,000 | 564,000 | |
Cancellation of predecessor shares | $ (158) | |||
Cancellation of predecessor shares (in shares) | (16,000) | |||
Balance, end of year | $ 3,094,061 | $ 3,113,829 | $ 3,106,875 | |
Balance, end of year (in shares) | 243,852,000 | 222,548,000 | 221,744,000 |
SHAREHOLDERS' EQUITY - Share _2
SHAREHOLDERS' EQUITY - Share Capital - Shares Authorized (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Share capital | ||
Share capital, shares authorized, unlimited | Unlimited | Unlimited |
Share capital, par value (in dollars per share) | $ 0 | $ 0 |
SHAREHOLDERS' EQUITY - Share _3
SHAREHOLDERS' EQUITY - Share Capital - Dividends (Details) $ / shares in Units, $ in Millions | Feb. 24, 2022$ / shares | Dec. 31, 2021USD ($)$ / shares | Dec. 31, 2021$ / shares | Dec. 31, 2020USD ($)$ / shares | Dec. 31, 2020$ / shares | Dec. 31, 2019USD ($)$ / shares | Dec. 31, 2019$ / shares |
Dividends | |||||||
Dividends declared per share | (per share) | $ 0.033 | $ 0.12 | $ 0.15 | $ 0.09 | $ 0.12 | $ 0.09 | $ 0.12 |
Dividends declared | $ 30.5 | $ 20 | $ 20.9 |
SHAREHOLDERS' EQUITY - Share _4
SHAREHOLDERS' EQUITY - Share Capital - Shares Issued (Details) - Feb. 03, 2021 $ in Millions | USD ($)shares | $ / shares |
Common shares issued | ||
Common shares issued (in shares) | shares | 33,062,500 | |
Share price (in CAD per share) | $ / shares | $ 4 | |
Gross proceeds | $ 103.4 | |
Net proceeds | 99.5 | |
Payment of stock issuance costs | 5.1 | |
Tax | $ 1.2 |
SHAREHOLDERS' EQUITY - Share _5
SHAREHOLDERS' EQUITY - Share Capital - Shelf Prospectus (Details) $ in Billions | Jun. 23, 2021CAD ($) |
SHAREHOLDERS' EQUITY | |
Shelf Prospectus, aggregate issue amount, 25-month period | $ 2 |
SHAREHOLDERS' EQUITY - Share _6
SHAREHOLDERS' EQUITY - Share Capital - Share Repurchases (Details) $ / shares in Units, $ in Thousands | 2 Months Ended | 12 Months Ended | ||||||
Feb. 23, 2022USD ($)$ / sharesshares | Feb. 23, 2022$ / shares | Dec. 31, 2021USD ($)$ / sharesshares | Dec. 31, 2021$ / sharesshares | Dec. 31, 2020USD ($)$ / sharesshares | Dec. 31, 2020$ / shares | Dec. 31, 2019USD ($)$ / sharesshares | Dec. 31, 2019$ / shares | |
Share capital | ||||||||
Normal Course Issuer Bid, purchases during twelve-month period, percentage of public float (as a percent) | 10.00% | 10.00% | ||||||
Shares purchased for cancellation (in shares) | shares | 12,897,721 | 340,434 | 18,231,401 | |||||
Average price per share | (per share) | $ 9.55 | $ 12.06 | $ 5.63 | $ 7.44 | $ 7.36 | $ 9.80 | ||
Purchase of common shares under Normal Course Issuer Bid | $ | $ 123,200 | $ 1,900 | $ 134,300 | |||||
Common shares available for repurchase under the current NCIB (in shares) | shares | 12,668,090 | 12,668,090 | ||||||
Subsequent Event | ||||||||
Share capital | ||||||||
Shares purchased for cancellation (in shares) | shares | 2,257,400 | |||||||
Average price per share | (per share) | $ 11.58 | $ 14.67 | ||||||
Purchase of common shares under Normal Course Issuer Bid | $ | $ 26,100 | |||||||
Share Capital | ||||||||
Share capital | ||||||||
Shares purchased for cancellation (in shares) | shares | 12,898,000 | 340,000 | 18,231,000 | |||||
Purchase of common shares under Normal Course Issuer Bid | $ | $ 128,686 | $ 3,582 | $ 190,917 | |||||
Accumulated Deficit | ||||||||
Share capital | ||||||||
Purchase of common shares under Normal Course Issuer Bid | $ | $ (5,504) | $ (1,775) | $ (56,632) |
SHAREHOLDERS' EQUITY - Share-Ba
SHAREHOLDERS' EQUITY - Share-Based Compensation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation | |||
Share-based compensation expense | $ 18,794 | $ 9,750 | $ 17,560 |
Cash Settled DSU | |||
Share-based Compensation | |||
Share-based compensation expense | 6,875 | (934) | 512 |
Equity-settled Long-term Incentive Plans | |||
Share-based Compensation | |||
Share-based compensation expense | 13,789 | 9,720 | 16,814 |
Equity Swaps | |||
Share-based Compensation | |||
Share-based compensation expense | $ (1,870) | $ 964 | $ 234 |
SHAREHOLDERS' EQUITY - LTI Plan
SHAREHOLDERS' EQUITY - LTI Plans (Details) shares in Thousands | 12 Months Ended |
Dec. 31, 2021shares | |
Number of units | |
Balance, beginning of year (in shares) | 4,932 |
Granted (in shares) | 4,634 |
Vested (in shares) | (1,853) |
Forfeited (in shares) | (77) |
Balance, end of year (in shares) | 7,636 |
Cash Settled DSU | |
Number of units | |
Balance, beginning of year (in shares) | 555 |
Granted (in shares) | 269 |
Vested (in shares) | (235) |
Balance, end of year (in shares) | 589 |
PSU | |
Number of units | |
Balance, beginning of year (in shares) | 2,552 |
Granted (in shares) | 2,158 |
Vested (in shares) | (728) |
Balance, end of year (in shares) | 3,982 |
RSU | |
Number of units | |
Balance, beginning of year (in shares) | 1,825 |
Granted (in shares) | 2,207 |
Vested (in shares) | (890) |
Forfeited (in shares) | (77) |
Balance, end of year (in shares) | 3,065 |
SHAREHOLDERS' EQUITY - Cash-set
SHAREHOLDERS' EQUITY - Cash-settled LTI Plans (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation | |||
Accounts payable | $ 367,008 | $ 197,895 | |
Cash Settled DSU | |||
Share-based Compensation | |||
Cash share-based compensation (recovery) expense | (6,900) | 900 | $ 500 |
Accounts payable | $ 6,300 | $ 1,700 |
SHAREHOLDERS' EQUITY - Equity-s
SHAREHOLDERS' EQUITY - Equity-settled LTI Plans (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-Based Compensation | |||
Cash withholding taxes | $ 3,551 | $ 5,567 | $ 3,705 |
Equity-settled Long-term Incentive Plans | |||
Share-Based Compensation | |||
Cumulative recognized share-based compensation expense | 23,345 | ||
Unrecognized share-based compensation expense | 13,353 | ||
Fair value | 36,698 | ||
PSU | |||
Share-Based Compensation | |||
Cumulative recognized share-based compensation expense | 12,791 | ||
Unrecognized share-based compensation expense | 9,050 | ||
Fair value | $ 21,841 | ||
Weighted-average remaining contractual term (years) | 1 year 10 months 24 days | ||
RSU | |||
Share-Based Compensation | |||
Cumulative recognized share-based compensation expense | $ 10,554 | ||
Unrecognized share-based compensation expense | 4,303 | ||
Fair value | $ 14,857 | ||
Weighted-average remaining contractual term (years) | 1 year 6 months |
SHAREHOLDERS' EQUITY - Basic an
SHAREHOLDERS' EQUITY - Basic and Diluted Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Basic and diluted net income/(loss) per share | |||
Net income/(loss) | $ 234,441 | $ (693,351) | $ (204,400) |
Net income/(loss) - basic | 234,441 | (693,351) | (204,400) |
Net income/(loss) - diluted | $ 234,441 | $ (693,351) | $ (204,400) |
Weighted average shares outstanding | |||
Weighted average shares outstanding - Basic (in shares) | 251,909 | 222,503 | 231,334 |
Dilutive impact of share-based compensation (in shares) | 7,942 | ||
Weighted average shares outstanding - Diluted (in shares) | 259,851 | 222,503 | 231,334 |
Net income/(loss) per share | |||
Basic (in dollars per share) | $ 0.93 | $ (3.12) | $ (0.88) |
Diluted (in dollars per share) | $ 0.90 | $ (3.12) | $ (0.88) |
FINANCIAL INSTRUMENTS AND RIS_3
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value Measurements (Details) - Senior Notes - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Carrying Value | ||
Fair Value Measurements | ||
Long-term debt, fair value | $ 303.8 | $ 385.4 |
Fair Value | Fair Value, Inputs, Level 2 | ||
Fair Value Measurements | ||
Long-term debt, fair value | $ 304.1 | $ 388.2 |
FINANCIAL INSTRUMENTS AND RIS_4
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Transfers (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Fair Value Measurements | |
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount | $ 0 |
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount | 0 |
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount | 0 |
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount | $ 0 |
FINANCIAL INSTRUMENTS AND RIS_5
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Change in Fair Value Associated with Equity and Commodity Contracts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Derivative Financial Instruments | |||
Equity Swaps, Gain/(Loss) | $ (109,536) | $ (18,074) | $ (59,750) |
Total Unrealized Gain/(Loss) | (109,536) | (18,074) | (59,750) |
Equity Swaps | |||
Derivative Financial Instruments | |||
Equity Swaps, Gain/(Loss) | 1,870 | (964) | (234) |
Commodity Contracts | |||
Derivative Financial Instruments | |||
Commodity Contracts, Gain/(Loss) | (111,406) | (17,110) | (59,516) |
Commodity Contracts | Oil | |||
Derivative Financial Instruments | |||
Commodity Contracts, Gain/(Loss) | (111,655) | (19,891) | (51,479) |
Commodity Contracts | Gas | |||
Derivative Financial Instruments | |||
Commodity Contracts, Gain/(Loss) | $ 249 | $ 2,781 | $ (8,037) |
FINANCIAL INSTRUMENTS AND RIS_6
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Contracts on the Consolidated Statements of Income (Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Derivative Financial Instruments | |||
Commodity contracts gain/(loss) | $ (274,432) | $ 75,742 | $ (47,930) |
Commodity Contracts | |||
Derivative Financial Instruments | |||
Change in fair value gain/(loss) | (111,406) | (17,110) | (59,516) |
Net realized cash gain/(loss) | (163,026) | 92,852 | 11,586 |
Commodity contracts gain/(loss) | $ (274,432) | $ 75,742 | $ (47,930) |
FINANCIAL INSTRUMENTS AND RIS_7
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value of Derivative Financial Instruments - Tabular Disclosure (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Derivative asset | ||
Derivative asset, current | $ 5,668 | $ 2,790 |
Derivative liability | ||
Derivative liability, current | 143,200 | 15,136 |
Derivative liability, noncurrent | 7,098 | |
Equity Swaps | ||
Derivative liability | ||
Derivative liability, current | 969 | 2,839 |
Commodity Contracts | Oil | ||
Derivative asset | ||
Derivative asset, current | 1,771 | |
Derivative liability | ||
Derivative liability, current | 141,364 | 12,297 |
Derivative liability, noncurrent | 7,098 | |
Commodity Contracts | Gas | ||
Derivative asset | ||
Derivative asset, current | 3,897 | $ 2,790 |
Derivative liability | ||
Derivative liability, current | $ 867 |
FINANCIAL INSTRUMENTS AND RIS_8
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value of Derivative Financial Instruments - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Mar. 10, 2021 |
Derivative Financial Instruments | ||
Derivative assets (liabilities) | $ (143.7) | |
Bruin Contract, Counterparties | ||
Derivative Financial Instruments | ||
Derivative assets (liabilities) | (40.2) | |
Bruin E&P HoldCo, LLC | Bruin Contract, Counterparties | ||
Derivative Financial Instruments | ||
Derivative liability | $ 76.4 | |
Derivative assets (liabilities) | $ (22.8) |
FINANCIAL INSTRUMENTS AND RIS_9
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - General Information (Details) | 12 Months Ended |
Dec. 31, 2021 | |
Commodity Contracts | |
Risk Management | |
Maximum percentage of forecasted production volumes net of royalties considered to enter into commodity contracts | 80.00% |
FINANCIAL INSTRUMENTS AND RI_10
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - Tabular Disclosure (Details) | Feb. 24, 2022bbl / dMMcf / d$ / bbl$ / Mcf |
West Texas Intermediate, January 1, 2022 to December 31, 2022 | Commodity Contract [Member] | Crude Oil | |
Commodity Price Risk | |
Total average deferred premium on outstanding hedges | 1.50 |
West Texas Intermediate, January 1, 2023 to June 30, 2023 | Commodity Contract [Member] | Crude Oil | |
Commodity Price Risk | |
Total average deferred premium on outstanding hedges | 1.25 |
West Texas Intermediate, January 1, 2023 to October 31, 2023 | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 2,000 |
Weighted average price | 75 |
New York Mercantile Exchange, March 1, 2022 to March 31, 2022 | Swap | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 60 |
Weighted average price | $ / Mcf | 4.50 |
New York Mercantile Exchange, April 1, 2022 to October 31, 2022 | Swap | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 40 |
Weighted average price | $ / Mcf | 3.40 |
Purchased | West Texas Intermediate, January 1, 2022 to June 30, 2022 | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 12,500 |
Weighted average price | 75 |
Purchased | West Texas Intermediate, January 1, 2022 to December 31, 2022 | Swap | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 3,828 |
Weighted average price | 66.52 |
Purchased | West Texas Intermediate, January 1, 2022 to December 31, 2022 | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 17,000 |
Weighted average price | 50 |
Purchased | West Texas Intermediate, January 1, 2023 to June 30, 2023 | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 10,000 |
Weighted average price | 76.50 |
Purchased | West Texas Intermediate, January 1, 2023 to October 31, 2023 | Swap | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 250 |
Weighted average price | 64.85 |
Purchased | West Texas Intermediate, January 1, 2023 to October 31, 2023 | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 2,000 |
Weighted average price | 5 |
Purchased | West Texas Intermediate, November 1, 2023 to December 31, 2023 [Member] | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 2,000 |
Weighted average price | 5 |
Purchased | New York Mercantile Exchange, January 1, 2022 to February 28, 2022 | Put | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 40 |
Weighted average price | $ / Mcf | 3.43 |
Purchased | New York Mercantile Exchange, March 1, 2022 to March 31, 2022 | Put | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 40 |
Weighted average price | $ / Mcf | 3.43 |
Purchased | New York Mercantile Exchange, April 1, 2022 to October 31, 2022 | Put | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 60 |
Weighted average price | $ / Mcf | 3.77 |
Sold | West Texas Intermediate, January 1, 2022 to June 30, 2022 | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 12,500 |
Weighted average price | 58 |
Sold | West Texas Intermediate, January 1, 2022 to June 30, 2022 | Call | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 12,500 |
Weighted average price | 87.63 |
Sold | West Texas Intermediate, January 1, 2022 to December 31, 2022 | Swap | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 3,828 |
Weighted average price | 42.35 |
Sold | West Texas Intermediate, January 1, 2022 to December 31, 2022 | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 17,000 |
Weighted average price | 40 |
Sold | West Texas Intermediate, January 1, 2022 to December 31, 2022 | Call | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 17,000 |
Weighted average price | 57.91 |
Sold | West Texas Intermediate, January 1, 2023 to June 30, 2023 | Put | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 10,000 |
Weighted average price | 60 |
Sold | West Texas Intermediate, January 1, 2023 to June 30, 2023 | Call | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 10,000 |
Weighted average price | 107.38 |
Sold | West Texas Intermediate, January 1, 2023 to October 31, 2023 | Swap | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 250 |
Weighted average price | 42.10 |
Sold | West Texas Intermediate, November 1, 2023 to December 31, 2023 [Member] | Call | Crude Oil | |
Commodity Price Risk | |
Volume | bbl / d | 2,000 |
Weighted average price | 75 |
Sold | New York Mercantile Exchange, January 1, 2022 to February 28, 2022 | Call | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 40 |
Weighted average price | $ / Mcf | 6 |
Sold | New York Mercantile Exchange, March 1, 2022 to March 31, 2022 | Call | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 40 |
Weighted average price | $ / Mcf | 6 |
Sold | New York Mercantile Exchange, April 1, 2022 to October 31, 2022 | Call | Natural Gas | |
Commodity Price Risk | |
Volume | MMcf / d | 60 |
Weighted average price | $ / Mcf | 4.50 |
FINANCIAL INSTRUMENTS AND RI_11
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Foreign Exchange Risk and Net Investment Hedge (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Debt | |||
Long-term debt | $ 701,771 | $ 385,400 | |
Foreign exchange gain/(loss) on net investment hedge, net of tax | 4,097 | 1,780 | $ 0 |
Senior Notes | |||
Debt | |||
Long-term debt | 303,800 | $ 385,400 | |
Unsecured Debt | |||
Debt | |||
Long-term debt | $ 400,000 |
FINANCIAL INSTRUMENTS AND RI_12
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Interest Rate Risk (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Debt | ||
Long-term debt, fixed interest rate, percentage of total debt (as a percent) | 43.00% | 100.00% |
Long-term debt, floating interest rate, percentage of total debt (as a percent) | 57.00% | |
Interest rate derivatives | ||
Interest rate derivatives | $ 0 | $ 0 |
Fixed Interest Rate Debt | ||
Debt | ||
Weighted average interest rate (as a percent) | 4.20% | 4.40% |
Floating Interest Rate Debt | ||
Debt | ||
Weighted average interest rate (as a percent) | 1.90% |
FINANCIAL INSTRUMENTS AND RI_13
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Credit Risk (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | ||
Marketing receivables, companies considered investment grade (as a percent) | 83.00% | 82.00% |
Allowance for doubtful accounts | $ 3,869 | $ 2,813 |
FINANCIAL INSTRUMENTS AND RI_14
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Climate Change Risk (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2021USD ($) | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | |
Asset impairment charges, oil and gas, ceiling test | $ 0 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Commitments - Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Dec. 31, 2020 |
Debt | ||
Total debt | $ 701,771 | $ 385,400 |
Senior Notes | ||
Debt | ||
Total debt | 303,800 | $ 385,400 |
2022 | 100,600 | |
2023 | 80,600 | |
2024 | 80,600 | |
2025 | 21,000 | |
2026 | 21,000 | |
Unsecured Debt | ||
Debt | ||
Total debt | 400,000 | |
2024 | $ 400,000 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - Commitments - Other Commitments (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Transportation Commitments | |
Other Commitments | |
Total | $ 545,636 |
2022 | 72,241 |
2023 | 72,802 |
2024 | 73,201 |
2025 | 74,014 |
2026 | 74,464 |
Thereafter | 178,914 |
Processing Commitments | |
Other Commitments | |
Total | 6,311 |
2022 | 1,202 |
2023 | 1,202 |
2024 | 1,206 |
2025 | 1,202 |
2026 | 1,202 |
Thereafter | 297 |
Service Workover Rigs Commitments | |
Other Commitments | |
Total | 9,828 |
2022 | 7,884 |
2023 | $ 1,944 |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES - Commitments - Total Commitments (Details) $ in Thousands | Dec. 31, 2021USD ($) |
Total Commitments | |
Total | $ 1,265,575 |
2022 | 181,927 |
2023 | 156,548 |
2024 | 555,007 |
2025 | 96,216 |
2026 | 96,666 |
Thereafter | $ 179,211 |
COMMITMENTS AND CONTINGENCIES_4
COMMITMENTS AND CONTINGENCIES - Commitments - Exchange Rate (Details) | Dec. 31, 2021$ / $ |
Commitments | |
Exchange Rate US$/CDN$ (in US dollars per Canadian dollars) | 0.79 |
GEOGRAPHICAL INFORMATION (Detai
GEOGRAPHICAL INFORMATION (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Geographical Information | |||
Crude oil and natural gas sales | $ 1,482,575 | $ 553,739 | $ 945,894 |
Depletion, depreciation and accretion | 271,336 | 218,118 | 269,046 |
Property, plant and equipment | 1,267,392 | 463,801 | 1,206,783 |
Deferred income tax asset | 380,858 | 477,014 | 286,760 |
Goodwill | 0 | 0 | 149,357 |
Long term income tax receivable | 10,664 | ||
Canada | |||
Geographical Information | |||
Crude oil and natural gas sales | 127,320 | 72,917 | 133,524 |
Depletion, depreciation and accretion | 24,387 | 34,892 | 45,172 |
Property, plant and equipment | 88,322 | 88,167 | 199,782 |
Deferred income tax asset | 218,276 | 165,512 | 143,094 |
U.S. | |||
Geographical Information | |||
Crude oil and natural gas sales | 1,355,255 | 480,822 | 812,370 |
Depletion, depreciation and accretion | 246,949 | 183,226 | 223,874 |
Property, plant and equipment | 1,179,070 | 375,634 | 1,007,001 |
Deferred income tax asset | $ 162,582 | $ 311,502 | 143,666 |
Goodwill | 149,357 | ||
Long term income tax receivable | $ 10,664 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Operating Working Capital (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in Non-Cash Operating Working Capital | |||
Accounts receivable | $ (144,413) | $ 84,685 | $ (255) |
Other assets | (7,583) | (3,333) | 3,177 |
Accounts payable - operating | 57,353 | 2,317 | (6,119) |
Non-cash operating activities | $ (94,643) | $ 83,669 | $ (3,197) |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Financing Working Capital (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in Non-Cash Working Capital | |||
Dividends payable | $ (1,749) | $ 65 | $ (96) |
Non-cash financing activities | $ (1,749) | $ 65 | $ (96) |
SUPPLEMENTAL CASH FLOW INFORM_5
SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Investing Working Capital (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in Non-Cash Working Capital | |||
Accounts payable - investing | $ 32,793 | $ (28,390) | $ 15,724 |
Non-cash investing activities | $ 32,793 | $ (28,390) | $ 15,724 |
SUPPLEMENTAL CASH FLOW INFORM_6
SUPPLEMENTAL CASH FLOW INFORMATION - Investing Activities (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2021USD ($) | |
Investing Activities | |
Distribution associated with a privately held investment | $ 4,600 |
Other expense/(income) | $ 4,593 |
SUPPLEMENTAL CASH FLOW INFORM_7
SUPPLEMENTAL CASH FLOW INFORMATION - Other (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Other | |||
Income taxes paid/(received) | $ 5,500 | $ (42,716) | $ (53,674) |
Interest paid | $ 25,808 | $ 21,276 | $ 25,517 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) | 12 Months Ended |
Dec. 31, 2021Boe | |
SUBSEQUENT EVENTS | |
Average daily production from Canadian assets (in BOE) | 7,200 |