Enerplus (ERF) 40-F 21 Feb 20 2019 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2019shares
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, 2019
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	221,743,701
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Business Contact [Member]
Document Information [Line Items]
Contact Personnel Name	CT Corporation System
Entity Address, Address Line One	28 Liberty Street
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10005
City Area Code	212
Local Phone Number	894-8940

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 151,649	$ 363,327
Accounts receivable	176,119	145,206
Income tax receivable	27,770	55,172
Derivative financial assets	10,570	59,258
Other current assets	2,990	8,928
Total Current Assets	369,098	631,891
Property, plant and equipment:
Oil and natural gas properties (full cost method)	1,547,362	1,293,941
Other capital assets, net	20,244	13,130
Property, plant and equipment	1,567,606	1,307,071
Right of use assets	48,729
Goodwill	194,015	654,799
Derivative financial assets		32,220
Deferred income tax asset	372,502	465,124
Income tax receivable	13,852	27,195
Total Assets	2,565,802	3,118,300
Current liabilities
Accounts payable	291,540	290,045
Dividends payable	2,217	2,395
Current portion of long-term debt	105,998	60,001
Derivative financial liabilities	2,734	1,909
Current portion of lease liabilities	17,541
Total Current Liabilities	420,030	354,350
Long-term debt	500,635	636,849
Asset retirement obligation	138,049	126,112
Lease liabilities	35,530
Total Non-current Liabilities	674,214	762,961
Total Liabilities	1,094,244	1,117,311
Shareholders' Equity
Share capital - authorized unlimited common shares, no par value Issued and outstanding: December 31, 2019 - 222 million shares December 31, 2018 - 239 million shares	3,088,094	3,337,608
Paid-in capital	59,490	46,524
Accumulated deficit	(1,984,365)	(1,772,084)
Accumulated other comprehensive income	308,339	388,941
Total Shareholders' Equity	1,471,558	2,000,989
Total Liabilities & Shareholders' Equity	2,565,802	3,118,300
Commitments and Contingencies

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share capital
Share capital, shares authorized, unlimited	Unlimited	Unlimited
Share capital, par value (in CAD per share)	$ 0	$ 0
Share capital, shares issued (in shares)	222	239
Share capital, shares outstanding (in shares)	222	239

Consolidated Statements of Inco

Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Oil and natural gas sales, net of royalties	$ 1,254,806	$ 1,292,736	$ 920,693
Type of revenue	us-gaap:OilAndGasMember	us-gaap:OilAndGasMember	us-gaap:OilAndGasMember
Commodity derivative instruments gain/(loss)	$ (66,071)	$ 88,232	$ 14,310
Total	1,188,735	1,380,968	935,003
Expenses
Production taxes	83,109	87,286	54,318
General and administrative	72,853	75,783	74,301
Depletion, depreciation and accretion	356,830	304,274	250,774
Goodwill impairment	451,121
Interest	33,919	36,799	38,714
Foreign exchange (gain)/loss	(25,378)	39,521	(30,150)
Gain on divestment of assets		0	(78,400)
Other expense /(income)	(7,529)	(5,909)	(1,906)
Total	1,400,594	899,478	616,017
Income/(Loss) Before Taxes	(211,859)	481,490	318,986
Current income tax expense/(recovery)	(33,414)	(27,093)	(47,957)
Deferred income tax expense/(recovery)	81,275	130,304	129,945
Net Income/(Loss)	(259,720)	378,279	236,998
Other Comprehensive Income/(Loss)
Unrealized gain/(loss) on foreign currency translation	(80,602)	125,817	(90,277)
Total Comprehensive Income/(Loss)	$ (340,322)	$ 504,096	$ 146,721
Net Income/(Loss) per Share
Basic (in CAD per share)	$ (1.12)	$ 1.55	$ 0.98
Diluted (in CAD per share)	$ (1.12)	$ 1.53	$ 0.96
Operating
Expenses
Costs of goods sold	$ 290,766	$ 238,261	$ 197,101
Transportation
Expenses
Costs of goods sold	$ 144,903	$ 123,463	$ 111,265

Consolidated Statements of Chan

Consolidated Statements of Changes in Shareholders' Equity $ in Thousands, $ in Millions	Share CapitalUSD ($)	Share CapitalCAD ($)	Paid-in CapitalCAD ($)	Accumulated DeficitUSD ($)	Accumulated DeficitCAD ($)	Accumulated Other Comprehensive Income/(Loss)CAD ($)	USD ($)	CAD ($)
Balance, beginning of year at Dec. 31, 2016		$ 3,365,962	$ 73,783		$ (2,332,641)	$ 353,401
Increase (decrease) in equity
Share-based compensation - treasury settled		20,984	(20,984)
Share-based compensation - non-cash			22,576
Net income/(loss)					236,998			$ 236,998
Dividends declared					(29,033)			(29,000)
Unrealized gain/(loss) on foreign currency translation						(90,277)
Balance, end of year at Dec. 31, 2017		3,386,946	75,375		(2,124,676)	263,124		1,600,769
Increase (decrease) in equity
Purchase of common shares under Normal Course Issuer Bid		(82,596)			3,569			(79,000)
Share-based compensation - cash settled			(30,648)
Share-based compensation - treasury settled		23,389	(23,389)
Share-based compensation - non-cash			25,917
Stock Option Plan - cash		9,138
Stock Option Plan - exercised		731	(731)
Net income/(loss)					378,279			378,279
Dividends declared					(29,256)			(29,300)
Unrealized gain/(loss) on foreign currency translation						125,817
Balance, end of year at Dec. 31, 2018		3,337,608	46,524		(1,772,084)	388,941		2,000,989
Increase (decrease) in equity
Purchase of common shares under Normal Course Issuer Bid	$ (253.9)	(253,920)		$ 75.1	75,127		$ (178.8)
Share-based compensation - cash settled (tax withholding)			(4,952)
Share-based compensation - treasury settled		4,406	(4,406)
Share-based compensation - non-cash			22,324
Net income/(loss)					(259,720)			(259,720)
Dividends declared					(27,688)			(27,700)
Unrealized gain/(loss) on foreign currency translation						(80,602)
Balance, end of year at Dec. 31, 2019		$ 3,088,094	$ 59,490		$ (1,984,365)	$ 308,339		$ 1,471,558

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2019$ / shares
Dividends declared
Dividends declared (in CAD per share)	$ 0.01

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Activities
Net income/(loss)	$ (259,720)	$ 378,279	$ 236,998
Non-cash items add/(deduct):
Depletion, depreciation and accretion	356,830	304,274	250,774
Goodwill impairment	451,121
Changes in fair value of derivative instruments	81,733	(124,266)	(6,184)
Deferred income tax expense/(recovery)	81,275	130,304	129,945
Foreign exchange (gain)/loss on debt and working capital	(34,085)	58,628	(42,623)
Share-based compensation and general and administrative	23,044	25,917	22,576
Translation of U.S. dollar cash held in Canada (gain)/loss	8,794	(19,630)	10,978
Gain on the divestment of assets			(78,400)
Asset retirement obligation expenditures	(16,715)	(11,263)	(12,907)
Changes in non-cash operating working capital	1,963	(3,459)	(35,032)
Cash flow from operating activities	694,240	738,784	476,125
Financing Activities
Proceeds from the issuance of shares (net of issue costs)		9,138
Dividends	(27,866)	(29,282)	(29,017)
Bank credit facility			(23,272)
Senior notes	(59,429)	(29,044)	(29,084)
Purchase of common shares under Normal Course Issuer Bid	(178,793)	(79,027)
Share-based compensation - cash settled (tax withholding)	(4,952)
Cash flow from/(used in) financing activities	(271,040)	(128,215)	(81,373)
Investing Activities
Capital and office expenditures	(24,362)	(18,009)	(13,276)
Property and land acquisitions	(606,966)	(604,110)	(459,152)
Property divestments	9,539	(919)	56,196
Cash flow from/(used in) investing activities	(621,789)	(623,038)	(416,232)
Effect of exchange rate changes on cash and cash equivalents	(13,089)	29,248	(25,277)
Change in cash and cash equivalents	(211,678)	16,779	(46,757)
Cash and cash equivalents, beginning of year	363,327	346,548	393,305
Cash and cash equivalents, end of year	$ 151,649	$ 363,327	$ 346,548

REPORTING ENTITY

REPORTING ENTITY	12 Months Ended
	Dec. 31, 2019
REPORTING ENTITY
REPORTING ENTITY	​ 1) REPORTING ENTITY These annual audited Consolidated Financial Statements (“Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (the “Company” or “Enerplus”) including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES	2) SIGNIFICANT ACCOUNTING POLICIES The following significant accounting policies are presented to assist the reader in evaluating these Consolidated Financial Statements and, together with the following notes, are an integral part of the Consolidated Financial Statements. a) Basis of Preparation Enerplus’ Consolidated Financial Statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Certain prior period amounts have been restated to conform with current period presentation. i. Reporting Currency These Consolidated Financial Statements are presented in Canadian dollars, which is Enerplus’ reporting currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand unless otherwise indicated. ii. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: 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. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions. In the opinion of management, these Consolidated Financial Statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies. 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 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. ​ The acquisition method of accounting is used to account for acquisitions that meet the definition of a business under U.S. GAAP. The cost of an acquisition is measured as the fair value of the assets transferred, equity instruments issued and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. ​ b) Revenue Revenue from the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers, net of sales taxes. Enerplus recognizes revenue when it satisfies a performance obligation by transferring control of the product to a customer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the contractual delivery points. ​ Enerplus evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, management considers if Enerplus retains control of the product being delivered to the end customer. As part of this assessment, management considers whether the Company retains the economic benefits associated with the good being delivered to the end customer. Management also considers whether the Company has the primary responsibility for the delivery of the product, the ability to establish prices or the inventory risk. If Enerplus acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction. c) Transportation Enerplus generally sells oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which the Company sells crude oil or natural gas at the wellhead and collects a price, net of the transportation incurred by the purchaser. In this case, sales are recorded at the price received from the purchaser, net of transportation costs. Under the other arrangement, Enerplus sells crude oil or natural gas at a specific delivery point, pays transportation to a third party and receives proceeds from the purchaser with no transportation deduction. In this case, transportation costs are recorded as transportation expense on the Consolidated Statements of Income/(Loss). Due to these two distinct selling arrangements, Enerplus’ computed realized prices, before the impact of derivative instruments, include revenues which are reported under two separate bases. d) Oil and Natural Gas Properties Enerplus uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs incurred in finding 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 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 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. Enerplus limits capitalized costs of proved and unproved 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 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”). 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 oil and natural gas prices subsequently increase the ceiling. Under full cost accounting rules, divestitures of oil and natural gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized. ​ e) Other Capital Assets Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, computer equipment and Company owned line-fill in third party pipelines. Line fill is recorded at lower of cost and net realizable value. Depreciation is calculated on a straight-line basis over the estimated useful life of the respective asset. The cost of repairs and maintenance is expensed as incurred. f) Cash and Cash Equivalents Cash and cash equivalents includes cash and highly liquid investments with maturities of less than 90 days. g) Goodwill Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. The portion of goodwill that relates to U.S. operations fluctuates due to changes in foreign exchange rates. Goodwill is stated at cost less impairment and is not amortized. Goodwill is not deductible for income tax purposes. Goodwill is assessed for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. Enerplus first performs a qualitative assessment to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value, quantitative impairment tests are performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied 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. For the purposes of goodwill impairment testing, Enerplus has two reporting units. h) Asset Retirement Obligations Enerplus’ oil and natural gas operating activities give rise to dismantling, decommissioning and site remediation activities. Enerplus recognizes a liability for the estimated present value of the future asset retirement obligation liability at each balance sheet date. Upon recognition, the liability is recorded at its estimated fair value. The associated asset retirement cost is capitalized and amortized over the same period as the underlying asset. Changes in the estimated liability and related asset retirement cost can arise as a result of revisions in the estimated amount or timing of cash flows. Depletion of asset retirement costs and increases in asset retirement obligations resulting from the passage of time are recorded to depreciation, depletion and accretion and charged against net income in the Consolidated Statements of Income/(Loss). i) Leases Enerplus determines if an arrangement is a lease at inception. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating and finance leases are included in right-of-use (“ROU”) assets and the associated lease liability in the Consolidated Balance Sheet. ​ ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Lease liabilities are recognized at lease commencement date based on the present value of remaining lease payments over the lease term. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for lease incentives received. Enerplus uses the implicit rate when readily available, or uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is reasonably certain that it will exercise those options. Lease expense for operating leases is recognized on a straight-line basis over the lease term. ​ Lease agreements contain both lease and non-lease components which are accounted for separately. For certain equipment leases, a portfolio approach is applied to effectively account for the ROU assets and liabilities. Prior to January 1, 2019, the Company applied lease accounting in accordance with ASC 840. ​ j) Income Tax Enerplus uses the liability method of accounting for income taxes. Deferred income tax assets and liabilities are recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax assets are reviewed each period and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. Enerplus considers both positive and negative evidence including historic and expected future taxable income, reversing existing temporary differences and tax basis carry forward periods in making this assessment. A valuation allowance is removed in any period where available evidence indicates all or a portion of the valuation allowance is no longer required. The financial statement effect of an uncertain tax position is recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. Penalties and interest expense related to income tax are recognized in income tax expense. k) Financial Instruments i. Fair Value Measurements Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. For financial instruments carried at fair value, and when disclosing the fair value of financial instruments on certain non-financial items, inputs used in determining the fair value are characterized according to the following fair value hierarchy: ● ● ● Subsequent measurement is based on classification of the financial instrument into one of the following five categories: held-for-trading, held-to-maturity, available-for-sale, loans and receivables or other financial liabilities. ii. Non-derivative financial instruments The carrying amount of cash, accounts receivable, income tax receivable, accounts payable, dividends payable and bank credit facilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of the senior notes are considered a level 2 fair value measurement. The fair value of debt has been disclosed in Note 15. iii. Derivative financial instruments Enerplus enters into financial derivative contracts in order to manage its exposure to market risks from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. Enerplus has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a result, all financial derivative contracts are classified as held-for-trading and are recorded at fair value based on a Level 2 designation, with changes in fair value recorded in net income. The fair values of these derivative instruments are generally based on an estimate of the amounts that would be paid or received to settle these instruments at the balance sheet date. Enerplus’ accounting policy is to not offset the fair values of its financial derivative assets and liabilities. Realized gains and losses from commodity price risk management activities are recognized in income when the contract is settled. Unrealized gains and losses on commodity price risk management activities are recognized in income based on the changes in fair value of the contracts at the end of the respective reporting period. Enerplus’ crude oil, natural gas and natural gas liquids physical delivery purchase and sales contracts qualify as normal purchases and sales as they are entered into and held for the purpose of receipt or delivery of products in accordance with the Company’s expected purchase, sale or usage requirements. As such, these contracts are not considered derivative financial instruments. Settlements on these physical contracts are recognized in net income over the term of the contracts as they occur. l) Foreign Currency i. Foreign currency transactions Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars) using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency of the entity using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Foreign currency differences arising on translation are recognized in net income in the period in which they arise. ii. Foreign operations Assets and liabilities of Enerplus’ U.S. operations, which has a U.S. dollar functional currency, are translated into Canadian dollars at period end exchange rates while revenues and expenses are translated using average rates for the period. Gains and losses from the translation are deferred and included in the cumulative translation adjustment which is recorded in accumulated other comprehensive income. m) Share-Based Compensation Enerplus’ share-based compensation plans include equity-settled Restricted Share Unit (“RSU”) and Performance Share Unit (“PSU”) awards made pursuant to its Share Award Incentive Plan (“SAIP”). The Company is authorized to issue up to 3.8% 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 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. 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 fair value of the respective awards. The grant date fair value is based on the Company’s 20 -day volume weighted average price on December 31 prior to the grant date. The fair value for the PSUs is adjusted for the outcome of the performance condition. Share-based compensation charges are recorded on the Consolidated Statements of Income/(Loss) with an offset to paid-in capital. Each period, management performs an estimate of the PSU plan multiplier. Any differences that arise between the actual multiplier on plan settlement and management’s estimate is recorded to share-based compensation. On settlement of these plans, amounts previously recorded to paid-in capital are reclassified to share capital. Enerplus recognizes a liability with respect to its cash-settled long-term incentive plans based on their estimated fair value. The liability is re-measured at each reporting date and at settlement date with any changes in the fair value recorded as share-based compensation, included in general and administrative expense. ii. Stock options Enerplus’ Stock Option Plan was suspended in 2014 and is now closed. All options outstanding under the plan are fully vested and the expense has been fully recognized. The remaining outstanding stock options will expire in 2020. n) Net Income/(Loss) Per Share Basic net income/(loss) per common share is computed by dividing net income/(loss) by the weighted average number of common shares outstanding during the period. For the diluted net income per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income. The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all stock options and outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price. o) Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recognized when it is probable that a liability has been incurred and the amount can be reasonably estimated. Contingencies are adjusted as additional information becomes available or circumstances change. p) Accounting Changes and Recent Pronouncements Issued i. Recently adopted accounting standards Except for the changes below, the Company has consistently applied the accounting policies to all periods presented in these Consolidated Financial Statements. ​ Enerplus adopted ASC 842 Leases effective January 1, 2019 using the modified retrospective method, with ASC 842 applied to all contracts not yet completed as of the date of adoption with the cumulative effect on comparative periods reflected as an adjustment to retained earnings, if applicable. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases, while accounting for finance leases and lessor accounting remained unchanged. ​ Enerplus elected the practical expedient related to land easements , allowing it to carry forward its accounting treatment for land easements on existing agreements. ​ The impacts of the adoption of ASC 842 as at January 1, 2019 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As reported as at ​ ​ ​ ​ ​ Balance as at ($ thousands) ​ ​ December 31, 2018 ​ ​ Adjustments ​ ​ January 1, 2019 Right-of-use assets $ — ​ $ 50,193 $ 50,193 Current portion of lease liabilities ​ ​ — ​ ​ (10,648) ​ ​ (10,648) Lease liabilities ​ — ​ ​ (39,545) ​ (39,545) Total ​ $ — ​ $ — ​ $ — ​ The standard did not materially impact the Company’s Consolidated Statement of Income/(Loss) or Consolidated Statements of Cash Flows. ​ ii. Future accounting changes In future accounting periods, the Company will adopt the following Accounting Standards Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”): In June 2016 , the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326) . The ASU changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 , and will be applied using a modified retrospective approach. Enerplus has not early adopted the standard and does not expect a material impact to the Consolidated Financial Statements. ​ In January 2017 , the FASB issued ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350) . This standard eliminates Step 2 of the goodwill impairment test, and requires a goodwill impairment charge for the amount that the carrying amount of the reporting unit exceeds the reporting unit’s fair value. The updated guidance is effective January 1, 2020 and will be applied prospectively . Enerplus has not early adopted this ASU. The amended standard simplifies the goodwill impairment test and will impact the amount of any impairment recorded post adoption. ​

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2019
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE	3) ACCOUNTS RECEIVABLE ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Accrued revenue ​ $ 142,048 ​ $ 118,821 Accounts receivable – trade ​ 37,736 ​ 30,252 Allowance for doubtful accounts ​ (3,665) ​ (3,867) Total accounts receivable, net of allowance for doubtful accounts ​ $ 176,119 ​ $ 145,206 ​

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT ("PP&E")	12 Months Ended
	Dec. 31, 2019
PROPERTY, PLANT AND EQUIPMENT ("PP&E")
PROPERTY, PLANT AND EQUIPMENT ("PP&E")	4) PROPERTY, PLANT AND EQUIPMENT (“PP&E”) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accumulated Depletion, ​ ​ As at December 31, 2019 ​ ​ ​ ​ Depreciation, ​ ​ ​ ($ thousands) ​ Cost ​ and Impairment ​ Net Book Value Oil and natural gas properties (1) ​ $ 15,088,724 ​ $ (13,541,362) ​ $ 1,547,362 Other capital assets ​ 125,265 ​ (105,021) ​ 20,244 Total PP&E ​ $ 15,213,989 ​ $ (13,646,383) ​ $ 1,567,606 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accumulated Depletion, ​ ​ As at December 31, 2018 ​ ​ ​ ​ Depreciation, ​ ​ ​ ($ thousands) ​ Cost and Impairment ​ Net Book Value Oil and natural gas properties (1) ​ $ 14,773,082 ​ $ (13,479,141) ​ $ 1,293,941 Other capital assets ​ 115,510 ​ (102,380) ​ 13,130 Total PP&E ​ $ 14,888,592 ​ $ (13,581,521) ​ $ 1,307,071 (1) All of the Company’s unproved properties are included in the full cost pool. Acquisitions: For the years ended December 31, 2019 and 2018, Enerplus acquired property and land totaling $24.4 million, and $25.8 million, respectively. ​ Divestments: For the years ended December 31, 2019 and 2018, Enerplus disposed of properties for proceeds of $9.6 million and $6.9 million, respectively. Certain asset divestments may result in gains if the divestments cause a significant alteration in the relationship between the cost centre’s capitalized costs and proved reserves. During 2019, Enerplus did not recognize any gains on asset divestments (2018 – nil, 2017 – $78.4 million).

IMPAIRMENT

IMPAIRMENT	12 Months Ended
	Dec. 31, 2019
IMPAIRMENT
IMPAIRMENT	​ ​ ​ 5) IMPAIRMENT a) Impairment of PP&E There was no impairment recorded for the years ended December 31, 2019, 2018 and 2017. The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling test as at December 31, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ U.S. Henry ​ ​ ​ ​ WTI Crude Oil ​ Edm Light Crude ​ Hub Gas ​ Exchange Rate Period ​ US$/bbl ​ CDN$/bbl ​ US$/Mcf ​ US$/CDN 2019 ​ $ 55.85 ​ $ 66.73 ​ $ 2.58 ​ ​ 1.33 2018 ​ 65.56 ​ ​ 69.58 ​ ​ 3.10 ​ ​ 1.28 2017 ​ 51.34 ​ ​ 63.57 ​ ​ 2.98 ​ ​ 1.30 ​ b) Impairment of Goodwill Enerplus recorded goodwill impairment of $451.1 million on its Canadian reporting unit for the period ended December 31, 2019. The impairment was due to the carrying value of the Canadian reporting unit exceeding its fair value 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. The estimated fair value of the Canadian reporting unit for the goodwill impairment test was based on the discounted after-tax cash flows associated with the proved and probable reserves of the reporting unit. Other changes in goodwill relate to the impact of foreign exchange movements on U.S. dollar denominated goodwill balances. At December 31, 2019, goodwill consisted entirely of US$149.4 million related to Enerplus’ U.S. reporting unit. There was no goodwill impairment for the years ended December 31, 2018 and 2017.

ACCOUNTS PAYABLE

ACCOUNTS PAYABLE	12 Months Ended
	Dec. 31, 2019
ACCOUNTS PAYABLE
ACCOUNTS PAYABLE	6) ACCOUNTS PAYABLE ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Accrued payables ​ $ 105,928 ​ $ 115,388 Accounts payable – trade ​ 185,612 ​ 174,657 Total accounts payable ​ $ 291,540 ​ $ 290,045 ​

DEBT

DEBT	12 Months Ended
	Dec. 31, 2019
DEBT
DEBT	7) DEBT ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Current: ​ ​ ​ ​ ​ ​ Senior notes ​ $ 105,998 ​ $ 60,001 Long-term: ​ ​ ​ ​ ​ ​ Bank credit facility ​ $ — ​ $ — Senior notes ​ 500,635 ​ 636,849 Total debt ​ $ 606,633 ​ $ 696,850 ​ Bank Credit Facility Enerplus has a senior unsecured, covenant-based, US$600 million bank credit facility that matures on October 31, 2023. Drawn fees range between 125 and 315 basis points over bankers’ acceptance rates. Standby fees on the undrawn portion of the facility are based on 20% of the drawn pricing. The Company has the ability to request an extension of the facility or repay the entire balance at the end of the term. At December 31, 2019, Enerplus was undrawn on the facility (December 31, 2018 –undrawn). Senior Notes During 2019 and 2018, Enerplus made its second and third US$22 million principal repayments on its 2009 senior notes. During 2019, Enerplus made a $30 million bullet repayment on its 2012 senior notes. ​ ​ ​ ​ The terms and rates of the Company’s outstanding senior notes are detailed below: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Original ​ Remaining CDN$ Carrying ​ ​ ​ ​ ​ ​ Coupon ​ Principal ​ Principal ​ Value Issue Date ​ Interest Payment Dates ​ Principal Repayment ​ Rate ​ ($ thousands) ​ ($ thousands) ​ ($ thousands) September 3, 2014 ​ March 3 and Sept 3 ​ 5 equal annual installments beginning September 3, 2022 ​ 3.79% ​ US$200,000 ​ US$105,000 ​ $ 136,395 May 15, 2012 May 15 and Nov 15 Bullet payment on May 15, 2022 4.40% ​ US$20,000 US$20,000 ​ 25,980 May 15, 2012 May 15 and Nov 15 5 equal annual installments beginning May 15, 2020 4.40% ​ US$355,000 US$298,000 ​ 387,102 June 18, 2009 June 18 and Dec 18 2 equal annual installments on June 18, 2020 and 2021 7.97% ​ US$225,000 US$44,000 ​ 57,156 ​ ​ ​ ​ ​ ​ ​ ​ Total carrying value ​ $ 606,633 ​

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2019
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION	8) ASSET RETIREMENT OBLIGATION ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Balance, beginning of year ​ $ 126,112 ​ $ 117,736 Change in estimates ​ 23,362 ​ 16,755 Property acquisition and development activity ​ 2,068 ​ 1,565 Divestments ​ (2,760) ​ (4,585) Settlements ​ (16,715) ​ (11,263) Accretion expense ​ 5,982 ​ 5,904 Balance, end of year ​ $ 138,049 ​ $ 126,112 ​ Enerplus has estimated the present value of its asset retirement obligation to be $138.0 million at December 31, 2019 based on a total undiscounted, uninflated liability of $344.7 million (December 31, 2018 – $126.1 million and $343.9 million, respectively). The asset retirement obligation was calculated using a weighted average credit-adjusted risk-free rate of 5.50% and inflation rate of 1.8% (December 31, 2018 – 5.59% and 1.8%, respectively). The majority of Enerplus’ asset retirement obligation expenditures are expected to be incurred between 2025 and 2055.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2019
LEASES
LEASES	9) LEASES The Company incurs lease payments related to office space, drilling rig commitments, vehicles and other equipment. Leases are entered into and exited in coordination with specific business requirements which include the assessment of the appropriate durations for the related leased assets. Short-term leases with a lease term of 12 months or less are not recorded on the Consolidated Balance Sheet. Such items are charged to operating expenses and general and administrative expenses in the Consolidated Statement of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with other U.S. GAAP. ​ ​ ​ ​ ​ ($ thousands) ​ At December 31, 2019 Assets ​ ​ ​ Operating right-of-use assets ​ $ 48,729 Liabilities ​ ​ ​ Current operating lease liabilities ​ $ 17,541 Non-current operating lease liabilities ​ ​ 35,530 Total lease liabilities ​ $ 53,071 ​ ​ ​ ​ Weighted average remaining lease term (years) ​ ​ ​ Operating leases ​ ​ 4.3 ​ ​ ​ ​ Weighted average discount rate ​ ​ ​ Operating leases ​ ​ 4.1% ​ ​ ​ ​ ​ ​ ​ ​ The components of lease expense for the year ended December 31, 2019 are as follows: ​ ​ ​ ​ ​ ​ ($ thousands) 2019 Operating lease cost $ 19,483 Short-term lease cost 15,332 Sublease income ​ (1,072) Total $ 33,743 ​ Maturities of lease liabilities, all of which are classified as operating leases at December 31, 2019, are as follows: ​ ​ ​ ​ ​ Maturity of Lease Liabilities ​ ($ thousands) ​ Operating Leases 2020 ​ $ 19,371 2021 ​ 14,098 2022 ​ 7,674 2023 ​ 6,706 2024 ​ ​ 6,200 After 2024 ​ 3,979 Total lease payments ​ $ 58,028 Less imputed interest ​ ​ (4,957) Total discounted lease payments ​ $ 53,071 Current portion of lease liabilities ​ $ 17,541 Non-current portion of lease liabilities ​ $ 35,530 ​ Supplemental information related to leases are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) ​ ​ December 31, 2019 Cash amounts paid to settle lease liabilities: ​ ​ ​ Operating cash flow used for operating leases ​ $ 18,637 Right-of-use assets obtained in exchange for lease obligations: ​ ​ Operating leases ​ $ 20,818 ​

OIL AND NATURAL GAS SALES

OIL AND NATURAL GAS SALES	12 Months Ended
	Dec. 31, 2019
OIL AND NATURAL GAS SALES
OIL AND NATURAL GAS SALES	10) OIL AND NATURAL GAS SALES ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Oil and natural gas sales ​ $ 1,572,955 ​ $ 1,610,899 ​ $ 1,141,770 Royalties (1) ​ (318,149) ​ (318,163) ​ (221,077) Oil and natural gas sales, net of royalties ​ $ 1,254,806 ​ $ 1,292,736 ​ $ 920,693 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). ​ Oil and natural gas revenue by country and by product for the years ended December 31, 2019 and 2018 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2019 ​ ​ Total revenue, net ​ ​ ​ ​ ​ Natural ​ ​ Natural gas ​ ​ ​ ($ thousands) ​ ​ of royalties (1) ​ ​ Crude oil (2) ​ ​ gas (2) ​ ​ liquids (2) ​ ​ Other (3) Canada $ 177,299 ​ $ 145,814 $ 21,776 $ 7,158 $ 2,551 United States ​ 1,077,507 ​ ​ 847,182 ​ 215,963 ​ 14,355 ​ 7 Total ​ $ 1,254,806 ​ $ 992,996 ​ $ 237,739 ​ $ 21,513 ​ $ 2,558 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 ​ ​ Total revenue, net ​ ​ ​ ​ ​ Natural ​ ​ Natural gas ​ ​ ​ ($ thousands) ​ ​ of royalties (1) ​ ​ Crude oil (2) ​ ​ gas (2) ​ ​ liquids (2) ​ ​ Other (3) Canada $ 198,263 ​ $ 148,949 $ 32,109 $ 14,075 $ 3,130 United States ​ 1,094,473 ​ ​ 834,146 ​ 236,825 ​ 23,502 ​ — Total ​ $ 1,292,736 ​ $ 983,095 ​ $ 268,934 ​ $ 37,577 ​ $ 3,130 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). (2) U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties. (3) Includes third party processing income. ​ Enerplus sells the majority of its production pursuant to variable-price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under the contracts, the Company is required to deliver a fixed or variable volume of crude oil, natural gas liquids or natural gas to the contract counterparty. ​ Crude oil, natural gas and natural gas liquids are sold under contracts of varying terms, including multi-year contracts. Revenues are typically collected in the month following production.

GENERAL AND ADMINISTRATIVE EXPE

GENERAL AND ADMINISTRATIVE EXPENSE	12 Months Ended
	Dec. 31, 2019
GENERAL AND ADMINISTRATIVE EXPENSE
GENERAL AND ADMINISTRATIVE EXPENSE	11) GENERAL AND ADMINISTRATIVE EXPENSE ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 General and administrative expense $ 49,532 ​ $ 49,943 ​ $ 50,544 Share-based compensation expense ​ 23,321 ​ 25,840 ​ 23,757 General and administrative expense (1) $ 72,853 ​ $ 75,783 ​ $ 74,301 (1) Includes cash and non-cash amounts.

FOREIGN EXCHANGE

FOREIGN EXCHANGE	12 Months Ended
	Dec. 31, 2019
FOREIGN EXCHANGE
FOREIGN EXCHANGE	12) FOREIGN EXCHANGE ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Realized: ​ ​ ​ ​ ​ ​ ​ ​ ​ Foreign exchange (gain)/loss ​ $ (87) ​ $ 523 ​ $ 1,495 Translation of U.S. dollar cash held in Canada (gain)/loss ​ ​ 8,794 ​ ​ (19,630) ​ ​ 10,978 Unrealized: ​ ​ ​ ​ ​ ​ ​ ​ ​ Translation of U.S. dollar debt and working capital (gain)/loss ​ (34,085) ​ 58,628 ​ (42,623) Foreign exchange (gain)/loss ​ $ (25,378) ​ $ 39,521 ​ $ (30,150) ​

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
INCOME TAXES
INCOME TAXES	13) INCOME TAXES Enerplus’ provision for income tax is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Current tax ​ ​ ​ ​ ​ ​ ​ ​ ​ Canada ​ $ (13,910) ​ $ (400) ​ $ (407) United States ​ (19,504) ​ (26,693) ​ (47,550) Current tax expense/(recovery) ​ ​ (33,414) ​ ​ (27,093) ​ ​ (47,957) Deferred tax ​ ​ ​ ​ ​ ​ ​ ​ ​ Canada ​ $ 11,023 ​ $ 3,915 ​ $ (17,127) United States ​ 70,252 ​ 126,389 ​ 147,072 Deferred tax expense/(recovery) ​ ​ 81,275 ​ ​ 130,304 ​ ​ 129,945 Income tax expense/(recovery) ​ $ 47,861 ​ $ 103,211 ​ $ 81,988 ​ The following provides a reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Income/(loss) before taxes ​ ​ ​ ​ ​ ​ ​ ​ ​ Canada ​ $ (437,571) ​ $ 104,204 ​ $ 146,953 United States ​ ​ 225,712 ​ 377,286 ​ 172,033 Total income/(loss) before taxes ​ ​ (211,859) ​ ​ 481,490 ​ ​ 318,986 Canadian statutory rate ​ ​ 26.50% ​ 27.00% ​ 27.00% Expected income tax expense/(recovery) ​ $ (56,143) ​ $ 130,002 ​ $ 86,126 Impact on taxes resulting from: ​ ​ ​ ​ ​ ​ ​ ​ ​ Foreign and statutory rate differences ​ $ 27,446 ​ $ (23,859) ​ $ 157,320 Share-based compensation ​ ​ (5,398) ​ ​ (18,102) ​ ​ 5,067 Capital gains and losses ​ ​ 3,994 ​ 7,254 ​ (6,337) Change in valuation allowance ​ ​ (22,038) ​ 6,292 ​ (162,992) Amounts in respect of prior periods ​ ​ (19,451) ​ ​ — ​ ​ — Non-deductible goodwill impairment ​ ​ 119,547 ​ ​ — ​ ​ — Other ​ ​ (96) ​ 1,624 ​ 2,804 Income tax expense/(recovery) ​ $ 47,861 ​ $ 103,211 ​ $ 81,988 ​ During the year, the Alberta corporate income tax rate change resulted in a decrease to the Canadian statutory rate by 0.5% for 2019. ​ The deferred income tax asset consists of the following: ​ ​ ​ ​ ​ ​ ​ ​ As at December 31 2019 2018 Deferred income tax assets ​ ​ ​ ​ ​ ​ Property, plant and equipment ​ $ 59,896 ​ $ 60,665 Tax loss carry-forwards and other credits ​ 383,600 ​ 429,651 Capital loss carryforwards and other capital items ​ ​ 154,532 ​ ​ 188,409 Asset retirement obligation ​ 33,569 ​ 33,935 Other assets ​ 12,219 ​ 14,099 Deferred income tax assets before valuation allowance ​ ​ 643,816 ​ ​ 726,759 Valuation allowance ​ ​ (169,129) ​ ​ (191,167) Deferred income tax assets, net ​ ​ 474,687 ​ ​ 535,592 Deferred income tax liabilities ​ ​ ​ ​ ​ ​ Property, plant and equipment ​ $ (100,328) ​ $ (46,284) Derivative financial instruments ​ ​ (1,857) ​ ​ (24,184) Total deferred income tax liabilities ​ ​ (102,185) ​ ​ (70,468) Total deferred income tax asset ​ $ 372,502 ​ $ 465,124 ​ As of December 31, 2019, $13.9 million was reclassified from deferred income tax asset to income tax receivable for the AMT refund expected to be realized in 2020 (December 31, 2018 – $27.2 million). ​ Loss carry-forwards and tax credits available for tax reporting purposes: ​ ​ ​ ​ ​ ​ ​ As at December 31 2019 Expiration Date Canada ​ ​ ​ ​ ​ Capital losses ​ $ 1,170,000 Indefinite Non-capital losses ​ 405,000 2028-2039 United States ​ ​ ​ ​ ​ Net operating losses – prior to 2018 ​ $ 889,000 ​ 2030-2039 Net operating losses – 2018 and thereafter ​ ​ 102,000 Indefinite ​ Changes in the balance of Enerplus' unrecognized tax benefits are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 ​ 2017 Balance, beginning of year ​ $ 13,300 ​ $ 13,300 ​ $ 13,300 Settlements ​ (13,300) ​ — ​ — Balance, end of year ​ $ — ​ $ 13,300 ​ $ 13,300 ​ Enerplus settled an outstanding dispute with the Canadian tax authorities in the Company's favor reducing the balance of its unrecognized tax benefit to nil and recorded a current tax recovery of $13.9 million including tax and interest. A summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities are as follows: ​ ​ ​ ​ Jurisdiction Taxation Years Canada – Federal 2014-2019 United States – Federal 2016-2019 ​ 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, 2019
SHAREHOLDERS' EQUITY
SHAREHOLDERS' EQUITY	14) SHAREHOLDERS’ EQUITY a) Share Capital ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2019 ​ 2018 ​ 2017 Authorized: unlimited number of common shares Issued: (thousands) Shares Amount Shares Amount Shares Amount Balance, beginning of year 239,411 ​ $ 3,337,608 242,129 ​ $ 3,386,946 240,483 ​ $ 3,365,962 Issued for cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Purchase of common shares under Normal Course Issuer Bid ​ (18,231) ​ ​ (253,920) ​ (5,925) ​ ​ (82,596) ​ — ​ — Stock Option Plan — ​ ​ — 668 ​ 9,138 — ​ — Non-cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Share-based compensation – settled (1) 564 ​ 4,406 2,539 ​ 23,389 1,646 ​ 20,984 Stock Option Plan – exercised ​ — ​ ​ — ​ — ​ ​ 731 ​ — ​ ​ — Balance, end of year 221,744 ​ $ 3,088,094 239,411 ​ $ 3,337,608 242,129 ​ $ 3,386,946 ​ (1) The amount of shares issued on LTI settlement is net of employee withholding taxes in 2019. ​ The Company is authorized to issue an unlimited number of common shares without par value. ​ For the year ended December 31, 2019, Enerplus declared dividends of $0.12 per weighted average common share totaling $27.7 million (December 31, 2018 – $0.12 per share and $29.3 million, December 31, 2017 – $0.12 per share and $29.0 million). ​ On March 21, 2019, Enerplus renewed its Normal Course Issuer Bid (“NCIB”) to continue to repurchase shares through the facilities of the Toronto Stock Exchange (the “TSX”), New York Stock Exchange and/or alternative Canadian trading systems. Pursuant to the NCIB, the Company was permitted to repurchase for cancellation up to 16,673,015 common shares over a period of twelve months commencing on March 26, 2019. All repurchases are made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess is allocated to accumulated deficit. On November 7, 2019, the Company’s Board of Directors approved an increase to the maximum number of common shares that may be repurchased under the NCIB for up to 10% of the public float (or an additional 7,145,578 common shares) until the expiry of the NCIB on March 25, 2020. ​ For the year ended December 31, 2019, the Company repurchased 18,231,401 common shares under the NCIB at an average price of $9.80 per share, for total consideration of $178.8 million. Of the amount paid, $253.9 million was charged to share capital and $75.1 million was credited to accumulated deficit. ​ For the year ended December 31, 2018, the Company repurchased 5,925,084 common shares under the NCIB at an average price of $13.33 per share, for total consideration of $79.0 million. Of the amount paid, $82.6 million was charged to share capital and $3.6 million was credited to accumulated deficit. ​ Subsequent to the year, and up to February 20, 2020, the Company repurchased approximately 340,000 common shares under the NCIB at an average price of $7.44 per share, for total consideration of $2.5 million. The Company also received approval from the Board of Directors to renew the NCIB upon expiry of the existing term on March 25, 2020, subject to approval by the TSX. The proposed renewal is anticipated to be for 10% of the public float (within the meaning under the TSX rules), consistent with the current bid. ​ b) Share-based Compensation The following table summarizes Enerplus' share-based compensation expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term incentive plans expense ​ $ 689 ​ $ 133 ​ $ 997 Non-Cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term incentive plans expense ​ ​ 22,324 ​ ​ 25,917 ​ ​ 22,576 Equity swap (gain)/loss ​ 308 ​ (210) ​ 184 Share-based compensation expense ​ $ 23,321 ​ $ 25,840 ​ $ 23,757 ​ ​ ​ ​ ​ ​ i) LTI Plans The following table summarizes the PSU, RSU and DSU activity for the twelve months ended December 31, 2019: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the year ended December 31, 2019 ​ Cash-settled LTI Plans ​ Equity-settled LTI Plans ​ Total (thousands of units) DSU PSU (1) RSU ​ Balance, beginning of year 391 ​ 1,371 ​ 1,753 ​ 3,515 Granted 99 ​ 817 ​ 862 ​ 1,778 Vested (68) ​ — ​ (1,007) ​ (1,075) Forfeited — ​ (49) ​ (77) ​ (126) Balance, end of year ​ 422 ​ 2,139 ​ 1,531 ​ 4,092 ​ (1) Based on underlying awards before any effect of the performance multiplier. ​ Cash-settled LTI Plans For the year ended December 31, 2019, the Company made cash payments of $0.9 million related to its cash-settled plans (2018 – $0.5 million, 2017 – $0.1 million). As of December 31, 2019, a liability of $3.9 million (December 31, 2018 – $4.1 million) with respect to the Director DSU Plan has been recorded to Accounts Payable on the Consolidated Balance Sheets. Equity-settled LTI Plans The following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ At December 31, 2019 ($ thousands, except for years) PSU (1) RSU Total Cumulative recognized share-based compensation expense ​ $ 30,768 ​ $ 13,495 ​ $ 44,263 Unrecognized share-based compensation expense ​ 11,971 ​ 5,582 ​ 17,553 Fair value ​ $ 42,739 ​ $ 19,077 ​ $ 61,816 Weighted-average remaining contractual term (years) ​ 1.7 ​ ​ 1.4 ​ ​ ​ (1) Includes estimated performance multipliers. The Company directly withholds shares on PSU and RSU settlements for tax-withholding purposes. For the year ended December 31, 2019, $5.0 million (2018, 2017 – nil) in cash withholding taxes were paid. ​ ii) Stock Option Plan At December 31, 2019, all stock options are fully vested and all non-cash share-based compensation expense has been fully recognized. The following table summarizes the stock option plan activity for the year ended December 31, 2019: ​ ​ ​ ​ ​ ​ ​ ​ Number of Options Weighted Average Year ended December 31, 2019 ​ (thousands) ​ Exercise Price Options outstanding, beginning of year 4,131 ​ $ 17.12 Exercised — ​ — Forfeited (96) ​ 15.22 Expired (1,928) ​ 20.35 Options outstanding and exercisable, end of year 2,107 ​ $ 14.24 ​ At December 31, 2019, 2,106,944 options were exercisable at a weighted average exercise price of $14.24 with a weighted average remaining contractual term of 0.2 years, giving an aggregate intrinsic value of nil (December 31, 2018 – nil , December 31, 2017 – nil ). c) Basic and Diluted Net Income/(Loss) Per Share Net income/(loss) per share has been determined as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (thousands, except per share amounts) 2019 2018 2017 Net income/(loss) ​ $ (259,720) ​ $ 378,279 ​ $ 236,998 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average shares outstanding – Basic ​ 231,334 ​ 244,076 ​ 241,929 Dilutive impact of share-based compensation (1) ​ — ​ 3,185 ​ 5,945 Weighted average shares outstanding – Diluted ​ ​ 231,334 ​ ​ 247,261 ​ ​ 247,874 Net income/(loss) per share ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ (1.12) ​ $ 1.55 ​ $ 0.98 Diluted ​ $ (1.12) ​ $ 1.53 ​ $ 0.96 ​ (1) For the year ended December 31, 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, 2019
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT	15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT a) Fair Value Measurements At December 31, 2019, senior notes had a carrying value of $606.6 million and a fair value of $613.8 million (December 31, 2018 – $696.9 million and $695.4 million, respectively). There were no transfers between fair value hierarchy levels during the year. b) Derivative Financial Instruments The derivative financial assets and liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value. The following tables summarize the change in fair value for the respective years: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income Gain/(Loss) ​ 2019 ​ 2018 ​ 2017 ​ Statement Presentation Equity Swaps ​ $ (308) ​ $ 210 ​ $ (184) G&A expense Electricity Swaps ​ — ​ — ​ 639 Operating expense Commodity Derivative Instruments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ (70,481) ​ 114,822 ​ (5,445) Commodity derivative Gas ​ (10,944) ​ 9,234 ​ 11,174 instruments Total Unrealized Gain/(Loss) ​ $ (81,733) ​ $ 124,266 ​ $ 6,184 ​ ​ ​ The following table summarizes the effect of Enerplus’ commodity derivative instruments on the Consolidated Statements of Income/(Loss): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Change in fair value gain/(loss) ​ $ (81,425) ​ $ 124,056 ​ $ 5,729 Net realized cash gain/(loss) ​ 15,354 ​ (35,824) ​ 8,581 Commodity derivative instruments gain/(loss) ​ $ (66,071) ​ $ 88,232 ​ $ 14,310 ​ The following table summarizes the fair values at the respective year ends: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ December 31, 2018 ​ ​ Assets ​ Liabilities ​ ​ Assets ​ Liabilities ($ thousands) Current Current ​ Current ​ Long-term Current Equity Swaps ​ $ — ​ $ 2,217 ​ $ — ​ $ — ​ $ 1,909 Commodity Derivative Instruments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ 10,570 ​ 517 ​ 48,314 ​ 32,220 ​ — Gas ​ — ​ — ​ 10,944 ​ — ​ — Total ​ $ 10,570 ​ $ 2,734 ​ $ 59,258 ​ $ 32,220 ​ $ 1,909 ​ c) Risk Management In the normal course of operations, Enerplus is exposed to various market risks, including commodity prices, foreign exchange, interest rates and equity prices, credit risk and liquidity risk. i) Market Risk Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk. Commodity Price Risk: Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes. The following tables summarize Enerplus’ price risk management positions at February 20, 2020: Crude Oil Instruments: ​ ​ ​ ​ ​ ​ Instrument Type (1)(2) bbls/day US$/bbl ​ ​ ​ ​ ​ Jan 1, 2020 – Jan 31, 2020 ​ ​ ​ ​ WTI Swap ​ 5,000 ​ 57.05 WTI Purchased Put ​ 16,000 ​ 57.50 WTI Sold Put ​ 16,000 ​ 46.88 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) WTI – Brent Swap (Sale) ​ 4,400 ​ (3.98) WCS Differential Swap ​ 1,000 ​ (19.25) ​ ​ ​ ​ ​ Feb 1, 2020 – Mar 31, 2020 ​ ​ ​ ​ WTI Swap ​ 10,000 ​ 54.56 WTI Purchased Put ​ 16,000 ​ 57.50 WTI Sold Put ​ 16,000 ​ 46.88 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) WTI – Brent Swap (Sale) ​ 4,400 ​ (3.98) WCS Differential Swap ​ 1,000 ​ (19.25) ​ ​ ​ ​ ​ Apr 1, 2020 – Jun 30, 2020 ​ ​ ​ ​ WTI Swap ​ 12,000 ​ 55.23 WTI Purchased Put ​ 16,000 ​ 57.50 WTI Sold Put ​ 16,000 ​ 46.88 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) WTI – Brent Swap (Sale) ​ 4,400 ​ (3.98) ​ ​ ​ ​ ​ Jul 1, 2020 – Sep 30, 2020 ​ ​ ​ ​ WTI Swap ​ 2,000 ​ 57.18 WTI Purchased Put ​ 21,000 ​ 57.20 WTI Sold Put ​ 21,000 ​ 47.14 WTI Sold Call ​ 5,000 ​ 65.00 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) ​ ​ ​ ​ ​ Oct 1, 2020 – Dec 31, 2020 ​ ​ ​ ​ WTI Purchased Put ​ 21,000 ​ 57.20 WTI Sold Put ​ 21,000 ​ 47.14 WTI Sold Call ​ 5,000 ​ 65.00 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) (1) Transactions with a common term have been aggregated and presented as the weighted average price/bbl before premiums. (2) The total average deferred premium on outstanding hedges is US $1.69 /bbl from January 1, 2020 to December 31, 2020. Foreign Exchange Risk: Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, U.S. dollar denominated senior notes, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a significant portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At December 31, 2019, Enerplus did not have any foreign exchange derivatives outstanding. Interest Rate Risk: At December 31, 2019, all of Enerplus’ debt was based on fixed interest rates, and Enerplus did not have any interest rate derivatives outstanding. Equity Price Risk: Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps maturing in 2020 and has effectively fixed the future settlement cost on 264,000 shares at a weighted average price of $17.82 per share. ii) Credit Risk Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables. Enerplus mitigates credit risk through credit management techniques, including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis. Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At December 31, 2019, approximately 77% of Enerplus’ marketing receivables were with companies considered investment grade. Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts off future payments or seeking other remedies including legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus’ allowance for doubtful accounts balance at December 31, 2019 was $3.7 million (December 31, 2018 – $3.9 million). iii) Liquidity Risk & Capital Management Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt (net of cash and cash equivalents) and shareholders’ capital. Enerplus’ objective is to provide adequate short and longer term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas assets and planned investment opportunities. Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, share repurchases, access to capital markets, as well as acquisition and divestment activity. At December 31, 2019, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	16) COMMITMENTS AND CONTINGENCIES a) Commitments Enerplus has the following minimum annual commitments, excluding operating leases which are recorded in the lease liability (see Note 9): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Minimum Annual Commitment Each Year ​ ​ ​ ($ thousands) ​ Total ​ 2020 ​ 2021 ​ 2022 ​ 2023 ​ 2024 ​ Thereafter Senior notes (1) $ ​ 606,633 ​ $ 105,998 ​ $ 105,998 ​ $ 130,680 ​ $ 104,700 ​ $ 104,699 ​ $ 54,558 Transportation commitments ​ ​ 313,197 ​ 34,829 ​ ​ 31,651 ​ ​ 29,271 ​ ​ 28,981 ​ ​ 28,719 ​ ​ 159,746 Processing commitments ​ 12,663 ​ 3,174 ​ ​ 1,519 ​ ​ 1,519 ​ ​ 1,519 ​ ​ 1,519 ​ ​ 3,413 Total commitments (2)(3) $ ​ 932,493 ​ $ 144,001 ​ $ 139,168 ​ $ 161,470 ​ $ 135,200 ​ $ 134,937 ​ $ 217,717 (1) Interest payments have not been included. (2) Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment. (3) US$ commitments have been converted to CDN$ using the December 31, 2019 foreign exchange rate of 1.2990 . 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, 2019
GEOGRAPHICAL INFORMATION
GEOGRAPHICAL INFORMATION	17) GEOGRAPHICAL INFORMATION ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As at and for the year ended December 31, 2019 ($ thousands) Canada U.S. Total Oil and natural gas sales, net of royalties ​ $ 177,299 ​ $ 1,077,507 ​ $ 1,254,806 Depletion, depreciation and accretion ​ ​ 59,936 ​ ​ 296,894 ​ ​ 356,830 Property, plant and equipment ​ 259,514 ​ 1,308,092 ​ 1,567,606 Deferred income tax asset ​ ​ 185,880 ​ ​ 186,622 ​ ​ 372,502 Goodwill ​ ​ — ​ ​ 194,015 ​ ​ 194,015 Long term income tax receivable ​ — ​ 13,852 ​ 13,852 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As at and for the year ended December 31, 2018 ($ thousands) Canada U.S. Total Oil and natural gas sales, net of royalties ​ $ 198,263 ​ $ 1,094,473 ​ $ 1,292,736 Depletion, depreciation and accretion ​ ​ 58,333 ​ ​ 245,941 ​ ​ 304,274 Property, plant and equipment ​ 262,159 ​ 1,044,912 ​ 1,307,071 Deferred income tax asset ​ ​ 196,903 ​ ​ 268,221 ​ ​ 465,124 Goodwill ​ 451,121 ​ ​ 203,678 ​ ​ 654,799 Long term income tax receivable ​ — ​ 27,195 ​ 27,195 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As at and for the year ended December 31, 2017 ($ thousands) Canada U.S. Total Oil and natural gas sales, net of royalties ​ $ 227,031 ​ $ 693,662 ​ $ 920,693 Depletion, depreciation and accretion ​ ​ 89,936 ​ ​ 160,838 ​ ​ 250,774 Property, plant and equipment ​ 246,604 ​ 653,427 ​ 900,031 Deferred income tax asset ​ ​ 200,818 ​ ​ 369,119 ​ ​ 569,937 Goodwill ​ 451,121 ​ 187,757 ​ 638,878 Long term income tax receivable ​ — ​ 50,108 ​ 50,108 ​

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2019
SUPPLEMENTAL CASH FLOW INFORMATION
SUPPLEMENTAL CASH FLOW INFORMATION	​ 18) SUPPLEMENTAL CASH FLOW INFORMATION ​ a) Changes in Non-Cash Operating Working Capital ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) ​ December 31, 2019 ​ December 31, 2018 ​ December 31, 2017 Accounts receivable ​ $ 8,493 ​ $ (45,385) ​ $ (66,860) Other assets ​ 4,475 ​ (3,026) ​ (154) Accounts payable ​ (11,005) ​ 44,952 ​ 31,982 ​ ​ $ 1,963 ​ $ (3,459) ​ $ (35,032) ​ b) Changes in Other Non-Cash Working Capital ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 December 31, 2017 Non-cash financing activities (1) ​ $ (178) ​ $ (26) ​ $ 16 Non-cash investing activities (2) ​ $ 17,682 ​ $ (3,753) ​ $ 1,523 (1) Relates to changes in dividends payable and included in dividends on the Consolidated Statements of Cash Flows. (2) Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Consolidated Statements of Cash Flows. ​ c) Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 ​ December 31, 2018 December 31, 2017 Income taxes paid/(received) ​ $ (71,890) ​ $ (481) ​ $ 2,640 Interest paid ​ $ 33,991 ​ $ 36,161 ​ $ 38,149 ​

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
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 Currency These Consolidated Financial Statements are presented in Canadian dollars, which is Enerplus’ reporting currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand unless otherwise indicated.
Use of Estimates	ii. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Actual results could differ from these estimates, and changes in estimates are recorded when known. Significant estimates made by management include: 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. Enerplus uses the most current information available and exercises judgment in making these estimates and assumptions. In the opinion of management, these Consolidated Financial Statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies.
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 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. ​ The acquisition method of accounting is used to account for acquisitions that meet the definition of a business under U.S. GAAP. The cost of an acquisition is measured as the fair value of the assets transferred, equity instruments issued and liabilities incurred or assumed at the acquisition date. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.
Revenue	b) Revenue Revenue from the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers, net of sales taxes. Enerplus recognizes revenue when it satisfies a performance obligation by transferring control of the product to a customer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the contractual delivery points. ​ Enerplus evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, management considers if Enerplus retains control of the product being delivered to the end customer. As part of this assessment, management considers whether the Company retains the economic benefits associated with the good being delivered to the end customer. Management also considers whether the Company has the primary responsibility for the delivery of the product, the ability to establish prices or the inventory risk. If Enerplus acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction.
Transportation	c) Transportation Enerplus generally sells oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which the Company sells crude oil or natural gas at the wellhead and collects a price, net of the transportation incurred by the purchaser. In this case, sales are recorded at the price received from the purchaser, net of transportation costs. Under the other arrangement, Enerplus sells crude oil or natural gas at a specific delivery point, pays transportation to a third party and receives proceeds from the purchaser with no transportation deduction. In this case, transportation costs are recorded as transportation expense on the Consolidated Statements of Income/(Loss). Due to these two distinct selling arrangements, Enerplus’ computed realized prices, before the impact of derivative instruments, include revenues which are reported under two separate bases.
Oil and Natural Gas Properties	d) Oil and Natural Gas Properties Enerplus uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs incurred in finding 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 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 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. Enerplus limits capitalized costs of proved and unproved 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 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”). 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 oil and natural gas prices subsequently increase the ceiling. Under full cost accounting rules, divestitures of oil and natural gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized.
Other Capital Assets	e) Other Capital Assets Other capital assets are recorded at historical cost, net of depreciation, and include furniture, fixtures, leasehold improvements, computer equipment and Company owned line-fill in third party pipelines. Line fill is recorded at lower of cost and net realizable value. Depreciation is calculated on a straight-line basis over the estimated useful life of the respective asset. The cost of repairs and maintenance is expensed as incurred.
Cash and Cash Equivalents	f) Cash and Cash Equivalents Cash and cash equivalents includes cash and highly liquid investments with maturities of less than 90 days.
Goodwill	g) Goodwill Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. The portion of goodwill that relates to U.S. operations fluctuates due to changes in foreign exchange rates. Goodwill is stated at cost less impairment and is not amortized. Goodwill is not deductible for income tax purposes. Goodwill is assessed for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. Enerplus first performs a qualitative assessment to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value, quantitative impairment tests are performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied 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. For the purposes of goodwill impairment testing, Enerplus has two reporting units.
Asset Retirement Obligations	h) Asset Retirement Obligations Enerplus’ oil and natural gas operating activities give rise to dismantling, decommissioning and site remediation activities. Enerplus recognizes a liability for the estimated present value of the future asset retirement obligation liability at each balance sheet date. Upon recognition, the liability is recorded at its estimated fair value. The associated asset retirement cost is capitalized and amortized over the same period as the underlying asset. Changes in the estimated liability and related asset retirement cost can arise as a result of revisions in the estimated amount or timing of cash flows. Depletion of asset retirement costs and increases in asset retirement obligations resulting from the passage of time are recorded to depreciation, depletion and accretion and charged against net income in the Consolidated Statements of Income/(Loss).
Leases	i) Leases Enerplus determines if an arrangement is a lease at inception. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating and finance leases are included in right-of-use (“ROU”) assets and the associated lease liability in the Consolidated Balance Sheet. ​ ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Lease liabilities are recognized at lease commencement date based on the present value of remaining lease payments over the lease term. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for lease incentives received. Enerplus uses the implicit rate when readily available, or uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is reasonably certain that it will exercise those options. Lease expense for operating leases is recognized on a straight-line basis over the lease term. ​ Lease agreements contain both lease and non-lease components which are accounted for separately. For certain equipment leases, a portfolio approach is applied to effectively account for the ROU assets and liabilities. Prior to January 1, 2019, the Company applied lease accounting in accordance with ASC 840.
Income Tax	j) Income Tax Enerplus uses the liability method of accounting for income taxes. Deferred income tax assets and liabilities are recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax assets are reviewed each period and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. Enerplus considers both positive and negative evidence including historic and expected future taxable income, reversing existing temporary differences and tax basis carry forward periods in making this assessment. A valuation allowance is removed in any period where available evidence indicates all or a portion of the valuation allowance is no longer required. The financial statement effect of an uncertain tax position is recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. Penalties and interest expense related to income tax are recognized in income tax expense.
Financial Instruments	k) Financial Instruments i. Fair Value Measurements Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. For financial instruments carried at fair value, and when disclosing the fair value of financial instruments on certain non-financial items, inputs used in determining the fair value are characterized according to the following fair value hierarchy: ● ● ● Subsequent measurement is based on classification of the financial instrument into one of the following five categories: held-for-trading, held-to-maturity, available-for-sale, loans and receivables or other financial liabilities. ii. Non-derivative financial instruments The carrying amount of cash, accounts receivable, income tax receivable, accounts payable, dividends payable and bank credit facilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of the senior notes are considered a level 2 fair value measurement. The fair value of debt has been disclosed in Note 15. iii. Derivative financial instruments Enerplus enters into financial derivative contracts in order to manage its exposure to market risks from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. Enerplus has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a result, all financial derivative contracts are classified as held-for-trading and are recorded at fair value based on a Level 2 designation, with changes in fair value recorded in net income. The fair values of these derivative instruments are generally based on an estimate of the amounts that would be paid or received to settle these instruments at the balance sheet date. Enerplus’ accounting policy is to not offset the fair values of its financial derivative assets and liabilities. Realized gains and losses from commodity price risk management activities are recognized in income when the contract is settled. Unrealized gains and losses on commodity price risk management activities are recognized in income based on the changes in fair value of the contracts at the end of the respective reporting period. Enerplus’ crude oil, natural gas and natural gas liquids physical delivery purchase and sales contracts qualify as normal purchases and sales as they are entered into and held for the purpose of receipt or delivery of products in accordance with the Company’s expected purchase, sale or usage requirements. As such, these contracts are not considered derivative financial instruments. Settlements on these physical contracts are recognized in net income over the term of the contracts as they occur.
Foreign Currency	l) Foreign Currency i. Foreign currency transactions Transactions denominated in foreign currencies are translated to the functional currency of the entity (Canadian dollars) using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency of the entity using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Foreign currency differences arising on translation are recognized in net income in the period in which they arise. ii. Foreign operations Assets and liabilities of Enerplus’ U.S. operations, which has a U.S. dollar functional currency, are translated into Canadian dollars at period end exchange rates while revenues and expenses are translated using average rates for the period. Gains and losses from the translation are deferred and included in the cumulative translation adjustment which is recorded in accumulated other comprehensive income.
Share-Based Compensation	m) Share-Based Compensation Enerplus’ share-based compensation plans include equity-settled Restricted Share Unit (“RSU”) and Performance Share Unit (“PSU”) awards made pursuant to its Share Award Incentive Plan (“SAIP”). The Company is authorized to issue up to 3.8% 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 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. 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 fair value of the respective awards. The grant date fair value is based on the Company’s 20 -day volume weighted average price on December 31 prior to the grant date. The fair value for the PSUs is adjusted for the outcome of the performance condition. Share-based compensation charges are recorded on the Consolidated Statements of Income/(Loss) with an offset to paid-in capital. Each period, management performs an estimate of the PSU plan multiplier. Any differences that arise between the actual multiplier on plan settlement and management’s estimate is recorded to share-based compensation. On settlement of these plans, amounts previously recorded to paid-in capital are reclassified to share capital. Enerplus recognizes a liability with respect to its cash-settled long-term incentive plans based on their estimated fair value. The liability is re-measured at each reporting date and at settlement date with any changes in the fair value recorded as share-based compensation, included in general and administrative expense. ii. Stock options Enerplus’ Stock Option Plan was suspended in 2014 and is now closed. All options outstanding under the plan are fully vested and the expense has been fully recognized. The remaining outstanding stock options will expire in 2020.
Net Income Per Share	n) Net Income/(Loss) Per Share Basic net income/(loss) per common share is computed by dividing net income/(loss) by the weighted average number of common shares outstanding during the period. For the diluted net income per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income. The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all stock options and outstanding RSU’s and PSU’s would be used to repurchase common shares at the average market price.
Contingencies	o) Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recognized when it is probable that a liability has been incurred and the amount can be reasonably estimated. Contingencies are adjusted as additional information becomes available or circumstances change.
Accounting Changes and Recent Pronouncements Issued	p) Accounting Changes and Recent Pronouncements Issued i. Recently adopted accounting standards Except for the changes below, the Company has consistently applied the accounting policies to all periods presented in these Consolidated Financial Statements. ​ Enerplus adopted ASC 842 Leases effective January 1, 2019 using the modified retrospective method, with ASC 842 applied to all contracts not yet completed as of the date of adoption with the cumulative effect on comparative periods reflected as an adjustment to retained earnings, if applicable. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases, while accounting for finance leases and lessor accounting remained unchanged. ​ Enerplus elected the practical expedient related to land easements , allowing it to carry forward its accounting treatment for land easements on existing agreements. ​ The impacts of the adoption of ASC 842 as at January 1, 2019 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As reported as at ​ ​ ​ ​ ​ Balance as at ($ thousands) ​ ​ December 31, 2018 ​ ​ Adjustments ​ ​ January 1, 2019 Right-of-use assets $ — ​ $ 50,193 $ 50,193 Current portion of lease liabilities ​ ​ — ​ ​ (10,648) ​ ​ (10,648) Lease liabilities ​ — ​ ​ (39,545) ​ (39,545) Total ​ $ — ​ $ — ​ $ — ​ The standard did not materially impact the Company’s Consolidated Statement of Income/(Loss) or Consolidated Statements of Cash Flows. ​ ii. Future accounting changes In future accounting periods, the Company will adopt the following Accounting Standards Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”): In June 2016 , the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326) . The ASU changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 , and will be applied using a modified retrospective approach. Enerplus has not early adopted the standard and does not expect a material impact to the Consolidated Financial Statements. ​ In January 2017 , the FASB issued ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350) . This standard eliminates Step 2 of the goodwill impairment test, and requires a goodwill impairment charge for the amount that the carrying amount of the reporting unit exceeds the reporting unit’s fair value. The updated guidance is effective January 1, 2020 and will be applied prospectively . Enerplus has not early adopted this ASU. The amended standard simplifies the goodwill impairment test and will impact the amount of any impairment recorded post adoption.

SIGNIFICANT ACCOUNTING POLICI_3

SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2019
SIGNIFICANT ACCOUNTING POLICIES
Schedule of impact of the adoption of ASC 842	​ The impacts of the adoption of ASC 842 as at January 1, 2019 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As reported as at ​ ​ ​ ​ ​ Balance as at ($ thousands) ​ ​ December 31, 2018 ​ ​ Adjustments ​ ​ January 1, 2019 Right-of-use assets $ — ​ $ 50,193 $ 50,193 Current portion of lease liabilities ​ ​ — ​ ​ (10,648) ​ ​ (10,648) Lease liabilities ​ — ​ ​ (39,545) ​ (39,545) Total ​ $ — ​ $ — ​ $ —

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2019
ACCOUNTS RECEIVABLE
Schedule of accounts receivable	​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Accrued revenue ​ $ 142,048 ​ $ 118,821 Accounts receivable – trade ​ 37,736 ​ 30,252 Allowance for doubtful accounts ​ (3,665) ​ (3,867) Total accounts receivable, net of allowance for doubtful accounts ​ $ 176,119 ​ $ 145,206

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT ("PP&E") (Tables)	12 Months Ended
	Dec. 31, 2019
PROPERTY, PLANT AND EQUIPMENT ("PP&E")
Schedule of property, plant and equipment	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accumulated Depletion, ​ ​ As at December 31, 2019 ​ ​ ​ ​ Depreciation, ​ ​ ​ ($ thousands) ​ Cost ​ and Impairment ​ Net Book Value Oil and natural gas properties (1) ​ $ 15,088,724 ​ $ (13,541,362) ​ $ 1,547,362 Other capital assets ​ 125,265 ​ (105,021) ​ 20,244 Total PP&E ​ $ 15,213,989 ​ $ (13,646,383) ​ $ 1,567,606 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accumulated Depletion, ​ ​ As at December 31, 2018 ​ ​ ​ ​ Depreciation, ​ ​ ​ ($ thousands) ​ Cost and Impairment ​ Net Book Value Oil and natural gas properties (1) ​ $ 14,773,082 ​ $ (13,479,141) ​ $ 1,293,941 Other capital assets ​ 115,510 ​ (102,380) ​ 13,130 Total PP&E ​ $ 14,888,592 ​ $ (13,581,521) ​ $ 1,307,071 (1) All of the Company’s unproved properties are included in the full cost pool.

IMPAIRMENT (Tables)

IMPAIRMENT (Tables)	12 Months Ended
	Dec. 31, 2019
IMPAIRMENT
Schedule of 12-month average trailing benchmark prices and exchange rates used in the ceiling tests	The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling test as at December 31, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ U.S. Henry ​ ​ ​ ​ WTI Crude Oil ​ Edm Light Crude ​ Hub Gas ​ Exchange Rate Period ​ US$/bbl ​ CDN$/bbl ​ US$/Mcf ​ US$/CDN 2019 ​ $ 55.85 ​ $ 66.73 ​ $ 2.58 ​ ​ 1.33 2018 ​ 65.56 ​ ​ 69.58 ​ ​ 3.10 ​ ​ 1.28 2017 ​ 51.34 ​ ​ 63.57 ​ ​ 2.98 ​ ​ 1.30

ACCOUNTS PAYABLE (Tables)

ACCOUNTS PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2019
ACCOUNTS PAYABLE
Schedule of accounts payable	​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Accrued payables ​ $ 105,928 ​ $ 115,388 Accounts payable – trade ​ 185,612 ​ 174,657 Total accounts payable ​ $ 291,540 ​ $ 290,045

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2019
DEBT
Schedule of debt	​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Current: ​ ​ ​ ​ ​ ​ Senior notes ​ $ 105,998 ​ $ 60,001 Long-term: ​ ​ ​ ​ ​ ​ Bank credit facility ​ $ — ​ $ — Senior notes ​ 500,635 ​ 636,849 Total debt ​ $ 606,633 ​ $ 696,850 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Original ​ Remaining CDN$ Carrying ​ ​ ​ ​ ​ ​ Coupon ​ Principal ​ Principal ​ Value Issue Date ​ Interest Payment Dates ​ Principal Repayment ​ Rate ​ ($ thousands) ​ ($ thousands) ​ ($ thousands) September 3, 2014 ​ March 3 and Sept 3 ​ 5 equal annual installments beginning September 3, 2022 ​ 3.79% ​ US$200,000 ​ US$105,000 ​ $ 136,395 May 15, 2012 May 15 and Nov 15 Bullet payment on May 15, 2022 4.40% ​ US$20,000 US$20,000 ​ 25,980 May 15, 2012 May 15 and Nov 15 5 equal annual installments beginning May 15, 2020 4.40% ​ US$355,000 US$298,000 ​ 387,102 June 18, 2009 June 18 and Dec 18 2 equal annual installments on June 18, 2020 and 2021 7.97% ​ US$225,000 US$44,000 ​ 57,156 ​ ​ ​ ​ ​ ​ ​ ​ Total carrying value ​ $ 606,633

ASSET RETIREMENT OBLIGATION (Ta

ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2019
ASSET RETIREMENT OBLIGATION
Schedule of changes in asset retirement obligation	​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 Balance, beginning of year ​ $ 126,112 ​ $ 117,736 Change in estimates ​ 23,362 ​ 16,755 Property acquisition and development activity ​ 2,068 ​ 1,565 Divestments ​ (2,760) ​ (4,585) Settlements ​ (16,715) ​ (11,263) Accretion expense ​ 5,982 ​ 5,904 Balance, end of year ​ $ 138,049 ​ $ 126,112

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2019
LEASES
Summary of leases	​ ​ ​ ​ ​ ($ thousands) ​ At December 31, 2019 Assets ​ ​ ​ Operating right-of-use assets ​ $ 48,729 Liabilities ​ ​ ​ Current operating lease liabilities ​ $ 17,541 Non-current operating lease liabilities ​ ​ 35,530 Total lease liabilities ​ $ 53,071 ​ ​ ​ ​ Weighted average remaining lease term (years) ​ ​ ​ Operating leases ​ ​ 4.3 ​ ​ ​ ​ Weighted average discount rate ​ ​ ​ Operating leases ​ ​ 4.1% ​ ​ ​ ​ ​ ​ ($ thousands) 2019 Operating lease cost $ 19,483 Short-term lease cost 15,332 Sublease income ​ (1,072) Total $ 33,743 ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) ​ ​ December 31, 2019 Cash amounts paid to settle lease liabilities: ​ ​ ​ Operating cash flow used for operating leases ​ $ 18,637 Right-of-use assets obtained in exchange for lease obligations: ​ ​ Operating leases ​ $ 20,818
Summary of maturity of leases	​ ​ ​ ​ ​ Maturity of Lease Liabilities ​ ($ thousands) ​ Operating Leases 2020 ​ $ 19,371 2021 ​ 14,098 2022 ​ 7,674 2023 ​ 6,706 2024 ​ ​ 6,200 After 2024 ​ 3,979 Total lease payments ​ $ 58,028 Less imputed interest ​ ​ (4,957) Total discounted lease payments ​ $ 53,071 Current portion of lease liabilities ​ $ 17,541 Non-current portion of lease liabilities ​ $ 35,530

OIL AND NATURAL GAS SALES (Tabl

OIL AND NATURAL GAS SALES (Tables)	12 Months Ended
	Dec. 31, 2019
OIL AND NATURAL GAS SALES
Tabular disclosure of revenue from oil and natural gas sales during the period	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Oil and natural gas sales ​ $ 1,572,955 ​ $ 1,610,899 ​ $ 1,141,770 Royalties (1) ​ (318,149) ​ (318,163) ​ (221,077) Oil and natural gas sales, net of royalties ​ $ 1,254,806 ​ $ 1,292,736 ​ $ 920,693 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). ​ Oil and natural gas revenue by country and by product for the years ended December 31, 2019 and 2018 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2019 ​ ​ Total revenue, net ​ ​ ​ ​ ​ Natural ​ ​ Natural gas ​ ​ ​ ($ thousands) ​ ​ of royalties (1) ​ ​ Crude oil (2) ​ ​ gas (2) ​ ​ liquids (2) ​ ​ Other (3) Canada $ 177,299 ​ $ 145,814 $ 21,776 $ 7,158 $ 2,551 United States ​ 1,077,507 ​ ​ 847,182 ​ 215,963 ​ 14,355 ​ 7 Total ​ $ 1,254,806 ​ $ 992,996 ​ $ 237,739 ​ $ 21,513 ​ $ 2,558 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 ​ ​ Total revenue, net ​ ​ ​ ​ ​ Natural ​ ​ Natural gas ​ ​ ​ ($ thousands) ​ ​ of royalties (1) ​ ​ Crude oil (2) ​ ​ gas (2) ​ ​ liquids (2) ​ ​ Other (3) Canada $ 198,263 ​ $ 148,949 $ 32,109 $ 14,075 $ 3,130 United States ​ 1,094,473 ​ ​ 834,146 ​ 236,825 ​ 23,502 ​ — Total ​ $ 1,292,736 ​ $ 983,095 ​ $ 268,934 ​ $ 37,577 ​ $ 3,130 (1) Royalties above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss). (2) U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties. (3) Includes third party processing income. ​

GENERAL AND ADMINISTRATIVE EX_2

GENERAL AND ADMINISTRATIVE EXPENSE (Tables)	12 Months Ended
	Dec. 31, 2019
GENERAL AND ADMINISTRATIVE EXPENSE
Schedule of General and Administrative Expense	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 General and administrative expense $ 49,532 ​ $ 49,943 ​ $ 50,544 Share-based compensation expense ​ 23,321 ​ 25,840 ​ 23,757 General and administrative expense (1) $ 72,853 ​ $ 75,783 ​ $ 74,301 (1) Includes cash and non-cash amounts.

FOREIGN EXCHANGE (Tables)

FOREIGN EXCHANGE (Tables)	12 Months Ended
	Dec. 31, 2019
FOREIGN EXCHANGE
Schedule of foreign exchange (gain)/loss	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Realized: ​ ​ ​ ​ ​ ​ ​ ​ ​ Foreign exchange (gain)/loss ​ $ (87) ​ $ 523 ​ $ 1,495 Translation of U.S. dollar cash held in Canada (gain)/loss ​ ​ 8,794 ​ ​ (19,630) ​ ​ 10,978 Unrealized: ​ ​ ​ ​ ​ ​ ​ ​ ​ Translation of U.S. dollar debt and working capital (gain)/loss ​ (34,085) ​ 58,628 ​ (42,623) Foreign exchange (gain)/loss ​ $ (25,378) ​ $ 39,521 ​ $ (30,150)

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
INCOME TAXES
Schedule of the Company's provision for income taxes	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Current tax ​ ​ ​ ​ ​ ​ ​ ​ ​ Canada ​ $ (13,910) ​ $ (400) ​ $ (407) United States ​ (19,504) ​ (26,693) ​ (47,550) Current tax expense/(recovery) ​ ​ (33,414) ​ ​ (27,093) ​ ​ (47,957) Deferred tax ​ ​ ​ ​ ​ ​ ​ ​ ​ Canada ​ $ 11,023 ​ $ 3,915 ​ $ (17,127) United States ​ 70,252 ​ 126,389 ​ 147,072 Deferred tax expense/(recovery) ​ ​ 81,275 ​ ​ 130,304 ​ ​ 129,945 Income tax expense/(recovery) ​ $ 47,861 ​ $ 103,211 ​ $ 81,988
Schedule of reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Income/(loss) before taxes ​ ​ ​ ​ ​ ​ ​ ​ ​ Canada ​ $ (437,571) ​ $ 104,204 ​ $ 146,953 United States ​ ​ 225,712 ​ 377,286 ​ 172,033 Total income/(loss) before taxes ​ ​ (211,859) ​ ​ 481,490 ​ ​ 318,986 Canadian statutory rate ​ ​ 26.50% ​ 27.00% ​ 27.00% Expected income tax expense/(recovery) ​ $ (56,143) ​ $ 130,002 ​ $ 86,126 Impact on taxes resulting from: ​ ​ ​ ​ ​ ​ ​ ​ ​ Foreign and statutory rate differences ​ $ 27,446 ​ $ (23,859) ​ $ 157,320 Share-based compensation ​ ​ (5,398) ​ ​ (18,102) ​ ​ 5,067 Capital gains and losses ​ ​ 3,994 ​ 7,254 ​ (6,337) Change in valuation allowance ​ ​ (22,038) ​ 6,292 ​ (162,992) Amounts in respect of prior periods ​ ​ (19,451) ​ ​ — ​ ​ — Non-deductible goodwill impairment ​ ​ 119,547 ​ ​ — ​ ​ — Other ​ ​ (96) ​ 1,624 ​ 2,804 Income tax expense/(recovery) ​ $ 47,861 ​ $ 103,211 ​ $ 81,988
Schedule of deferred income tax asset (liability)	​ ​ ​ ​ ​ ​ ​ ​ As at December 31 2019 2018 Deferred income tax assets ​ ​ ​ ​ ​ ​ Property, plant and equipment ​ $ 59,896 ​ $ 60,665 Tax loss carry-forwards and other credits ​ 383,600 ​ 429,651 Capital loss carryforwards and other capital items ​ ​ 154,532 ​ ​ 188,409 Asset retirement obligation ​ 33,569 ​ 33,935 Other assets ​ 12,219 ​ 14,099 Deferred income tax assets before valuation allowance ​ ​ 643,816 ​ ​ 726,759 Valuation allowance ​ ​ (169,129) ​ ​ (191,167) Deferred income tax assets, net ​ ​ 474,687 ​ ​ 535,592 Deferred income tax liabilities ​ ​ ​ ​ ​ ​ Property, plant and equipment ​ $ (100,328) ​ $ (46,284) Derivative financial instruments ​ ​ (1,857) ​ ​ (24,184) Total deferred income tax liabilities ​ ​ (102,185) ​ ​ (70,468) Total deferred income tax asset ​ $ 372,502 ​ $ 465,124
Schedule of loss carryforwards and tax credits that can be utilized in future years	​ ​ ​ ​ ​ ​ ​ As at December 31 2019 Expiration Date Canada ​ ​ ​ ​ ​ Capital losses ​ $ 1,170,000 Indefinite Non-capital losses ​ 405,000 2028-2039 United States ​ ​ ​ ​ ​ Net operating losses – prior to 2018 ​ $ 889,000 ​ 2030-2039 Net operating losses – 2018 and thereafter ​ ​ 102,000 Indefinite
Schedule of changes in the balance of Enerplus' unrecognized tax benefits	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 ​ 2017 Balance, beginning of year ​ $ 13,300 ​ $ 13,300 ​ $ 13,300 Settlements ​ (13,300) ​ — ​ — Balance, end of year ​ $ — ​ $ 13,300 ​ $ 13,300
Summary of the taxation years, by jurisdiction, that remain subject to examination by the taxation authorities	​ ​ ​ ​ Jurisdiction Taxation Years Canada – Federal 2014-2019 United States – Federal 2016-2019

SHAREHOLDERS' EQUITY (Tables)

SHAREHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2019
SHAREHOLDERS' EQUITY
Schedule of share capital	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2019 ​ 2018 ​ 2017 Authorized: unlimited number of common shares Issued: (thousands) Shares Amount Shares Amount Shares Amount Balance, beginning of year 239,411 ​ $ 3,337,608 242,129 ​ $ 3,386,946 240,483 ​ $ 3,365,962 Issued for cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Purchase of common shares under Normal Course Issuer Bid ​ (18,231) ​ ​ (253,920) ​ (5,925) ​ ​ (82,596) ​ — ​ — Stock Option Plan — ​ ​ — 668 ​ 9,138 — ​ — Non-cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Share-based compensation – settled (1) 564 ​ 4,406 2,539 ​ 23,389 1,646 ​ 20,984 Stock Option Plan – exercised ​ — ​ ​ — ​ — ​ ​ 731 ​ — ​ ​ — Balance, end of year 221,744 ​ $ 3,088,094 239,411 ​ $ 3,337,608 242,129 ​ $ 3,386,946
Summary of share-based compensation expense which is included in General and Administrative expense on the Consolidated Income Statements	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term incentive plans expense ​ $ 689 ​ $ 133 ​ $ 997 Non-Cash: ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term incentive plans expense ​ ​ 22,324 ​ ​ 25,917 ​ ​ 22,576 Equity swap (gain)/loss ​ 308 ​ (210) ​ 184 Share-based compensation expense ​ $ 23,321 ​ $ 25,840 ​ $ 23,757
Schedule of PSU, RSU and DSU activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the year ended December 31, 2019 ​ Cash-settled LTI Plans ​ Equity-settled LTI Plans ​ Total (thousands of units) DSU PSU (1) RSU ​ Balance, beginning of year 391 ​ 1,371 ​ 1,753 ​ 3,515 Granted 99 ​ 817 ​ 862 ​ 1,778 Vested (68) ​ — ​ (1,007) ​ (1,075) Forfeited — ​ (49) ​ (77) ​ (126) Balance, end of year ​ 422 ​ 2,139 ​ 1,531 ​ 4,092
Schedule of cumulative share-based compensation expense recognized to-date	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ At December 31, 2019 ($ thousands, except for years) PSU (1) RSU Total Cumulative recognized share-based compensation expense ​ $ 30,768 ​ $ 13,495 ​ $ 44,263 Unrecognized share-based compensation expense ​ 11,971 ​ 5,582 ​ 17,553 Fair value ​ $ 42,739 ​ $ 19,077 ​ $ 61,816 Weighted-average remaining contractual term (years) ​ 1.7 ​ ​ 1.4 ​ ​ ​ (1) Includes estimated performance multipliers.
Schedule of the stock option plan activity for the period	​ ​ ​ ​ ​ ​ ​ ​ Number of Options Weighted Average Year ended December 31, 2019 ​ (thousands) ​ Exercise Price Options outstanding, beginning of year 4,131 ​ $ 17.12 Exercised — ​ — Forfeited (96) ​ 15.22 Expired (1,928) ​ 20.35 Options outstanding and exercisable, end of year 2,107 ​ $ 14.24
Schedule of net income/(loss) per share	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (thousands, except per share amounts) 2019 2018 2017 Net income/(loss) ​ $ (259,720) ​ $ 378,279 ​ $ 236,998 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average shares outstanding – Basic ​ 231,334 ​ 244,076 ​ 241,929 Dilutive impact of share-based compensation (1) ​ — ​ 3,185 ​ 5,945 Weighted average shares outstanding – Diluted ​ ​ 231,334 ​ ​ 247,261 ​ ​ 247,874 Net income/(loss) per share ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ (1.12) ​ $ 1.55 ​ $ 0.98 Diluted ​ $ (1.12) ​ $ 1.53 ​ $ 0.96

FINANCIAL INSTRUMENTS AND RIS_2

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (Tables)	12 Months Ended
	Dec. 31, 2019
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Schedule of change in fair value of derivative financial instruments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income Gain/(Loss) ​ 2019 ​ 2018 ​ 2017 ​ Statement Presentation Equity Swaps ​ $ (308) ​ $ 210 ​ $ (184) G&A expense Electricity Swaps ​ — ​ — ​ 639 Operating expense Commodity Derivative Instruments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ (70,481) ​ 114,822 ​ (5,445) Commodity derivative Gas ​ (10,944) ​ 9,234 ​ 11,174 instruments Total Unrealized Gain/(Loss) ​ $ (81,733) ​ $ 124,266 ​ $ 6,184 ​ ​
Summary of the income statement effects of Enerplus' commodity derivative instruments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) 2019 2018 2017 Change in fair value gain/(loss) ​ $ (81,425) ​ $ 124,056 ​ $ 5,729 Net realized cash gain/(loss) ​ 15,354 ​ (35,824) ​ 8,581 Commodity derivative instruments gain/(loss) ​ $ (66,071) ​ $ 88,232 ​ $ 14,310
Summary of the fair value of derivative financial instruments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ December 31, 2018 ​ ​ Assets ​ Liabilities ​ ​ Assets ​ Liabilities ($ thousands) Current Current ​ Current ​ Long-term Current Equity Swaps ​ $ — ​ $ 2,217 ​ $ — ​ $ — ​ $ 1,909 Commodity Derivative Instruments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ 10,570 ​ 517 ​ 48,314 ​ 32,220 ​ — Gas ​ — ​ — ​ 10,944 ​ — ​ — Total ​ $ 10,570 ​ $ 2,734 ​ $ 59,258 ​ $ 32,220 ​ $ 1,909
Summary of management positions	​ ​ ​ ​ ​ ​ Instrument Type (1)(2) bbls/day US$/bbl ​ ​ ​ ​ ​ Jan 1, 2020 – Jan 31, 2020 ​ ​ ​ ​ WTI Swap ​ 5,000 ​ 57.05 WTI Purchased Put ​ 16,000 ​ 57.50 WTI Sold Put ​ 16,000 ​ 46.88 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) WTI – Brent Swap (Sale) ​ 4,400 ​ (3.98) WCS Differential Swap ​ 1,000 ​ (19.25) ​ ​ ​ ​ ​ Feb 1, 2020 – Mar 31, 2020 ​ ​ ​ ​ WTI Swap ​ 10,000 ​ 54.56 WTI Purchased Put ​ 16,000 ​ 57.50 WTI Sold Put ​ 16,000 ​ 46.88 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) WTI – Brent Swap (Sale) ​ 4,400 ​ (3.98) WCS Differential Swap ​ 1,000 ​ (19.25) ​ ​ ​ ​ ​ Apr 1, 2020 – Jun 30, 2020 ​ ​ ​ ​ WTI Swap ​ 12,000 ​ 55.23 WTI Purchased Put ​ 16,000 ​ 57.50 WTI Sold Put ​ 16,000 ​ 46.88 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) WTI – Brent Swap (Sale) ​ 4,400 ​ (3.98) ​ ​ ​ ​ ​ Jul 1, 2020 – Sep 30, 2020 ​ ​ ​ ​ WTI Swap ​ 2,000 ​ 57.18 WTI Purchased Put ​ 21,000 ​ 57.20 WTI Sold Put ​ 21,000 ​ 47.14 WTI Sold Call ​ 5,000 ​ 65.00 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) ​ ​ ​ ​ ​ Oct 1, 2020 – Dec 31, 2020 ​ ​ ​ ​ WTI Purchased Put ​ 21,000 ​ 57.20 WTI Sold Put ​ 21,000 ​ 47.14 WTI Sold Call ​ 5,000 ​ 65.00 WTI – Brent Swap (Purchase) ​ 4,400 ​ (8.03) (1) Transactions with a common term have been aggregated and presented as the weighted average price/bbl before premiums. (2) The total average deferred premium on outstanding hedges is US $1.69 /bbl from January 1, 2020 to December 31, 2020.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2019
COMMITMENTS AND CONTINGENCIES
Schedule of minimum annual commitments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Minimum Annual Commitment Each Year ​ ​ ​ ($ thousands) ​ Total ​ 2020 ​ 2021 ​ 2022 ​ 2023 ​ 2024 ​ Thereafter Senior notes (1) $ ​ 606,633 ​ $ 105,998 ​ $ 105,998 ​ $ 130,680 ​ $ 104,700 ​ $ 104,699 ​ $ 54,558 Transportation commitments ​ ​ 313,197 ​ 34,829 ​ ​ 31,651 ​ ​ 29,271 ​ ​ 28,981 ​ ​ 28,719 ​ ​ 159,746 Processing commitments ​ 12,663 ​ 3,174 ​ ​ 1,519 ​ ​ 1,519 ​ ​ 1,519 ​ ​ 1,519 ​ ​ 3,413 Total commitments (2)(3) $ ​ 932,493 ​ $ 144,001 ​ $ 139,168 ​ $ 161,470 ​ $ 135,200 ​ $ 134,937 ​ $ 217,717 (1) Interest payments have not been included. (2) Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment. (3) US$ commitments have been converted to CDN$ using the December 31, 2019 foreign exchange rate of 1.2990 .

GEOGRAPHICAL INFORMATION (Table

GEOGRAPHICAL INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2019
GEOGRAPHICAL INFORMATION
Schedule of geographical information	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As at and for the year ended December 31, 2019 ($ thousands) Canada U.S. Total Oil and natural gas sales, net of royalties ​ $ 177,299 ​ $ 1,077,507 ​ $ 1,254,806 Depletion, depreciation and accretion ​ ​ 59,936 ​ ​ 296,894 ​ ​ 356,830 Property, plant and equipment ​ 259,514 ​ 1,308,092 ​ 1,567,606 Deferred income tax asset ​ ​ 185,880 ​ ​ 186,622 ​ ​ 372,502 Goodwill ​ ​ — ​ ​ 194,015 ​ ​ 194,015 Long term income tax receivable ​ — ​ 13,852 ​ 13,852 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As at and for the year ended December 31, 2018 ($ thousands) Canada U.S. Total Oil and natural gas sales, net of royalties ​ $ 198,263 ​ $ 1,094,473 ​ $ 1,292,736 Depletion, depreciation and accretion ​ ​ 58,333 ​ ​ 245,941 ​ ​ 304,274 Property, plant and equipment ​ 262,159 ​ 1,044,912 ​ 1,307,071 Deferred income tax asset ​ ​ 196,903 ​ ​ 268,221 ​ ​ 465,124 Goodwill ​ 451,121 ​ ​ 203,678 ​ ​ 654,799 Long term income tax receivable ​ — ​ 27,195 ​ 27,195 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As at and for the year ended December 31, 2017 ($ thousands) Canada U.S. Total Oil and natural gas sales, net of royalties ​ $ 227,031 ​ $ 693,662 ​ $ 920,693 Depletion, depreciation and accretion ​ ​ 89,936 ​ ​ 160,838 ​ ​ 250,774 Property, plant and equipment ​ 246,604 ​ 653,427 ​ 900,031 Deferred income tax asset ​ ​ 200,818 ​ ​ 369,119 ​ ​ 569,937 Goodwill ​ 451,121 ​ 187,757 ​ 638,878 Long term income tax receivable ​ — ​ 50,108 ​ 50,108

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2019
SUPPLEMENTAL CASH FLOW INFORMATION
Schedule of net change in non-cash operating working capital	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) ​ December 31, 2019 ​ December 31, 2018 ​ December 31, 2017 Accounts receivable ​ $ 8,493 ​ $ (45,385) ​ $ (66,860) Other assets ​ 4,475 ​ (3,026) ​ (154) Accounts payable ​ (11,005) ​ 44,952 ​ 31,982 ​ ​ $ 1,963 ​ $ (3,459) ​ $ (35,032)
Schedule of changes in other non-cash working capital	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 December 31, 2018 December 31, 2017 Non-cash financing activities (1) ​ $ (178) ​ $ (26) ​ $ 16 Non-cash investing activities (2) ​ $ 17,682 ​ $ (3,753) ​ $ 1,523 (1) Relates to changes in dividends payable and included in dividends on the Consolidated Statements of Cash Flows. (2) Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Consolidated Statements of Cash Flows.
Schedule of supplementary cash flow information	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ($ thousands) December 31, 2019 ​ December 31, 2018 December 31, 2017 Income taxes paid/(received) ​ $ (71,890) ​ $ (481) ​ $ 2,640 Interest paid ​ $ 33,991 ​ $ 36,161 ​ $ 38,149

SIGNIFICANT ACCOUNTING POLICI_4

SIGNIFICANT ACCOUNTING POLICIES - Transportation (Details)	12 Months Ended
	Dec. 31, 2019agreement
Transportation
Number of agreement types common in the industry	2

SIGNIFICANT ACCOUNTING POLICI_5

SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details)	Dec. 31, 2019
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_6

SIGNIFICANT ACCOUNTING POLICIES - Goodwill (Details) - segment	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill
Number of reporting units	2	2	2

SIGNIFICANT ACCOUNTING POLICI_7

SIGNIFICANT ACCOUNTING POLICIES - Financial Instruments (Details)	12 Months Ended
	Dec. 31, 2019category
Financial Instruments
Number of categories in which financial instruments are classified	5

SIGNIFICANT ACCOUNTING POLICI_8

SIGNIFICANT ACCOUNTING POLICIES - Share-Based Compensation (Details)	12 Months Ended
	Dec. 31, 2019
Share-Based Compensation
Authorized percentage to issue outstanding common shares from treasury (as a percent)	3.80%
Volume weighted average price prior to the grant date, period	20 days
RSU
Share-Based Compensation
Award vesting percentage (as a percent)	33.33%
Award vesting period	3 years
PSU
Share-Based Compensation
Award vesting period	3 years
Multiplier, low end of range	0
Multiplier, high end of range	2

SIGNIFICANT ACCOUNTING POLICI_9

SIGNIFICANT ACCOUNTING POLICIES - Accounting Changes and Recent Pronouncements Issued - Recently Adopted Accounting Standards and Future Accounting Changes (Details)	Jan. 01, 2020	Dec. 31, 2019
Accounting Standards Update 2016-02
SIGNIFICANT ACCOUNTING POLICIES
Change in Accounting Principle, Accounting Standards Update, Adopted		true
Change in Accounting Principle, Accounting Standards Update, Adoption Date		Jan. 1, 2019
Change in Accounting Principle, Accounting Standards Update, Early Adoption		false
Change in Accounting Principle, Accounting Standards Update, Transition Option Elected		Modified Retrospective
Accounting Standards Update 2016-13
SIGNIFICANT ACCOUNTING POLICIES
Change in Accounting Principle, Accounting Standards Update, Adopted	true
Change in Accounting Principle, Accounting Standards Update, Adoption Date	Jan. 1, 2020
Change in Accounting Principle, Accounting Standards Update, Early Adoption	false
Change in Accounting Principle, Accounting Standards Update, Transition Option Elected	Modified Retrospective
Accounting Standards Update 2017-04
SIGNIFICANT ACCOUNTING POLICIES
Change in Accounting Principle, Accounting Standards Update, Adopted	true
Change in Accounting Principle, Accounting Standards Update, Adoption Date	Jan. 1, 2020
Change in Accounting Principle, Accounting Standards Update, Early Adoption	false
Change in Accounting Principle, Accounting Standards Update, Transition Option Elected	Prospective

SIGNIFICANT ACCOUNTING POLIC_10

SIGNIFICANT ACCOUNTING POLICIES - Accounting Changes and Recent Pronouncements Issued - ASC 842 - Practical Expedients (Details)	12 Months Ended
	Dec. 31, 2019
Leases
Lease, Practical Expedient, Land Easement	true

SIGNIFICANT ACCOUNTING POLIC_11

SIGNIFICANT ACCOUNTING POLICIES - Accounting Changes and Recent Pronouncements Issued - ASC 842 - Impacts of Adoption (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Leases
Right of use assets	$ 48,729	$ 50,193
Current portion of lease liabilities	(17,541)	(10,648)
Lease liabilities	$ (35,530)	(39,545)
Accounting Standards Update 2016-02 | Restatement Adjustment
Leases
Right of use assets		50,193
Current portion of lease liabilities		(10,648)
Lease liabilities		$ (39,545)

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable
Accrued revenue	$ 142,048	$ 118,821
Accounts receivable - trade	37,736	30,252
Allowance for doubtful accounts	(3,665)	(3,867)
Total accounts receivable, net of allowance for doubtful accounts	$ 176,119	$ 145,206

PROPERTY, PLANT AND EQUIPMENT_3

PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Tabular Disclosure (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and gas properties
Oil and gas properties, cost	$ 15,088,724	$ 14,773,082
Oil and gas properties, accumulated depletion, depreciation, and impairment	(13,541,362)	(13,479,141)
Oil and natural gas properties, net book value	1,547,362	1,293,941
Other capital assets
Other capital assets, cost	125,265	115,510
Other capital assets, accumulated depletion, depreciation, and impairment	(105,021)	(102,380)
Other capital assets, net book value	20,244	13,130
Property, plant and equipment
Total PP&E, cost	15,213,989	14,888,592
Total PP&E, accumulated depletion, depreciation, and impairment	(13,646,383)	(13,581,521)
Property, plant and equipment	$ 1,567,606	$ 1,307,071	$ 900,031

PROPERTY, PLANT AND EQUIPMENT_4

PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Acquisitions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas Properties and Land
Property, plant and equipment
Property, plant and equipment, additions	$ 24.4	$ 25.8

PROPERTY, PLANT AND EQUIPMENT_5

PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Divestments (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, plant and equipment
Property divestments	$ 9,600	$ 6,900
Gain on divestment of assets		$ 0	$ 78,400

IMPAIRMENT - Impairment of PP&E

IMPAIRMENT - Impairment of PP&E - General Information (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Impairment
Oil and natural gas properties impairment	$ 0	$ 0	$ 0

IMPAIRMENT - Impairment of PP_2

IMPAIRMENT - Impairment of PP&E - Tabular Disclosure (Details)	Dec. 31, 2019$ / bbl$ / Mcf$ / bbl$ / $	Dec. 31, 2018$ / Mcf$ / bbl$ / bbl$ / $	Dec. 31, 2017$ / bbl$ / Mcf$ / bbl$ / $
Impairment
WTI Crude Oil US$/bbl (in dollars per barrel)	55.85	65.56	51.34
Edm Light Crude CDN$/bbl (in Canadian dollar per barrel)	66.73	69.58	63.57
U.S. Henry Hub Gas US$/Mcf (in dollars per Mcf) | $ / Mcf	2.58	3.10	2.98
Exchange Rate US$/CDN$ (in Canadian dollars per US dollars) | $ / $	1.33	1.28	1.30

IMPAIRMENT - Goodwill (Details)

IMPAIRMENT - Goodwill (Details) $ in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)
Impairment
Goodwill impairment		$ 0	$ 0
Goodwill		$ 654,799	$ 638,878		$ 194,015
Canadian Reporting Unit
Impairment
Goodwill impairment	$ 451,100
United States Reporting Unit
Impairment
Goodwill				$ 149.4

ACCOUNTS PAYABLE (Details)

ACCOUNTS PAYABLE (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts Payable
Accrued payables	$ 105,928	$ 115,388
Accounts payable - trade	185,612	174,657
Total accounts payable	$ 291,540	$ 290,045

DEBT - Total Debt (Details)

DEBT - Total Debt (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt
Long-term debt, current portion	$ 105,998	$ 60,001
Long-term debt, non-current portion	500,635	636,849
Total debt	606,633	696,850
Line of Credit
Debt
Long-term debt, non-current portion	0	0
Senior Notes
Debt
Long-term debt, current portion	105,998	60,001
Long-term debt, non-current portion	500,635	$ 636,849
Total debt	$ 606,633

DEBT - Bank Credit Facility (De

DEBT - Bank Credit Facility (Details) - Bank Credit Facility - Line of Credit $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Debt
Unsecured, covenant-based bank credit facility	$ 600
Standby fees on undrawn portion of the facility as a percentage on drawn pricing (as a percent)	20.00%
Minimum | Canada Bankers' Acceptances Rate
Debt
Basis points over bankers' acceptance rates (as a percent)	1.25%
Maximum | Canada Bankers' Acceptances Rate
Debt
Basis points over bankers' acceptance rates (as a percent)	3.15%

DEBT - Senior Notes - General I

DEBT - Senior Notes - General Information (Details) - Senior Notes - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
7.97% senior notes maturing June 18, 2021
Debt
Principal repayment amount	$ 22	$ 22
4.34% senior notes maturing May 15, 2019
Debt
Bullet repayment	$ 30

DEBT - Senior Notes - Tabular D

DEBT - Senior Notes - Tabular Disclosure (Details) $ in Thousands, $ in Thousands	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Debt
Carrying Value		$ 606,633	$ 696,850
Senior Notes
Debt
Carrying Value		$ 606,633
Senior Notes | 3.79% senior notes maturing September 2022
Debt
Coupon Rate (as a percent)	3.79%	3.79%
Original Principal	$ 200,000
Remaining Principal	$ 105,000
Carrying Value		$ 136,395
Senior Notes | 4.40% senior notes maturing May 15, 2022
Debt
Coupon Rate (as a percent)	4.40%	4.40%
Original Principal	$ 20,000
Remaining Principal	$ 20,000
Carrying Value		$ 25,980
Senior Notes | 4.40% senior notes maturing May 15, 2020
Debt
Coupon Rate (as a percent)	4.40%	4.40%
Original Principal	$ 355,000
Remaining Principal	$ 298,000
Carrying Value		$ 387,102
Senior Notes | 7.97% senior notes maturing June 18, 2021
Debt
Coupon Rate (as a percent)	7.97%	7.97%
Original Principal	$ 225,000
Remaining Principal	$ 44,000
Carrying Value		$ 57,156

ASSET RETIREMENT OBLIGATION - T

ASSET RETIREMENT OBLIGATION - Tabular Disclosure (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in asset retirement obligation
Balance, beginning of year	$ 126,112	$ 117,736
Change in estimates	23,362	16,755
Property acquisition and development activity	2,068	1,565
Divestments	(2,760)	(4,585)
Settlements	(16,715)	(11,263)
Accretion expense	5,982	5,904
Balance, end of year	$ 138,049	$ 126,112

ASSET RETIREMENT OBLIGATION - A

ASSET RETIREMENT OBLIGATION - Additional Information (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation
Asset retirement obligation	$ 138,049	$ 126,112
Total undiscounted liability	$ 344,700	$ 126,100	$ 343,900
Risk free rate for calculating asset retirement obligation (as a percent)	5.50%	5.59%
Inflation rate for calculating asset retirement obligation (as a percent)	1.80%	1.80%

LEASES - Assets and Liabilities

LEASES - Assets and Liabilities (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Leases
Operating right-of-use assets	$ 48,729	$ 50,193
Current operating lease liabilities	17,541	10,648
Non-current operating lease liabilities	35,530	$ 39,545
Total lease liabilities	$ 53,071

LEASES - Weighted Average Remai

LEASES - Weighted Average Remaining Lease Term and Discount Rate (Details)	Dec. 31, 2019
Leases
Weighted average remaining lease term (years), operating leases	4 years 3 months 18 days
Weighted average discount rate, operating leases	4.10%

LEASES - Lease Expense (Details

LEASES - Lease Expense (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)
Lease expense
Operating lease cost	$ 19,483
Short-term lease cost	15,332
Sublease income	(1,072)
Total	$ 33,743

LEASES - Maturities of Lease Li

LEASES - Maturities of Lease Liabilities (Details) $ in Thousands	Dec. 31, 2019CAD ($)
Maturity of Lease Liabilities
2020	$ 19,371
2021	14,098
2022	7,674
2023	6,706
2024	6,200
After 2024	3,979
Total lease payments	$ 58,028

LEASES - Gross Difference (Deta

LEASES - Gross Difference (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Gross Difference
Total lease payments	$ 58,028
Less: Present value discount	(4,957)
Total discounted lease payments	53,071
Current portion of lease liabilities	17,541	$ 10,648
Non-current operating lease liabilities	$ 35,530	$ 39,545

LEASES - Supplemental Informati

LEASES - Supplemental Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)
Leases
Cash amounts paid to settle lease liabilities, operating cash flow used for operating leases	$ 18,637
Right-of-use assets obtained in exchange for lease obligations, operating leases	$ 20,818

OIL AND NATURAL GAS SALES - Oil

OIL AND NATURAL GAS SALES - Oil and Natural Gas Sales, Net of Royalties (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Oil and natural gas sales	$ 1,572,955	$ 1,610,899	$ 1,141,770
Royalties	(318,149)	(318,163)	(221,077)
Oil and natural gas sales, net of royalties	$ 1,254,806	$ 1,292,736	$ 920,693
Type of revenue	us-gaap:OilAndGasMember	us-gaap:OilAndGasMember	us-gaap:OilAndGasMember

OIL AND NATURAL GAS SALES - Rev

OIL AND NATURAL GAS SALES - Revenue by Country and by Product (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	$ 1,254,806	$ 1,292,736	$ 920,693
Crude oil
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	992,996	983,095
Natural gas
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	237,739	268,934
Natural gas liquids
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	21,513	37,577
Other
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	2,558	3,130
Canada
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	177,299	198,263	227,031
Canada | Crude oil
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	145,814	148,949
Canada | Natural gas
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	21,776	32,109
Canada | Natural gas liquids
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	7,158	14,075
Canada | Other
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	2,551	3,130
U.S.
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	1,077,507	1,094,473	$ 693,662
U.S. | Crude oil
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	847,182	834,146
U.S. | Natural gas
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	215,963	236,825
U.S. | Natural gas liquids
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	14,355	$ 23,502
U.S. | Other
Oil and natural gas revenue by country and by product
Oil and natural gas sales, net of royalties	$ 7

GENERAL AND ADMINISTRATIVE EX_3

GENERAL AND ADMINISTRATIVE EXPENSE (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense	$ 49,532	$ 49,943	$ 50,544
Share-based compensation expense	23,321	25,840	23,757
General and administrative expense	$ 72,853	$ 75,783	$ 74,301

FOREIGN EXCHANGE (Details)

FOREIGN EXCHANGE (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
FOREIGN EXCHANGE
Foreign exchange (gain)/loss	$ (87)	$ 523	$ 1,495
Translation of U.S. dollar cash held in Canada (gain)/loss	8,794	(19,630)	10,978
Translation of U.S. dollar debt and working capital (gain)/loss	(34,085)	58,628	(42,623)
Foreign exchange (gain)/loss	$ (25,378)	$ 39,521	$ (30,150)

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current tax expense/(recovery)
Canada	$ (13,910)	$ (400)	$ (407)
United States	(19,504)	(26,693)	(47,550)
Current Tax expense/(recovery)	(33,414)	(27,093)	(47,957)
Deferred Tax expense/(recovery)
Canada	11,023	3,915	(17,127)
United States	70,252	126,389	147,072
Deferred Tax expense/(recovery)	81,275	130,304	129,945
Income Tax expense/(recovery)	$ 47,861	$ 103,211	$ 81,988

INCOME TAXES - Income (Loss) Be

INCOME TAXES - Income (Loss) Before Taxes (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Expenses
Canada	$ (437,571)	$ 104,204	$ 146,953
United States	225,712	377,286	172,033
Income/(Loss) Before Taxes	$ (211,859)	$ 481,490	$ 318,986

INCOME TAXES - Reconciliation (

INCOME TAXES - Reconciliation (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of income taxes calculated at the Canadian statutory rate to the actual income taxes
Canadian statutory rate (as a percent)	26.50%	27.00%	27.00%
Expected income tax expense/(recovery)	$ (56,143)	$ 130,002	$ 86,126
Foreign and statutory rate differences	27,446	(23,859)	157,320
Share-based compensation	(5,398)	(18,102)	5,067
Non-taxable capital (gains)/losses	3,994	7,254	(6,337)
Change in valuation allowance	(22,038)	6,292	(162,992)
Amounts in respect of prior periods	(19,451)
Non-deductible goodwill impairment	119,547
Other	(96)	1,624	2,804
Income Tax expense/(recovery)	$ 47,861	$ 103,211	$ 81,988

INCOME TAXES - Deferred Tax Ass

INCOME TAXES - Deferred Tax Assets (Liability) (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred income tax assets
Property, plant and equipment	$ 59,896	$ 60,665
Tax loss carryforwards and other credits	383,600	429,651
Capital loss carryforwards and other capital items	154,532	188,409
Asset retirement obligation	33,569	33,935
Other assets	12,219	14,099
Deferred income tax asset before valuation allowance	643,816	726,759
Valuation allowance	(169,129)	(191,167)
Deferred income tax assets, net	474,687	535,592
Deferred income tax liabilities
Property, plant and equipment	(100,328)	(46,284)
Derivative financial instruments	(1,857)	(24,184)
Total deferred income tax liabilities	(102,185)	(70,468)
Total deferred income tax asset	$ 372,502	$ 465,124

INCOME TAXES - Additional Infor

INCOME TAXES - Additional Information (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
INCOME TAXES
Amount reclassified	$ 13.9	$ 27.2

INCOME TAXES - Operating Loss C

INCOME TAXES - Operating Loss Carryforwards (Details) $ in Thousands	Dec. 31, 2019CAD ($)
Domestic Tax Authority
Operating Loss Carryforwards
Operating loss carryforward	$ 1,170,000
Foreign Tax Authority | Earliest Tax Year
Operating Loss Carryforwards
Operating loss carryforward	889,000
Foreign Tax Authority | Latest Tax Year
Operating Loss Carryforwards
Operating loss carryforward	$ 102,000

INCOME TAXES - Tax Credit Carry

INCOME TAXES - Tax Credit Carryforwards (Details) $ in Thousands	Dec. 31, 2019CAD ($)
Domestic Tax Authority
Tax Credit Carryforwards
Tax credit carryforward	$ 405,000

INCOME TAXES - Unrecognized Tax

INCOME TAXES - Unrecognized Tax Benefits - Tabular Disclosure (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in the balance of unrecognized tax benefits
Balance, beginning of year	$ 13,300	$ 13,300	$ 13,300
Settlements	(13,300)	0	0
Balance, end of year	$ 0	$ 13,300	$ 13,300

INCOME TAXES - Unrecognized T_2

INCOME TAXES - Unrecognized Tax Benefits - Additional Information (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes
Unrecognized Tax Benefits	$ 0	$ 13,300	$ 13,300	$ 13,300
Unrecognized tax benefits, current tax recovery	$ 13,900

SHAREHOLDERS' EQUITY - Share Ca

SHAREHOLDERS' EQUITY - Share Capital - Tabular Disclosure (Details) $ in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)shares	Dec. 31, 2019CAD ($)shares	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)shares
Increase (decrease) in equity
Balance, beginning of year | $		$ 2,000,989	$ 1,600,769
Balance, beginning of year (in shares) | shares	239,000,000	239,000,000
Purchase of common shares under Normal Course Issuer Bid	$ (178.8)		$ (79,000)
Purchase of common shares under Normal Course Issuer Bid (in shares) | shares	(18,231,401)	(18,231,401)	(5,925,084)
Balance, end of year | $		$ 1,471,558	$ 2,000,989	$ 1,600,769
Balance, end of year (in shares) | shares	222,000,000	222,000,000	239,000,000
Share Capital
Increase (decrease) in equity
Balance, beginning of year | $		$ 3,337,608	$ 3,386,946	$ 3,365,962
Balance, beginning of year (in shares) | shares	239,411,000	239,411,000	242,129,000	240,483,000
Purchase of common shares under Normal Course Issuer Bid	$ (253.9)	$ (253,920)	$ (82,596)
Purchase of common shares under Normal Course Issuer Bid (in shares) | shares	(18,231,000)	(18,231,000)	(5,925,000)
Stock Option Plan | $			$ 9,138
Stock Option Plan (in shares) | shares			668,000
Stock issue costs (net of tax $2,621) | $		$ (253,920)	$ (82,596)
Share-based compensation - settled | $		$ 4,406	$ 23,389	$ 20,984
Share-based compensation - settled (in shares) | shares	564,000	564,000	2,539,000	1,646,000
Stock Option Plan - exercised | $			$ 731
Balance, end of year | $		$ 3,088,094	$ 3,337,608	$ 3,386,946
Balance, end of year (in shares) | shares	221,744,000	221,744,000	239,411,000	242,129,000

SHAREHOLDERS' EQUITY - Share _2

SHAREHOLDERS' EQUITY - Share Capital - Shares Authorized (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share capital
Share capital, shares authorized, unlimited	Unlimited	Unlimited
Share capital, par value (in CAD per share)	$ 0	$ 0

SHAREHOLDERS' EQUITY - Share _3

SHAREHOLDERS' EQUITY - Share Capital - Dividends (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Dividends
Dividend paid per common share (in CAD per share)	$ 0.12	$ 0.12	$ 0.12
Dividends declared	$ 27.7	$ 29.3	$ 29

SHAREHOLDERS' EQUITY - Share _4

SHAREHOLDERS' EQUITY - Share Capital - Share Repurchases (Details) $ / shares in Units, $ in Thousands, $ in Millions	Mar. 20, 2020	Mar. 21, 2019shares	Mar. 26, 2018	Feb. 20, 2020CAD ($)$ / sharesshares	Dec. 31, 2019USD ($)shares	Dec. 31, 2019CAD ($)$ / sharesshares	Dec. 31, 2018CAD ($)$ / sharesshares
Share capital
Shares permitted for repurchase and cancellation (in shares)		16,673,015
Share repurchase and cancellation, period in force			12 months
Threshold percentage of public float (as a percent)		10.00%
Number of shares authorized for repurchase (in shares)		7,145,578
Shares purchased for cancellation (in shares)					18,231,401	18,231,401	5,925,084
Average price per share (in CAD per share) | $ / shares						$ 9.80	$ 13.33
Purchase of common shares under Normal Course Issuer Bid					$ 178.8		$ 79,000
Subsequent Event
Share capital
Shares purchased for cancellation (in shares)				340,000
Average price per share (in CAD per share) | $ / shares				$ 7.44
Purchase of common shares under Normal Course Issuer Bid | $				$ 2,500
Subsequent Event | Forecast
Share capital
Threshold percentage of public float (as a percent)	10.00%
Share Capital
Share capital
Shares purchased for cancellation (in shares)					18,231,000	18,231,000	5,925,000
Purchase of common shares under Normal Course Issuer Bid					$ 253.9	$ 253,920	$ 82,596
Accumulated Deficit
Share capital
Purchase of common shares under Normal Course Issuer Bid					$ (75.1)	$ (75,127)	$ (3,569)

SHAREHOLDERS' EQUITY - Share-Ba

SHAREHOLDERS' EQUITY - Share-Based Compensation (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation
Share-based compensation expense	$ 23,321	$ 25,840	$ 23,757
Cash Settled DSU
Share-based Compensation
Share-based compensation expense	689	133	997
Equity-settled Long-term Incentive Plans
Share-based Compensation
Share-based compensation expense	22,324	25,917	22,576
Equity Swaps
Share-based Compensation
Share-based compensation expense	$ 308	$ (210)	$ 184

SHAREHOLDERS' EQUITY - Long-ter

SHAREHOLDERS' EQUITY - Long-term Incentive Plans - Activity (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2019shares
Number of units
Balance, beginning of year (in shares)	3,515
Granted (in shares)	1,778
Vested (in shares)	(1,075)
Forfeited (in shares)	(126)
Balance, end of year (in shares)	4,092
Cash Settled DSU
Number of units
Balance, beginning of year (in shares)	391
Granted (in shares)	99
Vested (in shares)	(68)
Balance, end of year (in shares)	422
PSU
Number of units
Balance, beginning of year (in shares)	1,371
Granted (in shares)	817
Forfeited (in shares)	(49)
Balance, end of year (in shares)	2,139
RSU
Number of units
Balance, beginning of year (in shares)	1,753
Granted (in shares)	862
Vested (in shares)	(1,007)
Forfeited (in shares)	(77)
Balance, end of year (in shares)	1,531

SHAREHOLDERS' EQUITY - Cash-set

SHAREHOLDERS' EQUITY - Cash-settled LTI Plans (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation
Accounts payable	$ 291,540	$ 290,045
Cash Settled DSU
Share-based Compensation
Cash paid for settlement of compensation costs	900	500	$ 100
Accounts payable	$ 3,900	$ 4,100

SHAREHOLDERS' EQUITY - Cumulati

SHAREHOLDERS' EQUITY - Cumulative Share-based Compensation Expense (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)
Share-Based Compensation
Cash withholding taxes	$ 4,952
Equity-settled Long-term Incentive Plans
Share-Based Compensation
Recognized non-cash share-based compensation expense	44,263
Unrecognized cash share-based compensation expense	17,553
Fair value	61,816
PSU
Share-Based Compensation
Recognized non-cash share-based compensation expense	30,768
Unrecognized cash share-based compensation expense	11,971
Fair value	$ 42,739
Weighted-average remaining contractual term (years)	1 year 8 months 12 days
RSU
Share-Based Compensation
Recognized non-cash share-based compensation expense	$ 13,495
Unrecognized cash share-based compensation expense	5,582
Fair value	$ 19,077
Weighted-average remaining contractual term (years)	1 year 4 months 24 days

SHAREHOLDERS' EQUITY - Stock Op

SHAREHOLDERS' EQUITY - Stock Option Plan - Activity (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Number of Options
Options outstanding, Beginning of year (in shares) | shares	4,131
Exercised (in shares) | shares	0
Forfeited (in shares) | shares	(96)
Expired (in shares) | shares	(1,928)
Options outstanding, End of year (in shares) | shares	2,107
Weighted Average Exercise Price
Options outstanding, Beginning of year (in dollars per share) | $ / shares	$ 17.12
Exercised (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	15.22
Expired (in dollars per share) | $ / shares	20.35
Options outstanding, End of year (in dollars per share) | $ / shares	$ 14.24

SHAREHOLDERS' EQUITY - Stock _2

SHAREHOLDERS' EQUITY - Stock Option Plan - Additional Information (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation
Options exercisable (in shares)	2,106,944
Options exercisable, weighted average exercise price (in CAD per share)	$ 14.24
Options exercisable, weighted average remaining contractual term	2 months 12 days
Options exercisable, aggregate intrinsic value	$ 0	$ 0	$ 0

SHAREHOLDERS' EQUITY - Net Inco

SHAREHOLDERS' EQUITY - Net Income/(Loss) (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Basic and Diluted Net Income/(Loss) Per Share
Net income/(loss)	$ (259,720)	$ 378,279	$ 236,998
Weighted average shares outstanding - Basic (in shares)	231,334	244,076	241,929
Dilutive impact of share-based compensation (in shares)		3,185	5,945
Weighted average shares outstanding - Diluted (in shares)	231,334	247,261	247,874
Net Income/(Loss) per Share
Basic (in CAD per share)	$ (1.12)	$ 1.55	$ 0.98
Diluted (in CAD per share)	$ (1.12)	$ 1.53	$ 0.96

FINANCIAL INSTRUMENTS AND RIS_3

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value Measurements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value Measurements
Transfers between hierarchy levels	$ 0
Senior Notes | Carrying Value
Fair Value Measurements
Long-term debt, fair value	606.6	$ 696.9
Senior Notes | Fair Value
Fair Value Measurements
Long-term debt, fair value	$ 613.8	$ 695.4

FINANCIAL INSTRUMENTS AND RIS_4

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Change in Fair Value (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in fair value
Total Gain/(Loss)	$ (81,733)	$ 124,266	$ 6,184
Equity Swaps | General and Administrative
Change in fair value
Total Gain/(Loss)	(308)	210	(184)
Electricity Swaps | Operating Expense
Change in fair value
Total Gain/(Loss)			639
Commodity Derivative Instruments
Change in fair value
Unrealized Gain (Loss) on Commodity Contracts	(81,425)	124,056	5,729
Commodity Derivative Instruments | Crude oil | Commodity derivative instruments
Change in fair value
Unrealized Gain (Loss) on Commodity Contracts	(70,481)	114,822	(5,445)
Commodity Derivative Instruments | Gas | Commodity derivative instruments
Change in fair value
Unrealized Gain (Loss) on Commodity Contracts	$ (10,944)	$ 9,234	$ 11,174

FINANCIAL INSTRUMENTS AND RIS_5

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Derivatives (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Financial Instruments
Commodity derivative instruments gain/(loss)	$ (66,071)	$ 88,232	$ 14,310
Commodity Derivative Instruments
Derivative Financial Instruments
Change in fair value gain/(loss)	(81,425)	124,056	5,729
Net realized cash gain/(loss)	15,354	(35,824)	8,581
Commodity derivative instruments gain/(loss)	$ (66,071)	$ 88,232	$ 14,310

FINANCIAL INSTRUMENTS AND RIS_6

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Fair Value (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets, current
Assets
Assets	$ 10,570	$ 59,258
Liabilities, current
Liabilities
Liabilities	2,734	32,220
Liabilities, long-term
Liabilities
Liabilities		1,909
Equity Swaps | Liabilities, current
Liabilities
Liabilities	2,217
Equity Swaps | Liabilities, long-term
Liabilities
Liabilities		1,909
Commodity Derivative Instruments | Crude oil | Assets, current
Assets
Assets	10,570	48,314
Commodity Derivative Instruments | Crude oil | Liabilities, current
Liabilities
Liabilities	$ 517	32,220
Commodity Derivative Instruments | Gas | Assets, current
Assets
Assets		$ 10,944

FINANCIAL INSTRUMENTS AND RIS_7

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - General Information (Details)	12 Months Ended
	Dec. 31, 2019
Commodity Derivative Instruments
Risk Management
Maximum percentage of forecasted production volumes net of royalties considered to enter into commodity contracts	80.00%

FINANCIAL INSTRUMENTS AND RIS_8

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Commodity Price Risk - Crude Oil Instruments (Details) - Crude oil	12 Months Ended
	Dec. 31, 2019bbl / d$ / bbl
Risk Management
Total average deferred premium on outstanding hedges	1.69
Jan 1, 2020 - Jan 31, 2020, WTI | Swap
Risk Management
Volume | bbl / d	5,000
Weighted average price	57.05
Jan 1, 2020 - Jan 31, 2020 WCS | Differential swap
Risk Management
Volume | bbl / d	1,000
Weighted average price (negative price)	(19.25)
Feb 1, 2020 - Mar 31, 2020 WTI | Swap
Risk Management
Volume | bbl / d	10,000
Weighted average price	54.56
Feb 1, 2020 - Mar 31, 2020 WTI | Differential swap
Risk Management
Volume | bbl / d	1,000
Weighted average price (negative price)	(19.25)
Apr 1, 2020 - Jun 30, 2020 WTI | Swap
Risk Management
Volume | bbl / d	12,000
Weighted average price	55.23
Jul 1, 2020 - Sep 30, 2020 WTI | Swap
Risk Management
Volume | bbl / d	2,000
Weighted average price	57.18
Purchased | Jan 1, 2020 - Jan 31, 2020, WTI | Put
Risk Management
Volume | bbl / d	16,000
Weighted average price	57.50
Purchased | Jan 1, 2020 - Jan 31, 2020, WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(8.03)
Purchased | Feb 1, 2020 - Mar 31, 2020 WTI | Put
Risk Management
Volume | bbl / d	16,000
Weighted average price	57.50
Purchased | Feb 1, 2020 - Mar 31, 2020 WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(8.03)
Purchased | Apr 1, 2020 - Jun 30, 2020 WTI | Put
Risk Management
Volume | bbl / d	16,000
Weighted average price	57.50
Purchased | Apr 1, 2020 - Jun 30, 2020 WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(8.03)
Purchased | Jul 1, 2020 - Sep 30, 2020 WTI | Put
Risk Management
Volume | bbl / d	21,000
Weighted average price	57.20
Purchased | Jul 1, 2020 - Sep 30, 2020 WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(8.03)
Purchased | Oct 1, 2020 - Dec 31, 2020 WTI | Put
Risk Management
Volume | bbl / d	21,000
Weighted average price	57.20
Purchased | Oct 1, 2020 - Dec 31, 2020 WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(8.03)
Sold | Jan 1, 2020 - Jan 31, 2020, WTI | Put
Risk Management
Volume | bbl / d	16,000
Weighted average price	46.88
Sold | Jan 1, 2020 - Jan 31, 2020, WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(3.98)
Sold | Feb 1, 2020 - Mar 31, 2020 WTI | Put
Risk Management
Volume | bbl / d	16,000
Weighted average price	46.88
Sold | Feb 1, 2020 - Mar 31, 2020 WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(3.98)
Sold | Apr 1, 2020 - Jun 30, 2020 WTI | Put
Risk Management
Volume | bbl / d	16,000
Weighted average price	46.88
Sold | Apr 1, 2020 - Jun 30, 2020 WTI | Brent Swap
Risk Management
Volume | bbl / d	4,400
Weighted average price (negative price)	(3.98)
Sold | Jul 1, 2020 - Sep 30, 2020 WTI | Put
Risk Management
Volume | bbl / d	21,000
Weighted average price	47.14
Sold | Jul 1, 2020 - Sep 30, 2020 WTI | Call
Risk Management
Volume | bbl / d	5,000
Weighted average price	65
Sold | Oct 1, 2020 - Dec 31, 2020 WTI | Put
Risk Management
Volume | bbl / d	21,000
Weighted average price	47.14
Sold | Oct 1, 2020 - Dec 31, 2020 WTI | Call
Risk Management
Volume | bbl / d	5,000
Weighted average price	65

FINANCIAL INSTRUMENTS AND RIS_9

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Equity Price Risk (Details) - Equity Swaps	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Risk Management
Number of shares for which future settlement cost at weighted average price is fixed | shares	264,000
Future settlement cost at a weighted average price (in dollars per share) | $ / shares	$ 17.82

FINANCIAL INSTRUMENTS AND RI_10

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Credit Risk (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Marketing receivables with companies considered investment grade (as a percent)	77.00%
Allowance for doubtful accounts	$ 3,665	$ 3,867

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Commitments - Senior Notes (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Senior notes
Total debt	$ 606,633	$ 696,850
2020	105,998
2021	105,998
2022	130,680
2023	104,700
2024	104,699
Thereafter	$ 54,558

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Commitments - Other Commitments (Details) $ in Thousands	Dec. 31, 2019CAD ($)
Transportation commitments
Other Commitments
Total	$ 313,197
2019	34,829
2020	31,651
2021	29,271
2022	28,981
2023	28,719
Thereafter	159,746
Processing commitments
Other Commitments
Total	12,663
2019	3,174
2020	1,519
2021	1,519
2022	1,519
2023	1,519
Thereafter	$ 3,413

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES - Commitments - Total Commitments (Details) $ in Thousands	Dec. 31, 2019CAD ($)
Total Commitments
Total	$ 932,493
2019	144,001
2020	139,168
2021	161,470
2022	135,200
2023	134,937
Thereafter	$ 217,717

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES - Commitments - Exchange Rate (Details)	Dec. 31, 2019$ / $
Commitments
Exchange Rate US$/CDN$ (in Canadian dollars per US dollars)	1.2990

GEOGRAPHICAL INFORMATION (Detai

GEOGRAPHICAL INFORMATION (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Geographical Information
Oil and natural gas sales, net of royalties	$ 1,254,806	$ 1,292,736	$ 920,693
Depletion, depreciation and accretion	356,830	304,274	250,774
Property, plant and equipment	1,567,606	1,307,071	900,031
Deferred income tax asset	372,502	465,124	569,937
Goodwill	194,015	654,799	638,878
Long term income tax receivable	13,852	27,195	50,108
Canada
Geographical Information
Oil and natural gas sales, net of royalties	177,299	198,263	227,031
Depletion, depreciation and accretion	59,936	58,333	89,936
Property, plant and equipment	259,514	262,159	246,604
Deferred income tax asset	185,880	196,903	200,818
Goodwill		451,121	451,121
U.S.
Geographical Information
Oil and natural gas sales, net of royalties	1,077,507	1,094,473	693,662
Depletion, depreciation and accretion	296,894	245,941	160,838
Property, plant and equipment	1,308,092	1,044,912	653,427
Deferred income tax asset	186,622	268,221	369,119
Goodwill	194,015	203,678	187,757
Long term income tax receivable	$ 13,852	$ 27,195	$ 50,108

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Non-Cash Operating Working Capital (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in Non-Cash Operating Working Capital
Accounts receivable	$ 8,493	$ (45,385)	$ (66,860)
Other current assets	4,475	(3,026)	(154)
Accounts payable	(11,005)	44,952	31,982
Changes in non-cash operating working capital	$ 1,963	$ (3,459)	$ (35,032)

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION - Changes in Other Non-Cash Working Capital (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in Other Non-Cash Working Capital
Non-cash financing activities	$ (178)	$ (26)	$ 16
Non-cash investing activities	$ 17,682	$ (3,753)	$ 1,523

SUPPLEMENTAL CASH FLOW INFORM_5

SUPPLEMENTAL CASH FLOW INFORMATION - Other (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other
Income taxes paid/(received)	$ (71,890)	$ (481)	$ 2,640
Interest paid	$ 33,991	$ 36,161	$ 38,149