Baytex Energy (BTE) 6-K 4 Mar 20 Management's Report on Internal Control Over Financial Reporting Financial data

Cover

Cover	12 Months Ended
	Dec. 31, 2019
Cover [Abstract]
Entity Registrant Name	BAYTEX ENERGY CORP.
Entity Central Index Key	0001279495
Document Type	6-K
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Current Fiscal Year End Date	--12-31

Consolidated Statements of Fina

Consolidated Statements of Financial Position - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash	$ 5,572	$ 0
Trade and other receivables	173,762	111,564
Financial derivatives	5,433	79,582
Total current assets	184,767	191,146
Non-current assets
Exploration and evaluation assets	320,210	358,935
Oil and gas properties	5,387,889	5,817,889
Other plant and equipment	7,598	9,228
Lease assets	13,619
Total assets	5,914,083	6,377,198
Current liabilities
Trade and other payables	207,454	258,114
Less current portion of lease obligations	5,798
Financial derivatives	8,668	0
Onerous contracts	0	1,986
Less current portion of asset retirement obligations	11,579	0
Total current liabilities	233,499	260,100
Non-current liabilities
Bank loan	505,412	520,700
Long-term notes	1,328,175	1,583,240
Lease obligations	8,085
Non-current portion of asset retirement obligations	656,395	646,898
Deferred income tax liability	235,308	310,836
Total Liabilities	2,966,874	3,321,774
SHAREHOLDERS’ EQUITY
Shareholders' capital	5,718,835	5,701,516
Contributed surplus	17,712	19,137
Accumulated other comprehensive income	556,224	667,874
Deficit	(3,345,562)	(3,333,103)
Total shareholders' equity	2,947,209	3,055,424
Total liabilities and shareholders' equity	$ 5,914,083	$ 6,377,198

Consolidated Statements of Loss

Consolidated Statements of Loss and Comprehensive Loss - CAD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue [abstract]
Petroleum and natural gas sales	$ 1,805,919	$ 1,428,870
Royalties	(320,241)	(313,754)
Revenue, net of royalties	1,485,678	1,115,116
Expenses
Operating	397,716	311,592
Transportation	43,942	36,869
Blending and other	68,795	68,832
General and administrative	45,469	45,825
Transaction costs	0	13,074
Exploration and evaluation	11,764	21,729
Depletion and depreciation	731,686	558,684
Impairment	187,822	285,341
Share-based compensation	15,894	19,534
Financing and interest	125,865	119,086
Financial derivatives loss (gain)	7,197	(43,550)
Foreign exchange (gain) loss	(61,787)	108,294
Gain on dispositions	(2,238)	(1,946)
Other income	(7,526)	(1,172)
Total expenses	1,564,599	1,542,192
Net loss before income taxes	(78,921)	(427,076)
Income tax (recovery) expense
Current income tax expense (recovery)	2,093	(35)
Deferred income tax expense (recovery)	(68,555)	(101,732)
Income tax recovery	(66,462)	(101,767)
Net income (loss)	(12,459)	(325,309)
Other comprehensive income [abstract]
Foreign currency translation adjustment	(111,650)	204,770
Comprehensive loss	$ (124,109)	$ (120,539)
Net loss per common share
Basic (in cad per share)	$ (0.02)	$ (0.93)
Diluted (in cad per share)	$ (0.02)	$ (0.93)
Weighted average common shares
Basic (in shares)	557,048	351,542
Diluted (in shares)	557,048	351,542

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - CAD ($) $ in Thousands	Total	Shareholders’ capital	Contributed surplus	Accumulated other comprehensive income	Deficit
Beginning balance at Dec. 31, 2017	$ 1,914,885	$ 4,443,576	$ 15,999	$ 463,104	$ (3,007,794)
Common shares issued	1,242,095	1,238,995	3,100
Issuance costs, net of tax	(551)	(551)
Share issuance costs	0	19,496	(19,496)
Share-based compensation	19,534	19,496	19,534
Comprehensive income (loss)	(120,539)			204,770	(325,309)
Ending balance at Dec. 31, 2018	3,055,424	5,701,516	19,137	667,874	(3,333,103)
Share issuance costs	0	17,319	(17,319)
Share-based compensation	15,894		15,894
Comprehensive income (loss)	(124,109)			(111,650)	(12,459)
Ending balance at Dec. 31, 2019	$ 2,947,209	$ 5,718,835	$ 17,712	$ 556,224	$ (3,345,562)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Operating activities
Net loss - basic	$ (12,459)	$ (325,309)
Adjustments for:
Share-based compensation	15,894	19,534
Unrealized foreign exchange (gain) loss	(62,753)	106,143
Exploration and evaluation	11,764	21,729
Depletion and depreciation	731,686	558,684
Impairment	187,822	285,341
Non-cash financing and accretion	18,448	14,768
Unrealized financial derivatives loss (gain)	82,817	(116,715)
Gain on dispositions	(2,238)	(1,946)
Deferred income tax recovery	(68,555)	(101,732)
Payments on onerous contracts	0	(588)
Asset retirement obligations settled	(15,417)	(14,035)
Change in non-cash working capital	(52,070)	39,448
Cash provided by (used in) operating activities	834,939	485,322
Financing activities
Decrease in bank loan	(7,775)	(21,295)
Common share issuance costs	0	(755)
Payments on lease obligations	(5,956)
Redemption of long-term notes		0
Cash provided by financing activities	(211,859)	(22,050)
Investing activities
Additions to exploration and evaluation assets	(2,948)	(10,567)
Additions to oil and gas properties	(549,343)	(485,154)
Additions to other plant and equipment	(552)	(1,804)
Property acquisitions	(3,667)	(701)
Proceeds from dispositions	1,487	2,519
Change in non-cash working capital	(62,485)	32,435
Cash used in investing activities	(617,508)	(463,272)
Change in cash	5,572	0
Cash, beginning of year	0	0
Cash, end of year	5,572	0
Supplementary information
Interest paid	112,241	104,821
Income taxes paid	$ 1,160	$ 0

Reporting Entity

Reporting Entity	12 Months Ended
	Dec. 31, 2019
Corporate Information And Statement Of IFRS Compliance [Abstract]
Reporting Entity	REPORTING ENTITYBaytex Energy Corp. (the “Company” or “Baytex”) is an oil and gas corporation engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and the United States. The Company’s common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2019
Corporate Information And Statement Of IFRS Compliance [Abstract]
Basis of Presentation	BASIS OF PRESENTATION The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). The significant accounting policies set forth below were consistently applied to all periods presented except for the adoption of IFRS 16 Leases as discussed in note 3. The consolidated financial statements were approved by the Board of Directors of Baytex on March 3, 2020. The consolidated financial statements have been prepared on a historical cost basis, with the exception of certain fair value measurements noted in the accounting policies set forth below. The consolidated financial statements are presented in Canadian dollars which is the presentation currency of the Company. References to “US$” are to United States ("U.S.") dollars. All financial information is rounded to the nearest thousand, except per share amounts or where otherwise indicated. Measurement Uncertainty and Judgments The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available to the Company at the time of financial statement preparation. Actual results can differ from those estimates as the effect of future events cannot be determined with certainty. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below. Reserves The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion and in the determination of fair value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by independent reserves evaluators and represent the estimated recoverable quantities of oil, natural gas and NGL and the related net cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the Canadian Oil and Gas Evaluation Handbook. Estimates of economically recoverable oil, natural gas and NGL and their future net cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forward price forecasts, production rates, ultimate reserve recovery, timing and amount of capital expenditures, production costs, marketability of oil and natural gas, royalty rates and other geological, economic and technical factors could have a significant impact on reported reserves. Changes in the Company's reserves estimates can have a significant impact on the carrying values of the Company's oil and gas properties, the calculation of depletion, the timing of cash flows for asset retirement obligations, asset impairments and estimates of fair value determined in accounting for business combinations. Cash-generating Units ("CGUs") The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash flows that are largely independent of the cash flows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk. Identification of Impairment and Impairment Reversal Indicators Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. The assessment for each CGU considers significant changes in reservoir performance including forecasted production volumes, forecasted royalty, operating, capital and abandonment and reclamation costs, forecasted oil and gas prices and the resulting cash flows from proved plus probable oil and gas reserves. Measurement of Recoverable Amount If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves, the discount rate used to present value future cash flows and assumptions regarding the timing and amount of capital expenditures and future abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets. Exploration and Evaluation ("E&E") Assets Costs associated with acquiring oil and natural gas licenses and exploratory drilling are accumulated as E&E assets pending determination of technical feasibility and commercial viability. The determination of technical feasibility and commercial viability of E&E assets for the purposes of reclassifying such assets to oil and gas properties is subject to management judgment. Management uses the establishment of commercial reserves as the basis for determining technical feasibility and commercial viability. Upon determination of commercial reserves, E&E assets are tested for impairment and reclassified to oil and natural gas properties. Business Combinations Business combinations are accounted for using the acquisition method of accounting when the assets acquired meet the definition of a business in accordance with IFRS. Determination of the acquirer in a business combination requires management judgment. In determining the acquirer in a business combination, factors such as voting rights of all equity instruments, the intended corporate governance structure, composition of senior management of the combined company, and various metrics used to evaluate the relative size of each company are considered. The determination of fair value assigned to assets acquired and liabilities assumed requires management to make assumptions and estimates including forecast benchmark commodity prices, estimates of reserves acquired and discount rates used to present value future cash flows. Changes in any of the assumptions or estimates used in determining the fair value of assets acquired and liabilities assumed could impact the amounts assigned to assets, liabilities and goodwill. Financial Derivatives Financial derivatives are measured at fair value on each reporting date. The Company uses quoted commodity prices, estimates of future volatility prices and interest rates available at period end to determine the fair value of outstanding financial derivatives. Changes in market pricing between period end and settlement of the derivative contracts could have a significant impact on financial results related to the financial derivatives. Asset Retirement Obligations The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim the wells and the facilities, the estimated time period during which these costs will be incurred in the future, and discount and inflation rates. The provision for asset retirement obligations represents management's best estimate of the present value of the future abandonment and reclamation costs required under current regulatory requirements. Actual abandonment and reclamation costs could be materially different from estimated amounts. Income Taxes Regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. Interpretation and application of existing regulation and legislation requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes. Estimates of future income taxes are subject to measurement uncertainty.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Significant Accounting Policies	SIGNIFICANT ACCOUNTING POLICIES Changes in significant accounting policies Leases Baytex adopted IFRS 16 Leases on January 1, 2019, using the modified retrospective approach. The modified retrospective approach does not require restatement of comparative financial information as it recognizes the cumulative effect on transition as an adjustment to opening retained earnings and applies the standard prospectively. Comparative information in the Company's consolidated statements of financial position, consolidated statements of loss and comprehensive loss, consolidated statements of changes in equity, and consolidated statements of cash flows has not been restated and continues to be accounted for in accordance with the Company's previous accounting policy found in the 2018 annual financial statements. The cumulative effect of initial application of the standard was to recognize an $18.0 million increase to right-of-use assets ("lease assets"), a $2.0 million reduction of onerous contracts and a $18.0 million increase to lease obligations. Initial measurement of the lease obligation was determined based on the remaining lease payments at January 1, 2019 using a weighted averaged incremental borrowing rate of approximately 3.9%. The lease assets were initially recognized at an amount equal to the lease obligations. The lease assets and lease obligations recognized largely relate to the Company's head office lease in Calgary. The adoption of IFRS 16 using the modified retrospective approach allowed the Company to use the following practical expedients in determining the opening transition adjustment: • The weighted average incremental borrowing rate in effect at January 1, 2019 was used as opposed to the rate in effect at inception of the lease; • Leases with a remaining term of less than 12 months as at January 1, 2019 were accounted for as short-term leases; • Leases with an underlying asset of low value are recorded as an expense and not recognized as a lease asset; • Leases with similar characteristics were accounted for as a portfolio using a single discount rate; and • Used the Company's previous assessment under IAS 37, "Provisions, Contingent Liabilities and Contingent Assets' for onerous contracts instead of reassessing the lease assets for impairment at January 1, 2019. Significant accounting policies Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany balances and transactions are eliminated in preparation of the consolidated financial statements. Many of the Company's exploration, development and production activities are conducted through joint arrangements. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by joint arrangements. Business Combinations Business combinations are accounted for using the acquisition method of accounting when the acquired assets meet the definition of a business under IFRS. The cost of an acquisition is measured as cash paid and the fair value of assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair value of the net identifiable assets acquired is recognized as goodwill. If the cost of acquisition is below the fair values of the identifiable net assets acquired, the difference is recognized as a bargain purchase gain in net income or loss. Associated transaction costs are expensed when incurred. Revenue Recognition Revenue from the sale of light oil and condensate, heavy oil, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis when Baytex acts in the capacity of an agent rather than as a principal. The transaction price for variable price contracts in the Canadian and U.S. operating segments is based on a representative commodity price index, and may include adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period. Tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided. Exploration and Evaluation Assets Pre-license costs, including certain geological, geophysical and seismic expenditures, are incurred before the legal rights to explore a specific area have been obtained. These costs are charged to exploration expense in the period in which they are incurred. Once the legal right to explore has been acquired, costs directly associated with an exploration program are capitalized as an intangible asset until results of the exploration program have been evaluated. Costs capitalized as E&E assets include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing of initial production results. E&E costs are subject to technical, commercial and management review to confirm the continued intent to develop or otherwise extract the underlying reserves. The technical feasibility and commercial viability of extracting petroleum and natural gas resources is dependent on the existence of economically recoverable reserves for the project. If the asset is determined not to be technically feasible or commercially viable the accumulated E&E costs associated with the exploration project are charged to E&E expense in the period the determination is made. Upon determination of technical feasibility and commercial viability, as evidenced by the classification of proved or probable reserves and management's intention to develop the E&E asset, the accumulated costs associated with the exploration project are tested for impairment and transferred to oil and gas properties. Oil and Gas Properties Items of oil and gas properties are initially recorded at cost. The initial cost of oil and gas properties includes the costs to acquire developed or producing oil and gas properties, and to develop oil and gas properties, such as costs of completing geological and geophysical surveys, drilling development wells, and the costs to construct and install development infrastructure such as wellhead equipment and processing facilities. Oil and gas properties includes costs related to planned major inspection, overhaul and turnaround activities to maintain items of oil and gas properties and benefit future years of operations. Replacements outside of a major inspection, overhaul or turnaround are recognized as oil and gas properties when it is probable the future economic benefits of the replacement will be realized by the Company. The carrying amount of any replaced or disposed item of oil and gas properties is derecognized. Repair and maintenance costs incurred for servicing an item of oil and gas properties is recorded as operating expense as incurred. Depletion and Depreciation The costs associated with an item of oil and gas properties are depleted on a unit-of-production basis by depletable area over proved plus probable reserves once commercial production has commenced. Future development costs required to bring those reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil equivalent. The depreciation methods and estimated useful lives for other plant and equipment are as follows: Classification Method Rate or period Motor Vehicles Diminishing balance 15% Office Equipment Diminishing balance 20% Computer Hardware Diminishing balance 30% Furniture and Fixtures Diminishing balance 10% Leasehold Improvements Straight-line over life of the lease Various Other Assets Diminishing balance Various The expected lives of other plant and equipment are reviewed on an annual basis and, if necessary, changes in expected useful lives are accounted for prospectively. Impairment Non-derivative financial assets The Company assesses non-derivative financial assets at each reporting date to determine whether there is any objective evidence indicating that it is impaired. Objective evidence exists if one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows. An impairment loss is reversed when there is objective evidence that the value of the financial assets has been partially or fully restored. For financial assets measured at amortized cost the reversal is recognized in net income or loss. Non-financial assets The Company reviews its non-financial assets, other than E&E assets, for indicators of impairment and impairment reversal at the end of each reporting period. The recoverable amount of the asset is estimated if indicators of impairment or impairment reversal exist. E&E assets are assessed for impairment when they are reclassified to oil and gas properties and if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. When reviewing for indicators of impairment and impairment reversal, and testing for impairment when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows includes CGU production volumes, royalty obligations, operating costs, capital costs, forecast commodity prices, along with inflation and discount rates used to estimate present value. FVLCD is determined as the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction between willing parties. In determining FVLCD, recent market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a discount rate that reflects current market assessments of the time value of money. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment reduces the carrying amount of any goodwill allocated to the CGU first, with any remaining impairment being allocated to the individual assets in the CGU on a pro-rata basis. Impairments may be reversed for all CGUs and individual assets, other than goodwill, when there is indication that a previously recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. An impairment may be reversed only to the extent that the asset’s revised carrying amount does not exceed the carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized. Impairment recognized in relation to goodwill is not reversed for subsequent increases in its recoverable amount. Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal occurs. Leases 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. A lease obligation and corresponding right-of-use asset ("lease asset") are recognized at the commencement of the lease. The present value of the lease obligation is based on the future lease payments and is discounted using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with similar characteristics. The lease asset is recognized at the amount of the lease obligation, adjusted for lease incentives received and initial direct costs, on commencement of the lease. Depreciation is recognized on the lease asset over the shorter of the estimated useful life of the asset or the lease term. Lease payments are allocated between the liability and interest expense. Interest expense is recognized on the lease obligations using the effective interest rate method and payments are applied against the lease obligation. Management judgement is required to determine the discount rate used to calculate the present value of the lease obligation. The carrying amounts of the lease assets, lease obligations, and the resulting interest and depletion and depreciation expense are based on the implicit interest rate within the lease arrangement or, if this information is unavailable, the incremental borrowing rate. Incremental borrowing rates are based on judgments including economic environment, term, and the underlying risk inherent to the asset. Asset Retirement Obligations The Company recognizes asset retirement obligations when it has a legal or constructive obligation as a result of past events, it is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The Company’s asset retirement obligations are based on its net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and the facilities using existing technology and the estimated time period during which these costs will be incurred in the future. Asset retirement obligations are recognized for future asset retirement costs associated with the abandonment and reclamation of the Company's E&E assets and oil and gas properties. Asset retirement obligations are measured at the present value of management's best estimate of the future cash flows required to settle the present obligation, using the risk-free interest rate. The present value of the liability is capitalized as part of the cost of the related asset and depleted over its useful life. The asset retirement obligation is accreted until the date of expected settlement of the retirement obligation and is recognized within finance expense in the statements of income or loss. Changes in the future cash flow estimates resulting from revisions to the estimated timing or amount of undiscounted cash flows or the discount rates are recognized as changes in the asset retirement obligation provision and related asset at each reporting date. Foreign Currency Translation Foreign transactions Transactions completed in currencies other than the functional currency are translated into the functional currency at the exchange rates prevailing at the time of the transactions. Foreign currency assets and liabilities are translated to functional currency at the period-end exchange rate. Revenue and expenses are translated to functional currency using the average exchange rate for the period. Realized and unrealized gains and losses resulting from the settlement or translation of foreign currency transactions are included in net income or loss. Foreign operations The functional currency of the Company's subsidiaries is the currency of the primary economic environment in which the entity operates. Certain subsidiaries of the Company operate and transact primarily in currencies other than the Canadian dollar. The designation of a subsidiary's functional currency is a management judgment based on the currency of the primary economic environment in which the subsidiary operates. The financial statements of each entity are translated into Canadian dollars in preparation of the Company's consolidated financial statements. The assets and liabilities of a foreign operation are translated to Canadian dollars at the period-end exchange rate. Revenues and expenses of foreign operations are translated to Canadian dollars using the average exchange rate for the period. Foreign exchange differences are recognized in other comprehensive income or loss. If the Company or any of its entities disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign operation are recognized in net income or loss. Financial Instruments IFRS 9 contains three principal classification categories for initial classification of financial assets: measured at amortized cost; fair value through other comprehensive income (“FVOCI”); or fair value through profit or loss (“FVTPL”). Financial assets are categorized based on the Company’s objective for the asset and the contractual cash flows. A financial asset is classified as amortized cost if the asset is held with the objective to collect contractual cash flows that are solely payments of principal and interest on principal amounts outstanding. A financial asset is classified as FVOCI if the asset is held with the objective to both collect contractual cash flows and sell the financial asset. All other financial assets are measured at FVTPL. Financial assets are assessed for impairment using an expected credit loss model. Trade and other receivables are classified and measured at amortized cost. The measurement categories for each class of financial asset and financial liability is set forth in the following table. Financial Instrument Classification Cash and cash equivalents Amortized cost Trade and other receivables Amortized cost Financial derivatives Fair value through profit or loss Trade and other payables Amortized cost Bank loan Amortized cost Long-term notes Amortized cost Lease obligations Amortized cost An embedded derivative is a component of a contract that modifies the cash flows of the contract. These hybrid contracts consist of a host contract and an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative unless the economic characteristics and risks of the embedded derivative are closely related to the host contract. The embedded derivatives are measured at FVTPL. Debt issuance costs related to the amendment our bank loan or the issuance of long term notes are capitalized and amortized as financing costs over the term of the credit facilities or long term notes. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract. The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The risk management policy permits the use of certain derivative financial instruments, including swaps and collars, to manage these fluctuations. All transactions of this nature entered into by the Company are related to underlying financial instruments or future petroleum and natural gas production. These instruments are classified as FVTPL. The Company does not use financial derivatives for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments by recording an asset or liability on the statements of financial position and recognizing changes in the fair value of the instrument in the statements of income or loss for the current period. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or loss when incurred. The Company has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are recognized in revenue in the period the product is delivered to the sales point. Impairment of financial assets is determined by calculating the expected credit loss ("ECL"). The Company measures an ECL allowance for trade and other receivables. The Company determines the ECL which is the probability of default events related to the financial asset by using historical realized bad debts and forward looking information. The carrying amounts of financial assets are reduced by the amount of the ECL through an allowance account and losses are recognized in the statement of income or loss. Fair Value of Financial Instruments Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments: • Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. • Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. • Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Income Taxes Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized directly in equity, in which case the current and deferred taxes are also recognized directly in equity. Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes the financial statement impact of a tax filing position when it is probable that the position will be sustained upon audit. The liability is measured based on an assessment of possible outcomes and their associated probabilities. The Company follows the balance sheet asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all temporary differences deductible to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs. Share-based Compensation Plans The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards (collectively, "share awards") may be granted to the directors, officers and employees of the Company and its subsidiaries. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plans of the Company) shall not at any time exceed 3.8% of the then-issued and outstanding common shares. Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus dividend equivalents). Each performance award entitles the holder to be issued the number of common shares designated in the performance award (plus dividend equivalents) multiplied by a payout multiplier. Expenses related to the Share Award Incentive Plan are determined based on the fair value of the share awards on the grant date which is based on quoted market prices for the Company's common shares. Both restricted and performance awards are expensed over the vesting period using the graded vesting method. The payout multiplier is dependent on the performance of the Company relative to pre-defined corporate performance measures for a particular period. In the case of both restricted and performance awards, the number of common shares to be issued on the applicable issue date is adjusted to account for the payments of dividends from the grant date to the applicable issue date. The Company assumed share awards and share options pursuant to a business combination in 2018 (note 4). The share options were valued at the closing date of the transaction utilizing a Black-Scholes pricing model to value the share options. The share awards were valued at fair value using the quoted market price of the Company's common shares on the closing date of the transaction. The share awards assumed consist of restricted share awards and performance share awards with a fixed multiplier of 1.0 . Share-based compensation is expensed over the remaining vesting period and recognized as share-based compensation expense, with a corresponding increase to contributed surplus. .

Business Combination

Business Combination	12 Months Ended
	Dec. 31, 2019
Business Combinations1 [Abstract]
Business Combination	BUSINESS COMBINATION On August 22, 2018, Baytex completed a plan of arrangement whereby Baytex acquired, directly and indirectly, all of the issued and outstanding common shares of Raging River Exploration Inc. (“Raging River”), a publicly traded oil and gas producer with light oil producing properties in southwest Saskatchewan and Alberta. The acquisition was accounted for as a business combination whereby the net assets acquired and liabilities assumed were recorded at fair value at the acquisition date. Consideration consisted of the issuance of 315.3 million Baytex common shares valued at approximately $1.2 billion (based on the closing price of Baytex’s common shares of $3.93 on the Toronto Stock Exchange on August 22, 2018). The fair value of oil and gas properties acquired was determined using estimates of proved plus probable reserves evaluated at December 31, 2018 by an independent reserves evaluator and adjusted for operations between August 22, 2018 and the effective date of the reserve evaluation. Asset retirement obligations were determined using internal estimates of the timing and estimated costs associated with the abandonment and reclamation of the wells and facilities acquired using a market discount rate of 7.5%.The fair value of exploration and evaluation properties was estimated with reference to recent land sales in similar areas. The total consideration paid and estimates of the fair value of the assets acquired and liabilities assumed as at the date of the acquisition are set forth in the table below. Consideration Common shares issued $ 1,238,995 Share-based compensation (1) 3,100 Total consideration $ 1,242,095 Fair value of net assets acquired Exploration and evaluation assets $ 97,858 Oil and gas properties 1,748,368 Working capital deficiency excluding bank debt and financial derivatives (46,773) Financial derivatives (5,548) Bank debt (2) (316,800) Asset retirement obligations (39,960) Deferred income tax liability (195,050) Net assets acquired $ 1,242,095 (1) Following closing of the transaction, holders of units outstanding under Raging River's share-based compensation plans were entitled to Baytex common shares rather than Raging River common shares with adjustment to the exercise price or quantity outstanding based on the exchange ratio for the Raging River shares. As a result, the fair value assigned to the service period that had occurred prior to closing was recognized by Baytex as additional consideration (see note 14). (2) On August 22, 2018, Baytex amended its credit facilities to include the credit facility assumed in conjunction with the acquisition of Raging River and converted outstanding principal amounts to a non-revolving term loan. The acquisition contributed revenue of $158.8 million and operating income of $98.6 million for the period from the acquisition date of August 22, 2018 to December 31, 2018. Had the acquisition occurred on January 1, 2018, revenue would have increased by $379.5 million and operating income would have increased by $273.2 million for the year. Operating income is defined as revenue, net of royalties, less operating, transportation and blending expense. In 2018, transaction costs of $13.1 million were expensed as incurred and share issuance costs of $0.6 million (net of taxes of $0.2 million) were recorded in shareholders' capital in the year.

Segmented Financial Information

Segmented Financial Information	12 Months Ended
	Dec. 31, 2019
Operating Segments [Abstract]
Segmented Financial Information	SEGMENTED FINANCIAL INFORMATION Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations: • Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada; • U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the U.S.; and • Corporate includes corporate activities and items not allocated between operating segments. Canada U.S. Corporate Consolidated Years Ended December 31 2019 2018 2019 2018 2019 2018 2019 2018 Revenue, net of royalties Petroleum and natural gas sales $ 1,077,724 $ 619,215 $ 728,195 $ 809,655 $ — $ — $ 1,805,919 $ 1,428,870 Royalties (107,467) (72,700) (212,774) (241,054) — — (320,241) (313,754) 970,257 546,515 515,421 568,601 — — 1,485,678 1,115,116 Expenses Operating 298,303 221,717 99,413 89,875 — — 397,716 311,592 Transportation 43,942 36,869 — — — — 43,942 36,869 Blending and other 68,795 68,832 — — — — 68,795 68,832 General and administrative — — — — 45,469 45,825 45,469 45,825 Transaction costs — — — — — 13,074 — 13,074 Exploration and evaluation 11,764 10,580 — 11,149 — — 11,764 21,729 Depletion and depreciation 463,501 294,925 261,766 261,709 6,419 2,050 731,686 558,684 Impairment 187,822 65,000 — 220,341 — — 187,822 285,341 Share-based compensation — — — — 15,894 19,534 15,894 19,534 Financing and interest — — — — 125,865 119,086 125,865 119,086 Financial derivatives loss (gain) — — — — 7,197 (43,550) 7,197 (43,550) Foreign exchange (gain) loss — — — — (61,787) 108,294 (61,787) 108,294 Gain on dispositions (2,238) (1,946) — — — — (2,238) (1,946) Other income — — — — (7,526) (1,172) (7,526) (1,172) 1,071,889 695,977 361,179 583,074 131,531 263,141 1,564,599 1,542,192 Net income (loss) before income taxes (101,632) (149,462) 154,242 (14,473) (131,531) (263,141) (78,921) (427,076) Income tax expense (recovery) Current income tax expense (recovery) 101 — 1,992 (35) — — 2,093 (35) Deferred income tax expense (recovery) (32,942) (40,723) 10,055 (26,049) (45,668) (34,960) (68,555) (101,732) (32,841) (40,723) 12,047 (26,084) (45,668) (34,960) (66,462) (101,767) Net income (loss) $ (68,791) $ (108,739) $ 142,195 $ 11,611 $ (85,863) $ (228,181) $ (12,459) $ (325,309) Total oil and natural gas capital expenditures (1) $ 376,543 $ 300,299 $ 177,928 $ 193,604 $ — $ — $ 554,471 $ 493,903 (1) Includes acquisitions, net of proceeds from divestitures. As at December 31, 2019 December 31, 2018 Canadian assets $ 3,484,123 $ 3,739,029 U.S. assets 2,403,310 2,628,941 Corporate assets 26,650 9,228 Total consolidated assets $ 5,914,083 $ 6,377,198

Exploration and Evaluation Asse

Exploration and Evaluation Assets	12 Months Ended
	Dec. 31, 2019
Exploration For And Evaluation Of Mineral Resources [Abstract]
Exploration and Evaluation Assets	EXPLORATION AND EVALUATION ASSETS December 31, 2019 December 31, 2018 Balance, beginning of year $ 358,935 $ 272,974 Capital expenditures 2,948 10,567 Corporate acquisition (note 4) — 97,858 Property acquisitions 1,523 514 Divestitures (443) (1,021) Impairment (7,822) — Property swaps 417 — Exploration and evaluation expense (11,764) (21,729) Transfers to oil and gas properties (note 7) (16,204) (13,866) Foreign currency translation (7,380) 13,638 Balance, end of year $ 320,210 $ 358,935 At December 31, 2019, the Company identified indicators of impairment for the exploration and evaluation assets within the Peace River CGU. The estimated recoverable amount was below the carrying value of the exploration and evaluation assets in the Peace River CGU and an impairment of $7.8 million was recorded as at December 31, 2019. There were no indicators of impairment for exploration and evaluation assets in the remaining CGUs at December 31, 2019. At December 31, 2018 the Company identified indicators of impairment for the exploration and evaluation assets within the Conventional CGU. The estimated recoverable amount exceeded the carrying value of the of the exploration and evaluation assets in the Conventional CGU and no impairment was recorded. There were no indicators of impairment for exploration and evaluation assets in the remaining CGUs at December 31, 2018.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2019
Property, plant and equipment [abstract]
Oil and gas properties	OIL AND GAS PROPERTIES Cost Accumulated Net book value Balance, December 31, 2017 $ 7,932,327 $ (3,974,018) $ 3,958,309 Capital expenditures 485,154 — 485,154 Corporate acquisition (note 4) 1,748,368 — 1,748,368 Property acquisitions 202 — 202 Transfers from exploration and evaluation assets (note 6) 13,866 — 13,866 Change in asset retirement obligations (note 12) 238,662 — 238,662 Divestitures (15) — (15) Impairment — (285,341) (285,341) Foreign currency translation 325,969 (110,651) 215,318 Depletion — (556,634) (556,634) Balance, December 31, 2018 $ 10,744,533 $ (4,926,644) $ 5,817,889 Capital expenditures 549,343 — 549,343 Property acquisitions 2,636 — 2,636 Transfers from exploration and evaluation assets (note 6) 16,204 — 16,204 Change in asset retirement obligations (note 12) 23,894 — 23,894 Divestitures (2,069) 1,690 (379) Property swaps 1,773 — 1,773 Impairment — (180,000) (180,000) Foreign currency translation (208,017) 89,813 (118,204) Depletion — (725,267) (725,267) Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Baytex recorded impairment expense related to oil and gas properties of $180.0 million for the year ended December 31, 2019 and $285.3 million for the year ended December 31, 2018. At December 31, 2019, the Company identified indicators of impairment for its Peace River CGU due to a sustained decline in Canadian heavy oil prices and a reduction in planned exploration and development expenditures related to thermal properties in the Peace River CGU. The recoverable amount of the Peace River CGU was based on its VIU which was estimated using a discounted cash flow model using proved plus probable cash flows from an independent reserve report approved by the Board of Directors and an after-tax discount rate of 11%. The recoverable amount was not sufficient to support the carrying amount of the the CGU which resulted in an impairment of $180.0 million recorded as at December 31, 2019. There were no indicators of impairment or impairment reversal identified for the remaining CGUs as at December 31, 2019. The recoverable amount of the Peace River CGU was calculated at December 31, 2019 using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 WTI crude oil (US$/bbl) 61.00 63.75 66.18 67.91 69.48 71.07 72.68 74.24 75.73 77.24 WCS heavy oil (CA$/bbl) 57.57 62.35 64.33 66.23 67.97 69.72 71.49 73.20 74.80 76.43 AECO (CA$/GJ) 2.04 2.32 2.62 2.71 2.81 2.89 2.96 3.03 3.09 3.16 Exchange rate (CAD/USD) 1.32 1.30 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2.0%. The following table demonstrates the sensitivity of the estimated recoverable amount of the Peace River CGU to reasonably possible changes in key assumptions inherent in the estimate. Change in discount rate of 1% Change in oil price of $2.50/bbl Change in impairment expense $ 24,000 $ 88,000 At December 31, 2018, indicators of impairment existed for the Conventional CGU due to a sustained decline in Canadian natural gas prices and a reduction in planned capital exploration and development expenditures. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $65.0 million recorded as at December 31, 2018. The recoverable amount of the Conventional CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20%. At December 31, 2018, indicators of impairment existed for the Eagle Ford CGU due to the expected development plan outlined by the operator which resulted in a decline in the net present value of the cash flows of the proved plus probable reserves. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $220.3 million recorded as at December 31, 2018. The recoverable amount of the Eagle Ford CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20%. Cost Accumulated depreciation Net book value Balance, December 31, 2017 $ 62,648 $ (53,174) $ 9,474 Capital expenditures 1,804 — 1,804 Depreciation — (2,050) (2,050) Balance, December 31, 2018 $ 64,452 $ (55,224) $ 9,228 Capital expenditures 552 — 552 Depreciation — (2,182) (2,182) Balance, December 31, 2019 $ 65,004 $ (57,406) $ 7,598

Other Plant and Equipment

Other Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Property, plant and equipment [abstract]
Other Plant and Equipment	OIL AND GAS PROPERTIES Cost Accumulated Net book value Balance, December 31, 2017 $ 7,932,327 $ (3,974,018) $ 3,958,309 Capital expenditures 485,154 — 485,154 Corporate acquisition (note 4) 1,748,368 — 1,748,368 Property acquisitions 202 — 202 Transfers from exploration and evaluation assets (note 6) 13,866 — 13,866 Change in asset retirement obligations (note 12) 238,662 — 238,662 Divestitures (15) — (15) Impairment — (285,341) (285,341) Foreign currency translation 325,969 (110,651) 215,318 Depletion — (556,634) (556,634) Balance, December 31, 2018 $ 10,744,533 $ (4,926,644) $ 5,817,889 Capital expenditures 549,343 — 549,343 Property acquisitions 2,636 — 2,636 Transfers from exploration and evaluation assets (note 6) 16,204 — 16,204 Change in asset retirement obligations (note 12) 23,894 — 23,894 Divestitures (2,069) 1,690 (379) Property swaps 1,773 — 1,773 Impairment — (180,000) (180,000) Foreign currency translation (208,017) 89,813 (118,204) Depletion — (725,267) (725,267) Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Baytex recorded impairment expense related to oil and gas properties of $180.0 million for the year ended December 31, 2019 and $285.3 million for the year ended December 31, 2018. At December 31, 2019, the Company identified indicators of impairment for its Peace River CGU due to a sustained decline in Canadian heavy oil prices and a reduction in planned exploration and development expenditures related to thermal properties in the Peace River CGU. The recoverable amount of the Peace River CGU was based on its VIU which was estimated using a discounted cash flow model using proved plus probable cash flows from an independent reserve report approved by the Board of Directors and an after-tax discount rate of 11%. The recoverable amount was not sufficient to support the carrying amount of the the CGU which resulted in an impairment of $180.0 million recorded as at December 31, 2019. There were no indicators of impairment or impairment reversal identified for the remaining CGUs as at December 31, 2019. The recoverable amount of the Peace River CGU was calculated at December 31, 2019 using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 WTI crude oil (US$/bbl) 61.00 63.75 66.18 67.91 69.48 71.07 72.68 74.24 75.73 77.24 WCS heavy oil (CA$/bbl) 57.57 62.35 64.33 66.23 67.97 69.72 71.49 73.20 74.80 76.43 AECO (CA$/GJ) 2.04 2.32 2.62 2.71 2.81 2.89 2.96 3.03 3.09 3.16 Exchange rate (CAD/USD) 1.32 1.30 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2.0%. The following table demonstrates the sensitivity of the estimated recoverable amount of the Peace River CGU to reasonably possible changes in key assumptions inherent in the estimate. Change in discount rate of 1% Change in oil price of $2.50/bbl Change in impairment expense $ 24,000 $ 88,000 At December 31, 2018, indicators of impairment existed for the Conventional CGU due to a sustained decline in Canadian natural gas prices and a reduction in planned capital exploration and development expenditures. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $65.0 million recorded as at December 31, 2018. The recoverable amount of the Conventional CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20%. At December 31, 2018, indicators of impairment existed for the Eagle Ford CGU due to the expected development plan outlined by the operator which resulted in a decline in the net present value of the cash flows of the proved plus probable reserves. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $220.3 million recorded as at December 31, 2018. The recoverable amount of the Eagle Ford CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20%. Cost Accumulated depreciation Net book value Balance, December 31, 2017 $ 62,648 $ (53,174) $ 9,474 Capital expenditures 1,804 — 1,804 Depreciation — (2,050) (2,050) Balance, December 31, 2018 $ 64,452 $ (55,224) $ 9,228 Capital expenditures 552 — 552 Depreciation — (2,182) (2,182) Balance, December 31, 2019 $ 65,004 $ (57,406) $ 7,598

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	LEASES Lease Assets Baytex had the following right-of-use assets at December 31, 2019. Office Leases Field Equipment Vehicles and Other Total Balance, January 1, 2019 (1) $ 14,775 $ 2,254 $ 969 $ 17,998 Additions — 1,668 159 1,827 Modifications (6) 4 19 17 Depreciation (4,904) (837) (482) (6,223) Balance, December 31, 2019 $ 9,865 $ 3,089 $ 665 $ 13,619 (1) The Company adopted IFRS 16 Leases on January 1, 2019 using the modified retrospective approach. At December 31, 2018, the Company did not report any finance leases in accordance with its previous accounting policy for leases. Lease Obligations Baytex had the following future commitments associated with its lease obligations at December 31, 2019. December 31, 2019 Less than 1 year $ 6,216 1 - 3 years 7,748 3 - 5 years 604 After 5 years — Total lease payments $ 14,568 Amounts representing interest over the term of the lease (685) Present value of net lease payments $ 13,883 Less current portion of lease obligations 5,798 Non-current portion of lease obligations $ 8,085 The Company recorded interest expense related to its lease obligations of $0.6 million and recorded lease payments of $6.0 million for the year ended December 31, 2019.

Bank Loan

Bank Loan	12 Months Ended
	Dec. 31, 2019
Financial Instruments [Abstract]
Bank Loan	BANK LOAN December 31, 2019 December 31, 2018 Bank loan - U.S. dollar denominated (1) $ 206,144 $ 122,388 Bank loan - Canadian dollar denominated 300,327 399,906 Bank loan - principal (2) $ 506,471 $ 522,294 Unamortized debt issuance costs (1,059) (1,594) Bank loan $ 505,412 $ 520,700 (1) U.S. dollar denominated bank loan balance was US$159.0 million as at December 31, 2019 (US$89.7 million as at December 31, 2018). (2) The decrease in the principal amount of the bank loan outstanding from December 31, 2018 to December 31, 2019 is the result of loan repayments of $7.1 million and changes in the reported amount of U.S. denominated debt of $8.7 million. Baytex has US$575 million of revolving secured credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving secured term loan (the "Term Loan"). On May 2, 2019, Baytex amended its credit facilities to extend maturity from June 4, 2020 to April 2, 2021. On March 3, 2020, Baytex amended its credit facilities to extend maturity to April 2, 2024. These facilities will automatically be extended to June 4, 2024 providing Baytex has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The credit facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon Baytex's request. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates, plus applicable margins. In the event that Baytex breaches any of the covenants under the credit facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders. At December 31, 2019, Baytex had $15.2 million of outstanding letters of credit under the credit facilities (December 31, 2018 - $14.6 million). At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2019. Covenant Description Position as at December 31, 2019 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.52:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 9.42:1.00 2.00:1.00 (1) "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at December 31, 2019, the Company's Senior Secured Debt totaled $521.7 million which includes $506.5 million of principal amounts outstanding and $15.2 million of letters of credit. (2) Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2019 was $1,011.9 million. December 31, 2019 December 31, 2018 6.75% notes (US$150,000 – principal) due February 17, 2021 $ — $ 204,683 5.125% notes (US$400,000 – principal) due June 1, 2021 518,600 545,820 6.625% notes (Cdn$300,000 – principal) due July 19, 2022 300,000 300,000 5.625% notes (US$400,000 – principal) due June 1, 2024 518,600 545,820 Total long-term notes - principal (1) $ 1,337,200 $ 1,596,323 Unamortized debt issuance costs (9,025) (13,083) Total long-term notes - net of unamortized debt issuance costs $ 1,328,175 $ 1,583,240 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2018 to December 31, 2019 is the result of principal repayments of $198.1 million and changes in the reported amount of U.S. denominated debt of $61.0 million. On September 13, 2019, Baytex completed the early redemption of the US$150,000 principal amount of 6.75% senior unsecured notes, due February 17, 2021. The total principal payment was $198.1 million. The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts the Company's ability to raise additional debt beyond the existing credit facilities and long-term notes unless the Company maintains a minimum coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 10) to financing and interest expense on a trailing twelve month basis) of 2.50:1.00. As at December 31, 2019, the fixed charge coverage ratio was 8.04:1.00. On February 5, 2020, Baytex issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually in arrears (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.4 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.3 million. On February 20, 2020, Baytex used a portion of the net proceeds from the issuance of the 8.75% Senior Notes of $652.3 million to complete the early redemption of the US$400 million principal amount of the 5.125% senior unsecured notes due June 1, 2021 at par plus accrued interest. On February 5, 2020, the Company also issued a notice of redemption for the $300 million

Long-Term Notes

Long-Term Notes	12 Months Ended
	Dec. 31, 2019
Financial Instruments [Abstract]
Long-Term Notes	BANK LOAN December 31, 2019 December 31, 2018 Bank loan - U.S. dollar denominated (1) $ 206,144 $ 122,388 Bank loan - Canadian dollar denominated 300,327 399,906 Bank loan - principal (2) $ 506,471 $ 522,294 Unamortized debt issuance costs (1,059) (1,594) Bank loan $ 505,412 $ 520,700 (1) U.S. dollar denominated bank loan balance was US$159.0 million as at December 31, 2019 (US$89.7 million as at December 31, 2018). (2) The decrease in the principal amount of the bank loan outstanding from December 31, 2018 to December 31, 2019 is the result of loan repayments of $7.1 million and changes in the reported amount of U.S. denominated debt of $8.7 million. Baytex has US$575 million of revolving secured credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving secured term loan (the "Term Loan"). On May 2, 2019, Baytex amended its credit facilities to extend maturity from June 4, 2020 to April 2, 2021. On March 3, 2020, Baytex amended its credit facilities to extend maturity to April 2, 2024. These facilities will automatically be extended to June 4, 2024 providing Baytex has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The credit facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon Baytex's request. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates, plus applicable margins. In the event that Baytex breaches any of the covenants under the credit facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders. At December 31, 2019, Baytex had $15.2 million of outstanding letters of credit under the credit facilities (December 31, 2018 - $14.6 million). At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2019. Covenant Description Position as at December 31, 2019 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.52:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 9.42:1.00 2.00:1.00 (1) "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at December 31, 2019, the Company's Senior Secured Debt totaled $521.7 million which includes $506.5 million of principal amounts outstanding and $15.2 million of letters of credit. (2) Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2019 was $1,011.9 million. December 31, 2019 December 31, 2018 6.75% notes (US$150,000 – principal) due February 17, 2021 $ — $ 204,683 5.125% notes (US$400,000 – principal) due June 1, 2021 518,600 545,820 6.625% notes (Cdn$300,000 – principal) due July 19, 2022 300,000 300,000 5.625% notes (US$400,000 – principal) due June 1, 2024 518,600 545,820 Total long-term notes - principal (1) $ 1,337,200 $ 1,596,323 Unamortized debt issuance costs (9,025) (13,083) Total long-term notes - net of unamortized debt issuance costs $ 1,328,175 $ 1,583,240 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2018 to December 31, 2019 is the result of principal repayments of $198.1 million and changes in the reported amount of U.S. denominated debt of $61.0 million. On September 13, 2019, Baytex completed the early redemption of the US$150,000 principal amount of 6.75% senior unsecured notes, due February 17, 2021. The total principal payment was $198.1 million. The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts the Company's ability to raise additional debt beyond the existing credit facilities and long-term notes unless the Company maintains a minimum coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 10) to financing and interest expense on a trailing twelve month basis) of 2.50:1.00. As at December 31, 2019, the fixed charge coverage ratio was 8.04:1.00. On February 5, 2020, Baytex issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually in arrears (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.4 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.3 million. On February 20, 2020, Baytex used a portion of the net proceeds from the issuance of the 8.75% Senior Notes of $652.3 million to complete the early redemption of the US$400 million principal amount of the 5.125% senior unsecured notes due June 1, 2021 at par plus accrued interest. On February 5, 2020, the Company also issued a notice of redemption for the $300 million

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS December 31, 2019 December 31, 2018 Balance, beginning of year $ 646,898 $ 368,995 Liabilities incurred 21,748 12,537 Liabilities settled (15,417) (14,035) Liabilities assumed from corporate acquisition (note 4) — 39,960 Liabilities acquired from property acquisitions 1,648 132 Liabilities divested (1,331) (580) Property swaps 792 — Accretion (note 18) 13,713 10,914 Change in estimate (1) 19,632 33,453 Changes in discount rates and inflation rates (17,486) 192,672 Foreign currency translation (2,223) 2,850 Balance, end of year $ 667,974 $ 646,898 Less current portion of asset retirement obligations 11,579 — Non-current portion of asset retirement obligations $ 656,395 $ 646,898 (1) Changes in the estimated costs, the timing of abandonment and reclamation and the status of wells are factors resulting in a change in estimate. At December 31, 2019, the undiscounted amount of estimated cash flows required to settle the asset retirement obligations is $714.8 million (December 31, 2018 - $673.1 million). The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2019 calculated using an estimated inflation rate of 1.4% (December 31, 2018 - 2.0%) and a risk free rate discount rate of 1.8% (December 31, 2018 - 2.2%) is $668.0 million (December 31, 2018 - $646.9 million). These costs are expected to be incurred over the next 60 years.

Shareholders' Capital

Shareholders' Capital	12 Months Ended
	Dec. 31, 2019
Share Capital, Reserves And Other Equity Interest [Abstract]
Shareholders' Capital	SHAREHOLDERS' CAPITAL The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at December 31, 2019, no preferred shares have been issued by the Company and all common shares issued were fully paid. The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meetings of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated. Number of Common Shares (000s) Amount Balance, December 31, 2017 235,451 $ 4,443,576 Vesting of share awards 3,343 19,496 Issued on corporate acquisition (note 4) 315,266 1,238,995 Issuance costs, net of tax (note 4) — (551) Balance, December 31, 2018 554,060 $ 5,701,516 Vesting of share awards 4,245 17,319 Balance, December 31, 2019 558,305 $ 5,718,835

Share-Based Compensation Plan

Share-Based Compensation Plan	12 Months Ended
	Dec. 31, 2019
Share-Based Payment Arrangements [Abstract]
Share-Based Compensation Plan	SHARE-BASED COMPENSATION PLAN The Company recorded compensation expense related to the share awards and share options of $15.9 million for the year ended December 31, 2019 ($19.5 million for the year ended December 31, 2018). Share Awards The weighted average fair value of share awards granted during the year ended December 31, 2019 was $2.63 per restricted and performance award (December 31, 2018 - $4.04). The number of share awards outstanding is detailed below: (000s) Number of Number of performance awards (1) Total number of Balance, December 31, 2017 2,028 2,253 4,281 Granted 2,793 2,591 5,384 Assumed on corporate acquisition (2) 302 257 559 Vested and converted to common shares (1,682) (1,661) (3,343) Forfeited (198) (167) (365) Balance, December 31, 2018 3,243 3,273 6,516 Granted 3,184 3,245 6,429 Vested and converted to common shares (2,081) (2,164) (4,245) Forfeited (545) (1,219) (1,764) Balance, December 31, 2019 3,801 3,135 6,936 (1) Based on underlying awards before applying the payout multiplier which can range from 0x to 2x. (2) Following closing of the business combination (note 4), holders of 0.3 million Raging River restricted awards and 0.3 million performance awards are entitled to receive Baytex common shares rather than Raging River common shares, after adjusting the quantity of awards outstanding based on the exchange ratio. The payout multiplier for the performance awards is fixed at 1.0. The fair value assigned to the service period that had occurred prior to closing was included in consideration for the business combination. Share Options Baytex assumed share option plans pursuant to a business combination in 2018 (note 4). No new grants will be made under the option plans. The Company accounts for share options using the fair value method. Under this method, compensation is expensed over the vesting period for the share options, with a corresponding increase in contributed surplus. One third of the options granted will vest on each of the first, second, and third anniversaries of the date of grant. At December 31, 2019, 2.5 million share options with a weighted average exercise price of $6.83 were outstanding. The following tables summarize the information about the share options. (000s, except per common share amounts) Number of options Weighted average Balance, December 31, 2017 — $ — Assumed on corporate acquisition 9,187 6.63 Forfeited/Expired (4,322) 6.57 Balance, December 31, 2018 4,865 $ 6.70 Forfeited/Expired (2,390) 6.56 Balance, December 31, 2019 2,475 $ 6.83 Options Outstanding Options Exercisable Exercise price Number outstanding at December 31, 2019 (000s) Weighted average remaining life (years) Weighted Number exercisable at December 31, 2019 (000s) Weighted $5.00 - $7.00 1,654 0.79 $ 6.39 1,248 $ 6.42 $7.01 - $9.00 821 0.15 7.73 821 7.73 Total 2,475 0.58 $ 6.83 2,069 $ 6.94

Net Income (Loss) Per Share

Net Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2019
Earnings per share [abstract]
Net Income (Loss) Per Share	NET INCOME (LOSS) PER SHARE Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards and share options were exercised. The treasury stock method is used to determine the dilutive effect of share awards and share options whereby the proceeds from the potential exercise of share options and the amount of unrecognized share-based compensation expense on all share awards and share options, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the year. Years Ended December 31 2019 2018 Net loss Weighted average common shares (000's) Net loss per share Net loss Weighted average common shares (000's) Net loss per share Net loss - basic $ (12,459) 557,048 $ (0.02) $ (325,309) 351,542 $ (0.93) Dilutive effect of share awards — — — — — — Dilutive effect of share options — — — — — — Net loss - diluted $ (12,459) 557,048 $ (0.02) $ (325,309) 351,542 $ (0.93)

Petroleum and Natural Gas Sales

Petroleum and Natural Gas Sales	12 Months Ended
	Dec. 31, 2019
Disclosure of revenue from contracts with customers [Abstract]
Petroleum and Natural Gas Sales	PETROLEUM AND NATURAL GAS SALES The Company's petroleum and natural gas sales from contracts with customers for each reportable segment is set forth in the following table. Years Ended December 31 2019 2018 Canada U.S. Total Canada U.S. Total Light oil and condensate $ 538,487 $ 600,163 $ 1,138,650 $ 169,335 $ 637,055 $ 806,390 Heavy oil 500,187 — 500,187 411,794 — 411,794 NGL 8,430 60,647 69,077 14,531 97,008 111,539 Natural gas sales 30,620 67,385 98,005 23,555 75,592 99,147 Total petroleum and natural gas sales $ 1,077,724 $ 728,195 $ 1,805,919 $ 619,215 $ 809,655 $ 1,428,870 Included in accounts receivable at December 31, 2019 is $138.0 million (December 31, 2018 - $77.4 million) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Taxes [Abstract]
Income Taxes	INCOME TAXES The provision for income taxes has been computed as follows: Years Ended December 31 2019 2018 Net loss before income taxes $ (78,921) $ (427,076) Expected income taxes at the statutory rate of 26.72% (2018 – 27.00%) (21,088) (115,311) (Increase) decrease in income tax recovery resulting from: Share-based compensation 4,247 5,185 Non-taxable portion of foreign exchange (gain) loss (8,155) 14,467 Effect of change in income tax rates (6,098) — Effect of rate adjustments for foreign jurisdictions (27,785) (22,119) Effect of change in deferred tax benefit not recognized (1) (7,563) 14,467 Adjustments and assessments (20) 1,544 Income tax recovery $ (66,462) $ (101,767) (1) A deferred income tax asset has not been recognized for accumulated allowable capital losses of $109 million ($139 million as at December 31, 2018) related to the foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes. For the year ended December 31, 2019, the deferred tax recovery includes $6.1 million attributable to decreases in the Alberta provincial income tax rate for the period from July 1, 2019 to January 1, 2022, which reduced the provincial tax rate to 11% effective July 1, 2019, and further reduces it by 1% on January 1 st for each of the years 2020, 2021, and 2022, resulting in a provincial rate of 8%. In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the "CRA”) that deny $591 million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Office was assigned to the Company's file in July 2018. Baytex remains confident that the original tax filings are correct and intends to defend these tax filings through the appeals process. A continuity of the net deferred income tax liability is detailed in the following tables: As at January 1, 2019 Recognized in Net Income Foreign Currency Translation Adjustment December 31, 2019 Taxable temporary differences: Petroleum and natural gas properties $ (954,506) $ 48,995 $ 23,517 $ (881,994) Financial derivatives (21,486) 21,486 — — Other (3,045) 5,192 (4,550) (2,403) Deductible temporary differences: Asset retirement obligations 172,359 (7,364) (472) 164,523 Financial derivatives — 802 — 802 Non-capital losses 399,699 (1,460) (11,522) 386,717 Finance costs 96,143 904 — 97,047 Net deferred income tax liability (1) $ (310,836) $ 68,555 $ 6,973 $ (235,308) (1) Non-capital loss carry-forwards at December 31, 2019 totaled $1,714.6 million and expire from 2029 to 2039. As at January 1, 2018 Recognized in Net Loss Share Issuance Costs Business Combination Foreign Currency Translation Adjustment December 31, 2018 Taxable temporary differences: Petroleum and natural gas properties $ (696,427) $ (11,639) $ — $ (207,337) $ (39,103) $ (954,506) Financial derivatives — (22,984) — 1,498 — (21,486) Deferred income (17,827) 17,827 — — — — Other (5,956) (2,538) 209 — 5,240 (3,045) Deductible temporary differences: Asset retirement obligations 97,977 62,984 — 10,789 609 172,359 Financial derivatives 8,528 (8,528) — — — — Non-capital losses 330,749 48,725 — — 20,225 399,699 Finance costs 78,258 17,885 — — — 96,143 Net deferred income tax liability (1) $ (204,698) $ 101,732 $ 209 $ (195,050) $ (13,029) $ (310,836) (1) Non-capital loss carry-forwards at December 31, 2018 totaled $1,733.8 million and expire from 2029 to 2038.

Financing and Interest

Financing and Interest	12 Months Ended
	Dec. 31, 2019
Analysis of income and expense [abstract]
Financing and Interest	FINANCING AND INTEREST Years Ended December 31 2019 2018 Interest on bank loan $ 20,376 $ 15,637 Interest on long-term notes 86,431 88,681 Interest on lease obligations 610 — Non-cash financing 4,735 3,854 Accretion of asset retirement obligations (note 12) 13,713 10,914 Financing and interest $ 125,865 $ 119,086

Foreign Exchange

Foreign Exchange	12 Months Ended
	Dec. 31, 2019
Effects Of Changes In Foreign Exchange Rates [Abstract]
Foreign Exchange	FOREIGN EXCHANGE Years Ended December 31 2019 2018 Unrealized foreign exchange (gain) loss $ (62,753) $ 106,143 Realized foreign exchange loss 966 2,151 Foreign exchange (gain) loss $ (61,787) $ 108,294

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2019
Financial Instruments [Abstract]
Financial Instruments and Risk Management	FINANCIAL INSTRUMENTS AND RISK MANAGEMENTThe Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, bank loan, long-term notes, and lease obligations. The fair value of the bank loan is equal to the principal amount outstanding as the credit facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices. The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories: December 31, 2019 December 31, 2018 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 5,433 $ 5,433 $ 79,582 $ 79,582 Level 2 Total $ 5,433 $ 5,433 $ 79,582 $ 79,582 Financial assets at amortized cost Cash $ 5,572 $ 5,572 $ — $ — — Trade and other receivables 173,762 173,762 111,564 111,564 — Total $ 179,334 $ 179,334 $ 111,564 $ 111,564 Financial Liabilities FVTPL Financial Derivatives $ (8,668) $ (8,668) $ — $ — Level 2 Total $ (8,668) $ (8,668) $ — $ — Financial liabilities at amortized cost Trade and other payables $ (207,454) $ (207,454) $ (258,114) $ (258,114) — Bank loan (505,412) (506,471) (520,700) (522,294) — Long-term notes (1,328,175) (1,290,817) (1,583,240) (1,492,363) Level 1 Lease obligations (13,883) (13,883) — — — Total $ (2,054,924) $ (2,018,625) $ (2,362,054) $ (2,272,771) There were no transfers of financial instruments between Level 1 and Level 2 in during the years ended December 31, 2019 or 2018. Financial Risk Baytex is exposed to a variety of financial risks, including market risk, liquidity risk and credit risk. The Company's process to mitigate these risks is described below. Market Risk Market risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in market prices. Market risk is comprised of foreign currency risk, interest rate risk and commodity price risk. Foreign Currency Risk Baytex is exposed to fluctuations in foreign exchange rates as a result of the U.S. dollar portion of its bank loan and long-term notes, crude oil sales based on U.S. dollar benchmark prices and commodity financial derivative contracts that are settled in U.S. dollars. The Company's net income or loss, comprehensive income or loss and cash flow will therefore be impacted by fluctuations in foreign exchange rates. To manage the impact of foreign exchange rate fluctuations, the Company may enter into agreements to fix the Canadian to U.S. dollar exchange rate. At December 31, 2019 and 2018, the Company did not have any currency derivative contracts outstanding. A $0.01 increase or decrease in the CAD/USD foreign exchange rate on the revaluation of outstanding U.S. dollar denominated assets and liabilities, would impact net income or loss before income taxes by approxim ately $8.3 million. The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows: Assets Liabilities December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 U.S. dollar denominated US$8,733 US$80,857 US$841,961 US$963,351 Interest Rate Risk The Company's interest rate risk arises from borrowing at floating rates under the Revolving Facilities and Term Loan (note 10). Based on the Company's principal bank loan outstanding net of the interest rate swap, as at December 31, 2019, a change of 100 basis points in interest rates would have an impact on net income or loss before income taxes of approximately $4.1 million. Interest Rate Swaps The Company mitigates its exposure to interest rate risk by entering into interest rate swap transactions. As of March 3, 2020, Baytex had an interest rate swap outstanding with a notional value of $100 million maturing in October 2020, with a fixed contract price of 2.02% referencing the Canadian Dollar Offered Rate. At December 31, 2019, the interest rate swap had a fair value of zero (December 31, 2018 - $0.3 million). Commodity Price Risk Baytex utilizes financial derivative contracts or physical delivery contracts to manage the risk associated with changes in commodity prices. The use of derivatives is governed by a Risk Management Policy approved by the Board of Directors of Baytex which sets out limits on the use of derivatives. Baytex does not use financial derivatives for speculative purposes. Baytex's financial derivative contracts are subject to master netting agreements that create a legally enforceable right to offset by the counterparty the related financial assets and financial liabilities. When assessing the potential impact of crude oil price changes on the crude oil financial derivative contracts outstanding as at December 31, 2019, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $17.5 million. When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2019, a $0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $1.2 million. Financial Derivative Contracts Baytex had the following financial derivative contracts outstanding as of March 3, 2020: Remaining Period Volume Price/Unit (1) Index Oil Basis swap Jan 2020 to Dec 2020 2,500 bbl/d WTI less US$16.10/bbl WCS Basis swap (6) Apr 2020 to Dec 2020 4,000 bbl/d WTI less US$16.38/bbl WCS Basis swap Jan 2020 to Dec 2020 2,000 bbl/d WTI less US$6.50/bbl MSW Basis swap (6) Apr 2020 to Dec 2020 3,000 bbl/d WTI less US$5.92/bbl MSW Fixed - Sell Jan 2020 to Mar 2020 6,000 bbl/d US$56.60/bbl WTI Fixed - Sell Jan 2020 to Dec 2020 2,000 bbl/d US$58.00/bbl WTI 3-way option (2) Jan 2020 to Dec 2020 3,000 bbl/d US$50.00/US$56.00/US$61.35 WTI 3-way option (2) Jan 2020 to Dec 2020 3,000 bbl/d US$50.00/US$57.00/US$60.00 WTI 3-way option (2) Jan 2020 to Dec 2020 4,500 bbl/d US$50.00/US$57.00/US$62.00 WTI 3-way option (2) Jan 2020 to Dec 2020 3,000 bbl/d US$50.00/US$58.00/US$62.00 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$58.00/US$60.50 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$58.00/US$60.83 WTI 3-way option (2) Jan 2020 to Dec 2020 1,500 bbl/d US$51.00/US$59.00/US$65.60 WTI 3-way option (2) Jan 2020 to Dec 2020 1,500 bbl/d US$51.00/US$59.00/US$66.00 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$59.50/US$66.15 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$60.00/US$65.60 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$60.00/US$66.00 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$60.00/US$66.05 WTI 3-way option (2) Jan 2020 to Dec 2020 2,000 bbl/d US$51.00/US$60.00/US$66.70 WTI Swaption (3) Jan 2021 to Dec 2021 3,000 bbl/d US$64.50/bbl Brent Swaption (4) Jan 2021 to Dec 2021 3,000 bbl/d US$70.00/bbl Brent Swaption (4) Jan 2021 to Dec 2021 3,000 bbl/d US$60.75/bbl WTI Natural Gas 3-way option (2) Jan 2020 to Dec 2020 5,000 mmbtu/d US$2.25/US$2.60/US$2.85 NYMEX Swaption (5) Jan 2021 to Dec 2021 5,000 mmbtu/d US$2.90/mmbtu NYMEX (1) Based on the weighted average price per unit for the period. (2) Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US50/US$58.00/US$62.00 contract, Baytex receives WTI plus US$8.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$58.00/bbl when WTI is between US$50.00/bbl and US$58.00/bbl; Baytex receives the market price when WTI is between US$58.00/bbl and US$62.00/bbl; and Baytex receives US$62.00/bbl when WTI is above US$62.00/bbl. (3) For these contracts, the counterparty has the right, if exercised on September 30, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. (4) For these contracts, the counterparty has the right, if exercised on December 31, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. (5) For these contracts, the counterparty has the right, if exercised on December 23, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. (6) Contracts entered subsequent to December 31, 2019. The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives. Years Ended December 31 2019 2018 Realized financial derivatives (gain) loss $ (75,620) $ 73,165 Unrealized financial derivatives loss (gain) 82,817 (116,715) Financial derivatives loss (gain) $ 7,197 $ (43,550) Liquidity Risk Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Such strategies include monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements, opportunities to issue additional common shares as well as reducing capital expenditures. As at December 31, 2019, Baytex had available unused bank credit facilities in the amount of $523.8 million (December 31, 2018 - $547.7 million). In the event the Company is not able to comply with the financial covenants contained in agreements with its lenders, the Company's ability to access additional debt may be restricted. The timing of cash outflows relating to financial liabilities as at December 31, 2019 is outlined in the table below: Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Trade and other payables $ 207,454 $ 207,454 $ — $ — $ — Bank loan (1)(2) 506,471 — 506,471 — — Long-term notes (2) 1,337,200 — 818,600 518,600 — Interest on long-term notes (3) 217,247 75,625 100,303 41,319 — Lease obligations 14,568 6,216 7,748 604 — $ 2,282,940 $ 289,295 $ 1,433,122 $ 560,523 $ — (1) At December 31, 2019, the bank loan was set to mature on April 2, 2021. On March 3, 2020, Baytex amended the bank loan to extend maturity to April 2, 2024 which will automatically be extended to June 4, 2024 providing the Company has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. (2) Principal amount of instruments. On February 5, 2020, Baytex issued US$500 million principal amount of 8.75% senior unsecured notes due 2027 and issued a redemption notice for the $300 million principal amount of 6.625% senior unsecured notes due 2022 (note 11). The Company expects to complete the redemption of these notes on March 6, 2020. On February 20, 2020 Baytex completed the redemption of the US$400 million principal amount of senior unsecured notes due 2021 (note 11). (3) Excludes interest on bank loan as interest payments on bank loans fluctuate based on amounts outstanding and interest rates. Credit Risk Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31, 2019, the Company is exposed to credit risk with respect to its trade and other receivables and financial derivatives. Credit risk is considered very low for the Company's trade and other receivables and financial derivatives due to the external credit ratings of its counterparties and Baytex's process for selecting and monitoring credit-worthy counterparties. Most of the Company's trade and other receivables relate to petroleum and natural gas sales and are exposed to typical industry credit risks. Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts with only creditworthy entities. Letters of credit or parental guarantees may be obtained prior to the commencement of business with certain counterparties. Credit risk may also arise from financial derivative instruments. The maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company considers all financial assets that are not impaired or past due to be of good credit quality. The majority of the Company's credit exposure on accounts receivable at December 31, 2019 relates to accrued revenues for November and December 2019. Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day of the month following production. Joint interest receivables are typically collected within one three Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of accounts receivable is reduced by the use of an allowance for doubtful accounts and a charge to net income or loss. If the Company subsequently determines the accounts receivable is uncollectible, the receivable and allowance for doubtful accounts are adjusted accordingly. As at December 31, 2019, allowance for doubtful accounts was $1.6 million (December 31, 2018 - $1.9 million). In determining whether amounts past due are collectible, the Company will assess the nature of the past due amounts as well as the credit worthiness and past payment history of the counterparty. As at December 31, 2019, accounts receivable that Baytex has deemed past due (more than 90 days) but not impaired was $2.7 million (December 31, 2018 - $2.6 million). Baytex has estimated the lifetime expected credit loss as at and for the years ended December 31, 2019 to be nominal. The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2019. Trade and Other Receivables Aging December 31, 2019 December 31, 2018 Current (less than 30 days) $ 169,500 $ 104,099 31-60 days 1,199 3,037 61-90 days 342 1,842 Past due (more than 90 days) 2,721 2,586 $ 173,762 $ 111,564

Supplemental Information

Supplemental Information	12 Months Ended
	Dec. 31, 2019
Additional Information1 [Abstract]
Supplemental Information	SUPPLEMENTAL INFORMATION Change in Non-Cash Working Capital Items Years Ended December 31 2019 2018 Trade and other receivables $ (62,198) $ 1,280 Trade and other payables (50,660) 113,572 Non-cash working capital acquired (note 4) — (46,773) $ (112,858) $ 68,079 Changes in non-cash working capital related to: Operating activities $ (52,070) $ 39,448 Investing activities (62,485) 32,435 Foreign currency translation on non-cash working capital 1,697 (3,804) $ (112,858) $ 68,079 Income Statement Presentation Baytex's consolidated statements of income or loss and comprehensive income or loss are prepared primarily according to the nature of expense, with the exception of employee compensation costs which are included in both operating expense and general and administrative expense line items. The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense. Years Ended December 31 2019 2018 Operating $ 12,918 $ 12,140 General and administrative 33,728 34,963 Total employee compensation costs $ 46,646 $ 47,103

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments And Contingencies [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s cash flow from operations in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of December 31, 2019, and the expected timing of funding of these obligations, are noted in the table below. Total Less than 1-3 years 3-5 years Beyond 5 years Processing agreements 39,352 10,234 10,591 8,848 9,679 Transportation agreements 115,999 11,636 41,263 37,099 26,001 Total $ 155,351 $ 21,870 $ 51,854 $ 45,947 $ 35,680

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2019
Related Party [Abstract]
Related Parties	RELATED PARTIES Balances and transactions between the Company and its subsidiaries, which are related parties of the Company, have been eliminated on consolidation and are not disclosed separately in this note. Transactions with key management personnel and directors are noted in the table below. Years Ended December 31 2019 2018 Short-term employee benefits $ 6,202 $ 8,703 Share-based compensation 9,188 10,985 Termination payments 2,208 3,025 Total compensation for key management personnel $ 17,598 $ 22,713

Capital Management

Capital Management	12 Months Ended
	Dec. 31, 2019
Corporate Information And Statement Of IFRS Compliance [Abstract]
Capital Management	CAPITAL MANAGEMENT The Company's capital management objective is to maintain financial flexibility and sufficient sources of liquidity to execute its capital programs, while meeting short and long-term commitments. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At December 31, 2019, the Company's capital structure was comprised of shareholders' capital, long-term debt, working capital and the bank loan. Baytex monitors its estimated adjusted funds flow and the level of undrawn credit facilities. The Company's adjusted funds flow depends on a number of factors, including commodity prices, production and sales volumes, royalties, operating expenses, taxes and foreign exchange rates. In order to manage its capital structure and liquidity, Baytex may from time to time issue equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required. At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities and had unused capacity of $523.8 million (December 31, 2018 - $547.7 million). Baytex considers adjusted funds flow a key measure that provides a more complete understanding of operating performance and the Company's ability to generate funds for capital investments, debt repayment, settlement of abandonment obligations and potential future dividends. Baytex eliminates changes in non-cash working capital, transaction costs, and settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on the Company's capital programs and the maturity of its operating areas. The settlement of abandonment obligations are managed through the capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them from the calculation Baytex is able to provide a more meaningful measure of cash flow on a continuing basis. Transaction costs associated with business combinations (note 4) are excluded from adjusted funds flow as the costs are considered non-recurring and not reflective of the Company's ability to generate adjusted funds flow on an ongoing basis. Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with IFRS, such as cash flow from operating activities and net income or loss. Adjusted funds flow does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures for other entities. It is reconciled to the nearest measure determined in accordance with IFRS, cash flow from operating activities, as set forth below. Years Ended December 31 2019 2018 Cash flow from operating activities $ 834,939 $ 485,322 Change in non-cash working capital 52,070 (39,448) Asset retirement obligations settled 15,417 14,035 Transaction costs — 13,074 Adjusted funds flow $ 902,426 $ 472,983 The Company believes that net debt assists in providing a more complete understanding of its financial position and provides a key measure to assess liquidity. Net debt is calculated based on the principal amounts of the bank loan and long-term notes outstanding, net of working capital. The current portion of financial derivatives is excluded as the valuation of the underlying contracts is subject to a high degree of volatility prior to the ultimate settlement. Onerous contracts are excluded from net debt as the underlying contracts do not represent an available source of liquidity. The principal amounts of the bank loan and long-term notes outstanding are used in the calculation of net debt as these amounts represent the Company's ultimate repayment obligation at maturity. The carrying amount of debt issue costs associated with the bank loan and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source of liquidity or repayment obligation. Net debt does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measure for other entities. The computation of net debt is set forth below. December 31, 2019 December 31, 2018 Bank loan - principal $ 506,471 $ 522,294 Long-term notes - principal 1,337,200 1,596,323 Trade and other payables 207,454 258,114 Cash (5,572) — Trade and other receivables (173,762) (111,564) Net debt $ 1,871,791 $ 2,265,167

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Consolidation	Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany balances and transactions are eliminated in preparation of the consolidated financial statements. Many of the Company's exploration, development and production activities are conducted through joint arrangements. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by joint arrangements.
Business Combinations	Business Combinations Business combinations are accounted for using the acquisition method of accounting when the acquired assets meet the definition of a business under IFRS. The cost of an acquisition is measured as cash paid and the fair value of assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair value of the net identifiable assets acquired is recognized as goodwill. If the cost of acquisition is below the fair values of the identifiable net assets acquired, the difference is recognized as a bargain purchase gain in net income or loss. Associated transaction costs are expensed when incurred.
Revenue Recognition	Revenue Recognition Revenue from the sale of light oil and condensate, heavy oil, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis when Baytex acts in the capacity of an agent rather than as a principal. The transaction price for variable price contracts in the Canadian and U.S. operating segments is based on a representative commodity price index, and may include adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period. Tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.
Exploration and Evaluation Assets	Exploration and Evaluation Assets Pre-license costs, including certain geological, geophysical and seismic expenditures, are incurred before the legal rights to explore a specific area have been obtained. These costs are charged to exploration expense in the period in which they are incurred. Once the legal right to explore has been acquired, costs directly associated with an exploration program are capitalized as an intangible asset until results of the exploration program have been evaluated. Costs capitalized as E&E assets include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing of initial production results. E&E costs are subject to technical, commercial and management review to confirm the continued intent to develop or otherwise extract the underlying reserves. The technical feasibility and commercial viability of extracting petroleum and natural gas resources is dependent on the existence of economically recoverable reserves for the project. If the asset is determined not to be technically feasible or commercially viable the accumulated E&E costs associated with the exploration project are charged to E&E expense in the period the determination is made. Upon determination of technical feasibility and commercial viability, as evidenced by the classification of proved or probable reserves and management's intention to develop the E&E asset, the accumulated costs associated with the exploration project are tested for impairment and transferred to oil and gas properties.
Oil and Gas Properties	Oil and Gas Properties Items of oil and gas properties are initially recorded at cost. The initial cost of oil and gas properties includes the costs to acquire developed or producing oil and gas properties, and to develop oil and gas properties, such as costs of completing geological and geophysical surveys, drilling development wells, and the costs to construct and install development infrastructure such as wellhead equipment and processing facilities. Oil and gas properties includes costs related to planned major inspection, overhaul and turnaround activities to maintain items of oil and gas properties and benefit future years of operations. Replacements outside of a major inspection, overhaul or turnaround are recognized as oil and gas properties when it is probable the future economic benefits of the replacement will be realized by the Company. The carrying amount of any replaced or disposed item of oil and gas properties is derecognized. Repair and maintenance costs incurred for servicing an item of oil and gas properties is recorded as operating expense as incurred.
Depletion and Depreciation	Depletion and Depreciation The costs associated with an item of oil and gas properties are depleted on a unit-of-production basis by depletable area over proved plus probable reserves once commercial production has commenced. Future development costs required to bring those reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil equivalent. The depreciation methods and estimated useful lives for other plant and equipment are as follows: Classification Method Rate or period Motor Vehicles Diminishing balance 15% Office Equipment Diminishing balance 20% Computer Hardware Diminishing balance 30% Furniture and Fixtures Diminishing balance 10% Leasehold Improvements Straight-line over life of the lease Various Other Assets Diminishing balance Various
Impairment	Impairment Non-derivative financial assets The Company assesses non-derivative financial assets at each reporting date to determine whether there is any objective evidence indicating that it is impaired. Objective evidence exists if one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows. An impairment loss is reversed when there is objective evidence that the value of the financial assets has been partially or fully restored. For financial assets measured at amortized cost the reversal is recognized in net income or loss. Non-financial assets The Company reviews its non-financial assets, other than E&E assets, for indicators of impairment and impairment reversal at the end of each reporting period. The recoverable amount of the asset is estimated if indicators of impairment or impairment reversal exist. E&E assets are assessed for impairment when they are reclassified to oil and gas properties and if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. When reviewing for indicators of impairment and impairment reversal, and testing for impairment when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows includes CGU production volumes, royalty obligations, operating costs, capital costs, forecast commodity prices, along with inflation and discount rates used to estimate present value. FVLCD is determined as the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction between willing parties. In determining FVLCD, recent market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a discount rate that reflects current market assessments of the time value of money. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment reduces the carrying amount of any goodwill allocated to the CGU first, with any remaining impairment being allocated to the individual assets in the CGU on a pro-rata basis. Impairments may be reversed for all CGUs and individual assets, other than goodwill, when there is indication that a previously recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. An impairment may be reversed only to the extent that the asset’s revised carrying amount does not exceed the carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized. Impairment recognized in relation to goodwill is not reversed for subsequent increases in its recoverable amount. Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal occurs.
Leases	Leases 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. A lease obligation and corresponding right-of-use asset ("lease asset") are recognized at the commencement of the lease. The present value of the lease obligation is based on the future lease payments and is discounted using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with similar characteristics. The lease asset is recognized at the amount of the lease obligation, adjusted for lease incentives received and initial direct costs, on commencement of the lease. Depreciation is recognized on the lease asset over the shorter of the estimated useful life of the asset or the lease term. Lease payments are allocated between the liability and interest expense. Interest expense is recognized on the lease obligations using the effective interest rate method and payments are applied against the lease obligation.
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes asset retirement obligations when it has a legal or constructive obligation as a result of past events, it is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The Company’s asset retirement obligations are based on its net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and the facilities using existing technology and the estimated time period during which these costs will be incurred in the future. Asset retirement obligations are recognized for future asset retirement costs associated with the abandonment and reclamation of the Company's E&E assets and oil and gas properties. Asset retirement obligations are measured at the present value of management's best estimate of the future cash flows required to settle the present obligation, using the risk-free interest rate. The present value of the liability is capitalized as part of the cost of the related asset and depleted over its useful life. The asset retirement obligation is accreted until the date of expected settlement of the retirement obligation and is recognized within finance expense in the statements of income or loss. Changes in the future cash flow estimates resulting from revisions to the estimated timing or amount of undiscounted cash flows or the discount rates are recognized as changes in the asset retirement obligation provision and related asset at each reporting date.
Foreign Currency Translation	Foreign Currency Translation Foreign transactions Transactions completed in currencies other than the functional currency are translated into the functional currency at the exchange rates prevailing at the time of the transactions. Foreign currency assets and liabilities are translated to functional currency at the period-end exchange rate. Revenue and expenses are translated to functional currency using the average exchange rate for the period. Realized and unrealized gains and losses resulting from the settlement or translation of foreign currency transactions are included in net income or loss. Foreign operations The functional currency of the Company's subsidiaries is the currency of the primary economic environment in which the entity operates. Certain subsidiaries of the Company operate and transact primarily in currencies other than the Canadian dollar. The designation of a subsidiary's functional currency is a management judgment based on the currency of the primary economic environment in which the subsidiary operates. The financial statements of each entity are translated into Canadian dollars in preparation of the Company's consolidated financial statements. The assets and liabilities of a foreign operation are translated to Canadian dollars at the period-end exchange rate. Revenues and expenses of foreign operations are translated to Canadian dollars using the average exchange rate for the period. Foreign exchange differences are recognized in other comprehensive income or loss. If the Company or any of its entities disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign operation are recognized in net income or loss.
Financial Instruments	Financial Instruments IFRS 9 contains three principal classification categories for initial classification of financial assets: measured at amortized cost; fair value through other comprehensive income (“FVOCI”); or fair value through profit or loss (“FVTPL”). Financial assets are categorized based on the Company’s objective for the asset and the contractual cash flows. A financial asset is classified as amortized cost if the asset is held with the objective to collect contractual cash flows that are solely payments of principal and interest on principal amounts outstanding. A financial asset is classified as FVOCI if the asset is held with the objective to both collect contractual cash flows and sell the financial asset. All other financial assets are measured at FVTPL. Financial assets are assessed for impairment using an expected credit loss model. Trade and other receivables are classified and measured at amortized cost. The measurement categories for each class of financial asset and financial liability is set forth in the following table. Financial Instrument Classification Cash and cash equivalents Amortized cost Trade and other receivables Amortized cost Financial derivatives Fair value through profit or loss Trade and other payables Amortized cost Bank loan Amortized cost Long-term notes Amortized cost Lease obligations Amortized cost An embedded derivative is a component of a contract that modifies the cash flows of the contract. These hybrid contracts consist of a host contract and an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative unless the economic characteristics and risks of the embedded derivative are closely related to the host contract. The embedded derivatives are measured at FVTPL. Debt issuance costs related to the amendment our bank loan or the issuance of long term notes are capitalized and amortized as financing costs over the term of the credit facilities or long term notes. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract. The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The risk management policy permits the use of certain derivative financial instruments, including swaps and collars, to manage these fluctuations. All transactions of this nature entered into by the Company are related to underlying financial instruments or future petroleum and natural gas production. These instruments are classified as FVTPL. The Company does not use financial derivatives for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments by recording an asset or liability on the statements of financial position and recognizing changes in the fair value of the instrument in the statements of income or loss for the current period. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or loss when incurred. The Company has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are recognized in revenue in the period the product is delivered to the sales point.
Fair Value of Financial Instruments	Fair Value of Financial Instruments Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments: • Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. • Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. • Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.
Income Taxes	Income Taxes Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized directly in equity, in which case the current and deferred taxes are also recognized directly in equity. Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes the financial statement impact of a tax filing position when it is probable that the position will be sustained upon audit. The liability is measured based on an assessment of possible outcomes and their associated probabilities. The Company follows the balance sheet asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all temporary differences deductible to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs.
Share-based Compensation	Share-based Compensation Plans The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards (collectively, "share awards") may be granted to the directors, officers and employees of the Company and its subsidiaries. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plans of the Company) shall not at any time exceed 3.8% of the then-issued and outstanding common shares. Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus dividend equivalents). Each performance award entitles the holder to be issued the number of common shares designated in the performance award (plus dividend equivalents) multiplied by a payout multiplier. Expenses related to the Share Award Incentive Plan are determined based on the fair value of the share awards on the grant date which is based on quoted market prices for the Company's common shares. Both restricted and performance awards are expensed over the vesting period using the graded vesting method. The payout multiplier is dependent on the performance of the Company relative to pre-defined corporate performance measures for a particular period. In the case of both restricted and performance awards, the number of common shares to be issued on the applicable issue date is adjusted to account for the payments of dividends from the grant date to the applicable issue date. The Company assumed share awards and share options pursuant to a business combination in 2018 (note 4). The share options were valued at the closing date of the transaction utilizing a Black-Scholes pricing model to value the share options. The share awards were valued at fair value using the quoted market price of the Company's common shares on the closing date of the transaction. The share awards assumed consist of restricted share awards and performance share awards with a fixed multiplier of 1.0 .

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Depreciation methods and estimated useful lives for other plant and equipment	The depreciation methods and estimated useful lives for other plant and equipment are as follows: Classification Method Rate or period Motor Vehicles Diminishing balance 15% Office Equipment Diminishing balance 20% Computer Hardware Diminishing balance 30% Furniture and Fixtures Diminishing balance 10% Leasehold Improvements Straight-line over life of the lease Various Other Assets Diminishing balance Various Cost Accumulated Net book value Balance, December 31, 2017 $ 7,932,327 $ (3,974,018) $ 3,958,309 Capital expenditures 485,154 — 485,154 Corporate acquisition (note 4) 1,748,368 — 1,748,368 Property acquisitions 202 — 202 Transfers from exploration and evaluation assets (note 6) 13,866 — 13,866 Change in asset retirement obligations (note 12) 238,662 — 238,662 Divestitures (15) — (15) Impairment — (285,341) (285,341) Foreign currency translation 325,969 (110,651) 215,318 Depletion — (556,634) (556,634) Balance, December 31, 2018 $ 10,744,533 $ (4,926,644) $ 5,817,889 Capital expenditures 549,343 — 549,343 Property acquisitions 2,636 — 2,636 Transfers from exploration and evaluation assets (note 6) 16,204 — 16,204 Change in asset retirement obligations (note 12) 23,894 — 23,894 Divestitures (2,069) 1,690 (379) Property swaps 1,773 — 1,773 Impairment — (180,000) (180,000) Foreign currency translation (208,017) 89,813 (118,204) Depletion — (725,267) (725,267) Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Cost Accumulated depreciation Net book value Balance, December 31, 2017 $ 62,648 $ (53,174) $ 9,474 Capital expenditures 1,804 — 1,804 Depreciation — (2,050) (2,050) Balance, December 31, 2018 $ 64,452 $ (55,224) $ 9,228 Capital expenditures 552 — 552 Depreciation — (2,182) (2,182) Balance, December 31, 2019 $ 65,004 $ (57,406) $ 7,598

Business Combination (Tables)

Business Combination (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations1 [Abstract]
Estimates of fair value to assets acquired and liabilities assumed	The total consideration paid and estimates of the fair value of the assets acquired and liabilities assumed as at the date of the acquisition are set forth in the table below. Consideration Common shares issued $ 1,238,995 Share-based compensation (1) 3,100 Total consideration $ 1,242,095 Fair value of net assets acquired Exploration and evaluation assets $ 97,858 Oil and gas properties 1,748,368 Working capital deficiency excluding bank debt and financial derivatives (46,773) Financial derivatives (5,548) Bank debt (2) (316,800) Asset retirement obligations (39,960) Deferred income tax liability (195,050) Net assets acquired $ 1,242,095 (1) Following closing of the transaction, holders of units outstanding under Raging River's share-based compensation plans were entitled to Baytex common shares rather than Raging River common shares with adjustment to the exercise price or quantity outstanding based on the exchange ratio for the Raging River shares. As a result, the fair value assigned to the service period that had occurred prior to closing was recognized by Baytex as additional consideration (see note 14). (2) On August 22, 2018, Baytex amended its credit facilities to include the credit facility assumed in conjunction with the acquisition of Raging River and converted outstanding principal amounts to a non-revolving term loan.

Segmented Financial Informati_2

Segmented Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Operating Segments [Abstract]
Information by reportable segment	Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations: • Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada; • U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the U.S.; and • Corporate includes corporate activities and items not allocated between operating segments. Canada U.S. Corporate Consolidated Years Ended December 31 2019 2018 2019 2018 2019 2018 2019 2018 Revenue, net of royalties Petroleum and natural gas sales $ 1,077,724 $ 619,215 $ 728,195 $ 809,655 $ — $ — $ 1,805,919 $ 1,428,870 Royalties (107,467) (72,700) (212,774) (241,054) — — (320,241) (313,754) 970,257 546,515 515,421 568,601 — — 1,485,678 1,115,116 Expenses Operating 298,303 221,717 99,413 89,875 — — 397,716 311,592 Transportation 43,942 36,869 — — — — 43,942 36,869 Blending and other 68,795 68,832 — — — — 68,795 68,832 General and administrative — — — — 45,469 45,825 45,469 45,825 Transaction costs — — — — — 13,074 — 13,074 Exploration and evaluation 11,764 10,580 — 11,149 — — 11,764 21,729 Depletion and depreciation 463,501 294,925 261,766 261,709 6,419 2,050 731,686 558,684 Impairment 187,822 65,000 — 220,341 — — 187,822 285,341 Share-based compensation — — — — 15,894 19,534 15,894 19,534 Financing and interest — — — — 125,865 119,086 125,865 119,086 Financial derivatives loss (gain) — — — — 7,197 (43,550) 7,197 (43,550) Foreign exchange (gain) loss — — — — (61,787) 108,294 (61,787) 108,294 Gain on dispositions (2,238) (1,946) — — — — (2,238) (1,946) Other income — — — — (7,526) (1,172) (7,526) (1,172) 1,071,889 695,977 361,179 583,074 131,531 263,141 1,564,599 1,542,192 Net income (loss) before income taxes (101,632) (149,462) 154,242 (14,473) (131,531) (263,141) (78,921) (427,076) Income tax expense (recovery) Current income tax expense (recovery) 101 — 1,992 (35) — — 2,093 (35) Deferred income tax expense (recovery) (32,942) (40,723) 10,055 (26,049) (45,668) (34,960) (68,555) (101,732) (32,841) (40,723) 12,047 (26,084) (45,668) (34,960) (66,462) (101,767) Net income (loss) $ (68,791) $ (108,739) $ 142,195 $ 11,611 $ (85,863) $ (228,181) $ (12,459) $ (325,309) Total oil and natural gas capital expenditures (1) $ 376,543 $ 300,299 $ 177,928 $ 193,604 $ — $ — $ 554,471 $ 493,903
Assets by segment	As at December 31, 2019 December 31, 2018 Canadian assets $ 3,484,123 $ 3,739,029 U.S. assets 2,403,310 2,628,941 Corporate assets 26,650 9,228 Total consolidated assets $ 5,914,083 $ 6,377,198

Exploration and Evaluation As_2

Exploration and Evaluation Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Exploration For And Evaluation Of Mineral Resources [Abstract]
Exploration and evaluation assets	December 31, 2019 December 31, 2018 Balance, beginning of year $ 358,935 $ 272,974 Capital expenditures 2,948 10,567 Corporate acquisition (note 4) — 97,858 Property acquisitions 1,523 514 Divestitures (443) (1,021) Impairment (7,822) — Property swaps 417 — Exploration and evaluation expense (11,764) (21,729) Transfers to oil and gas properties (note 7) (16,204) (13,866) Foreign currency translation (7,380) 13,638 Balance, end of year $ 320,210 $ 358,935

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2019
Property, plant and equipment [abstract]
Plant and equipment	The depreciation methods and estimated useful lives for other plant and equipment are as follows: Classification Method Rate or period Motor Vehicles Diminishing balance 15% Office Equipment Diminishing balance 20% Computer Hardware Diminishing balance 30% Furniture and Fixtures Diminishing balance 10% Leasehold Improvements Straight-line over life of the lease Various Other Assets Diminishing balance Various Cost Accumulated Net book value Balance, December 31, 2017 $ 7,932,327 $ (3,974,018) $ 3,958,309 Capital expenditures 485,154 — 485,154 Corporate acquisition (note 4) 1,748,368 — 1,748,368 Property acquisitions 202 — 202 Transfers from exploration and evaluation assets (note 6) 13,866 — 13,866 Change in asset retirement obligations (note 12) 238,662 — 238,662 Divestitures (15) — (15) Impairment — (285,341) (285,341) Foreign currency translation 325,969 (110,651) 215,318 Depletion — (556,634) (556,634) Balance, December 31, 2018 $ 10,744,533 $ (4,926,644) $ 5,817,889 Capital expenditures 549,343 — 549,343 Property acquisitions 2,636 — 2,636 Transfers from exploration and evaluation assets (note 6) 16,204 — 16,204 Change in asset retirement obligations (note 12) 23,894 — 23,894 Divestitures (2,069) 1,690 (379) Property swaps 1,773 — 1,773 Impairment — (180,000) (180,000) Foreign currency translation (208,017) 89,813 (118,204) Depletion — (725,267) (725,267) Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Cost Accumulated depreciation Net book value Balance, December 31, 2017 $ 62,648 $ (53,174) $ 9,474 Capital expenditures 1,804 — 1,804 Depreciation — (2,050) (2,050) Balance, December 31, 2018 $ 64,452 $ (55,224) $ 9,228 Capital expenditures 552 — 552 Depreciation — (2,182) (2,182) Balance, December 31, 2019 $ 65,004 $ (57,406) $ 7,598
Disclosure of recoverable amount of CGU benchmark reference prices	The recoverable amount of the Peace River CGU was calculated at December 31, 2019 using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 WTI crude oil (US$/bbl) 61.00 63.75 66.18 67.91 69.48 71.07 72.68 74.24 75.73 77.24 WCS heavy oil (CA$/bbl) 57.57 62.35 64.33 66.23 67.97 69.72 71.49 73.20 74.80 76.43 AECO (CA$/GJ) 2.04 2.32 2.62 2.71 2.81 2.89 2.96 3.03 3.09 3.16 Exchange rate (CAD/USD) 1.32 1.30 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27
Sensitivity of The Estimated Recoverable Amount of Changes in Assumptions	The following table demonstrates the sensitivity of the estimated recoverable amount of the Peace River CGU to reasonably possible changes in key assumptions inherent in the estimate. Change in discount rate of 1% Change in oil price of $2.50/bbl Change in impairment expense $ 24,000 $ 88,000

Other Plant and Equipment (Tabl

Other Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, plant and equipment [abstract]
Plant and equipment	The depreciation methods and estimated useful lives for other plant and equipment are as follows: Classification Method Rate or period Motor Vehicles Diminishing balance 15% Office Equipment Diminishing balance 20% Computer Hardware Diminishing balance 30% Furniture and Fixtures Diminishing balance 10% Leasehold Improvements Straight-line over life of the lease Various Other Assets Diminishing balance Various Cost Accumulated Net book value Balance, December 31, 2017 $ 7,932,327 $ (3,974,018) $ 3,958,309 Capital expenditures 485,154 — 485,154 Corporate acquisition (note 4) 1,748,368 — 1,748,368 Property acquisitions 202 — 202 Transfers from exploration and evaluation assets (note 6) 13,866 — 13,866 Change in asset retirement obligations (note 12) 238,662 — 238,662 Divestitures (15) — (15) Impairment — (285,341) (285,341) Foreign currency translation 325,969 (110,651) 215,318 Depletion — (556,634) (556,634) Balance, December 31, 2018 $ 10,744,533 $ (4,926,644) $ 5,817,889 Capital expenditures 549,343 — 549,343 Property acquisitions 2,636 — 2,636 Transfers from exploration and evaluation assets (note 6) 16,204 — 16,204 Change in asset retirement obligations (note 12) 23,894 — 23,894 Divestitures (2,069) 1,690 (379) Property swaps 1,773 — 1,773 Impairment — (180,000) (180,000) Foreign currency translation (208,017) 89,813 (118,204) Depletion — (725,267) (725,267) Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Cost Accumulated depreciation Net book value Balance, December 31, 2017 $ 62,648 $ (53,174) $ 9,474 Capital expenditures 1,804 — 1,804 Depreciation — (2,050) (2,050) Balance, December 31, 2018 $ 64,452 $ (55,224) $ 9,228 Capital expenditures 552 — 552 Depreciation — (2,182) (2,182) Balance, December 31, 2019 $ 65,004 $ (57,406) $ 7,598

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Disclosure Of Right Of Use Assets and Depreciation	Baytex had the following right-of-use assets at December 31, 2019. Office Leases Field Equipment Vehicles and Other Total Balance, January 1, 2019 (1) $ 14,775 $ 2,254 $ 969 $ 17,998 Additions — 1,668 159 1,827 Modifications (6) 4 19 17 Depreciation (4,904) (837) (482) (6,223) Balance, December 31, 2019 $ 9,865 $ 3,089 $ 665 $ 13,619 (1) The Company adopted IFRS 16 Leases on January 1, 2019 using the modified retrospective approach. At December 31, 2018, the Company did not report any finance leases in accordance with its previous accounting policy for leases.
Disclosure of Future Commitment Obligations	Baytex had the following future commitments associated with its lease obligations at December 31, 2019. December 31, 2019 Less than 1 year $ 6,216 1 - 3 years 7,748 3 - 5 years 604 After 5 years — Total lease payments $ 14,568 Amounts representing interest over the term of the lease (685) Present value of net lease payments $ 13,883 Less current portion of lease obligations 5,798 Non-current portion of lease obligations $ 8,085 The Company recorded interest expense related to its lease obligations of $0.6 million and recorded lease payments of $6.0 million for the year ended December 31, 2019.

Bank Loan (Tables)

Bank Loan (Tables)	12 Months Ended
	Dec. 31, 2019
Financial Instruments [Abstract]
Bank loans	December 31, 2019 December 31, 2018 Bank loan - U.S. dollar denominated (1) $ 206,144 $ 122,388 Bank loan - Canadian dollar denominated 300,327 399,906 Bank loan - principal (2) $ 506,471 $ 522,294 Unamortized debt issuance costs (1,059) (1,594) Bank loan $ 505,412 $ 520,700 (1) U.S. dollar denominated bank loan balance was US$159.0 million as at December 31, 2019 (US$89.7 million as at December 31, 2018). (2) The decrease in the principal amount of the bank loan outstanding from December 31, 2018 to December 31, 2019 is the result of loan repayments of $7.1 million and changes in the reported amount of U.S. denominated debt of $8.7 million. At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2019. Covenant Description Position as at December 31, 2019 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.52:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 9.42:1.00 2.00:1.00 (1) "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at December 31, 2019, the Company's Senior Secured Debt totaled $521.7 million which includes $506.5 million of principal amounts outstanding and $15.2 million of letters of credit. (2) Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2019 was $1,011.9 million. December 31, 2019 December 31, 2018 6.75% notes (US$150,000 – principal) due February 17, 2021 $ — $ 204,683 5.125% notes (US$400,000 – principal) due June 1, 2021 518,600 545,820 6.625% notes (Cdn$300,000 – principal) due July 19, 2022 300,000 300,000 5.625% notes (US$400,000 – principal) due June 1, 2024 518,600 545,820 Total long-term notes - principal (1) $ 1,337,200 $ 1,596,323 Unamortized debt issuance costs (9,025) (13,083) Total long-term notes - net of unamortized debt issuance costs $ 1,328,175 $ 1,583,240 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2018 to December 31, 2019 is the result of principal repayments of $198.1 million and changes in the reported amount of U.S. denominated debt of $61.0 million.

Long-Term Notes (Tables)

Long-Term Notes (Tables)	12 Months Ended
	Dec. 31, 2019
Financial Instruments [Abstract]
Long-term notes	December 31, 2019 December 31, 2018 Bank loan - U.S. dollar denominated (1) $ 206,144 $ 122,388 Bank loan - Canadian dollar denominated 300,327 399,906 Bank loan - principal (2) $ 506,471 $ 522,294 Unamortized debt issuance costs (1,059) (1,594) Bank loan $ 505,412 $ 520,700 (1) U.S. dollar denominated bank loan balance was US$159.0 million as at December 31, 2019 (US$89.7 million as at December 31, 2018). (2) The decrease in the principal amount of the bank loan outstanding from December 31, 2018 to December 31, 2019 is the result of loan repayments of $7.1 million and changes in the reported amount of U.S. denominated debt of $8.7 million. At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2019. Covenant Description Position as at December 31, 2019 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.52:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 9.42:1.00 2.00:1.00 (1) "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at December 31, 2019, the Company's Senior Secured Debt totaled $521.7 million which includes $506.5 million of principal amounts outstanding and $15.2 million of letters of credit. (2) Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2019 was $1,011.9 million. December 31, 2019 December 31, 2018 6.75% notes (US$150,000 – principal) due February 17, 2021 $ — $ 204,683 5.125% notes (US$400,000 – principal) due June 1, 2021 518,600 545,820 6.625% notes (Cdn$300,000 – principal) due July 19, 2022 300,000 300,000 5.625% notes (US$400,000 – principal) due June 1, 2024 518,600 545,820 Total long-term notes - principal (1) $ 1,337,200 $ 1,596,323 Unamortized debt issuance costs (9,025) (13,083) Total long-term notes - net of unamortized debt issuance costs $ 1,328,175 $ 1,583,240 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2018 to December 31, 2019 is the result of principal repayments of $198.1 million and changes in the reported amount of U.S. denominated debt of $61.0 million.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Change in asset retirement obligations	December 31, 2019 December 31, 2018 Balance, beginning of year $ 646,898 $ 368,995 Liabilities incurred 21,748 12,537 Liabilities settled (15,417) (14,035) Liabilities assumed from corporate acquisition (note 4) — 39,960 Liabilities acquired from property acquisitions 1,648 132 Liabilities divested (1,331) (580) Property swaps 792 — Accretion (note 18) 13,713 10,914 Change in estimate (1) 19,632 33,453 Changes in discount rates and inflation rates (17,486) 192,672 Foreign currency translation (2,223) 2,850 Balance, end of year $ 667,974 $ 646,898 Less current portion of asset retirement obligations 11,579 — Non-current portion of asset retirement obligations $ 656,395 $ 646,898

Shareholders' Capital (Tables)

Shareholders' Capital (Tables)	12 Months Ended
	Dec. 31, 2019
Share Capital, Reserves And Other Equity Interest [Abstract]
Schedule of shareholders' capital	All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated. Number of Common Shares (000s) Amount Balance, December 31, 2017 235,451 $ 4,443,576 Vesting of share awards 3,343 19,496 Issued on corporate acquisition (note 4) 315,266 1,238,995 Issuance costs, net of tax (note 4) — (551) Balance, December 31, 2018 554,060 $ 5,701,516 Vesting of share awards 4,245 17,319 Balance, December 31, 2019 558,305 $ 5,718,835

Share-Based Compensation Plan (

Share-Based Compensation Plan (Tables)	12 Months Ended
	Dec. 31, 2019
Share-Based Payment Arrangements [Abstract]
Number of share awards outstanding	The number of share awards outstanding is detailed below: (000s) Number of Number of performance awards (1) Total number of Balance, December 31, 2017 2,028 2,253 4,281 Granted 2,793 2,591 5,384 Assumed on corporate acquisition (2) 302 257 559 Vested and converted to common shares (1,682) (1,661) (3,343) Forfeited (198) (167) (365) Balance, December 31, 2018 3,243 3,273 6,516 Granted 3,184 3,245 6,429 Vested and converted to common shares (2,081) (2,164) (4,245) Forfeited (545) (1,219) (1,764) Balance, December 31, 2019 3,801 3,135 6,936 (1) Based on underlying awards before applying the payout multiplier which can range from 0x to 2x. (2) Following closing of the business combination (note 4), holders of 0.3 million Raging River restricted awards and 0.3 million performance awards are entitled to receive Baytex common shares rather than Raging River common shares, after adjusting the quantity of awards outstanding based on the exchange ratio. The payout multiplier for the performance awards is fixed at 1.0. The fair value assigned to the service period that had occurred prior to closing was included in consideration for the business combination.
Disclosure of number and weighted average exercise prices of share options	The following tables summarize the information about the share options. (000s, except per common share amounts) Number of options Weighted average Balance, December 31, 2017 — $ — Assumed on corporate acquisition 9,187 6.63 Forfeited/Expired (4,322) 6.57 Balance, December 31, 2018 4,865 $ 6.70 Forfeited/Expired (2,390) 6.56 Balance, December 31, 2019 2,475 $ 6.83 Options Outstanding Options Exercisable Exercise price Number outstanding at December 31, 2019 (000s) Weighted average remaining life (years) Weighted Number exercisable at December 31, 2019 (000s) Weighted $5.00 - $7.00 1,654 0.79 $ 6.39 1,248 $ 6.42 $7.01 - $9.00 821 0.15 7.73 821 7.73 Total 2,475 0.58 $ 6.83 2,069 $ 6.94

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings per share [abstract]
Net income (loss) per share	Years Ended December 31 2019 2018 Net loss Weighted average common shares (000's) Net loss per share Net loss Weighted average common shares (000's) Net loss per share Net loss - basic $ (12,459) 557,048 $ (0.02) $ (325,309) 351,542 $ (0.93) Dilutive effect of share awards — — — — — — Dilutive effect of share options — — — — — — Net loss - diluted $ (12,459) 557,048 $ (0.02) $ (325,309) 351,542 $ (0.93)

Petroleum and Natural Gas Sal_2

Petroleum and Natural Gas Sales (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of revenue from contracts with customers [Abstract]
Disclosure of disaggregation of revenue from contracts with customers	The Company's petroleum and natural gas sales from contracts with customers for each reportable segment is set forth in the following table. Years Ended December 31 2019 2018 Canada U.S. Total Canada U.S. Total Light oil and condensate $ 538,487 $ 600,163 $ 1,138,650 $ 169,335 $ 637,055 $ 806,390 Heavy oil 500,187 — 500,187 411,794 — 411,794 NGL 8,430 60,647 69,077 14,531 97,008 111,539 Natural gas sales 30,620 67,385 98,005 23,555 75,592 99,147 Total petroleum and natural gas sales $ 1,077,724 $ 728,195 $ 1,805,919 $ 619,215 $ 809,655 $ 1,428,870

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Taxes [Abstract]
Provision for income taxes	The provision for income taxes has been computed as follows: Years Ended December 31 2019 2018 Net loss before income taxes $ (78,921) $ (427,076) Expected income taxes at the statutory rate of 26.72% (2018 – 27.00%) (21,088) (115,311) (Increase) decrease in income tax recovery resulting from: Share-based compensation 4,247 5,185 Non-taxable portion of foreign exchange (gain) loss (8,155) 14,467 Effect of change in income tax rates (6,098) — Effect of rate adjustments for foreign jurisdictions (27,785) (22,119) Effect of change in deferred tax benefit not recognized (1) (7,563) 14,467 Adjustments and assessments (20) 1,544 Income tax recovery $ (66,462) $ (101,767) (1) A deferred income tax asset has not been recognized for accumulated allowable capital losses of $109 million ($139 million as at December 31, 2018) related to the foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes.
Continuity of net deferred income tax liability	A continuity of the net deferred income tax liability is detailed in the following tables: As at January 1, 2019 Recognized in Net Income Foreign Currency Translation Adjustment December 31, 2019 Taxable temporary differences: Petroleum and natural gas properties $ (954,506) $ 48,995 $ 23,517 $ (881,994) Financial derivatives (21,486) 21,486 — — Other (3,045) 5,192 (4,550) (2,403) Deductible temporary differences: Asset retirement obligations 172,359 (7,364) (472) 164,523 Financial derivatives — 802 — 802 Non-capital losses 399,699 (1,460) (11,522) 386,717 Finance costs 96,143 904 — 97,047 Net deferred income tax liability (1) $ (310,836) $ 68,555 $ 6,973 $ (235,308) (1) Non-capital loss carry-forwards at December 31, 2019 totaled $1,714.6 million and expire from 2029 to 2039. As at January 1, 2018 Recognized in Net Loss Share Issuance Costs Business Combination Foreign Currency Translation Adjustment December 31, 2018 Taxable temporary differences: Petroleum and natural gas properties $ (696,427) $ (11,639) $ — $ (207,337) $ (39,103) $ (954,506) Financial derivatives — (22,984) — 1,498 — (21,486) Deferred income (17,827) 17,827 — — — — Other (5,956) (2,538) 209 — 5,240 (3,045) Deductible temporary differences: Asset retirement obligations 97,977 62,984 — 10,789 609 172,359 Financial derivatives 8,528 (8,528) — — — — Non-capital losses 330,749 48,725 — — 20,225 399,699 Finance costs 78,258 17,885 — — — 96,143 Net deferred income tax liability (1) $ (204,698) $ 101,732 $ 209 $ (195,050) $ (13,029) $ (310,836) (1) Non-capital loss carry-forwards at December 31, 2018 totaled $1,733.8 million and expire from 2029 to 2038.

Financing and Interest (Tables)

Financing and Interest (Tables)	12 Months Ended
	Dec. 31, 2019
Analysis of income and expense [abstract]
Schedule of financing and interest	Years Ended December 31 2019 2018 Interest on bank loan $ 20,376 $ 15,637 Interest on long-term notes 86,431 88,681 Interest on lease obligations 610 — Non-cash financing 4,735 3,854 Accretion of asset retirement obligations (note 12) 13,713 10,914 Financing and interest $ 125,865 $ 119,086

Foreign Exchange (Tables)

Foreign Exchange (Tables)	12 Months Ended
	Dec. 31, 2019
Effects Of Changes In Foreign Exchange Rates [Abstract]
Foreign exchange gains and losses	Years Ended December 31 2019 2018 Unrealized foreign exchange (gain) loss $ (62,753) $ 106,143 Realized foreign exchange loss 966 2,151 Foreign exchange (gain) loss $ (61,787) $ 108,294

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2019
Financial Instruments [Abstract]
Disclosure of financial assets	The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories: December 31, 2019 December 31, 2018 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 5,433 $ 5,433 $ 79,582 $ 79,582 Level 2 Total $ 5,433 $ 5,433 $ 79,582 $ 79,582 Financial assets at amortized cost Cash $ 5,572 $ 5,572 $ — $ — — Trade and other receivables 173,762 173,762 111,564 111,564 — Total $ 179,334 $ 179,334 $ 111,564 $ 111,564 Financial Liabilities FVTPL Financial Derivatives $ (8,668) $ (8,668) $ — $ — Level 2 Total $ (8,668) $ (8,668) $ — $ — Financial liabilities at amortized cost Trade and other payables $ (207,454) $ (207,454) $ (258,114) $ (258,114) — Bank loan (505,412) (506,471) (520,700) (522,294) — Long-term notes (1,328,175) (1,290,817) (1,583,240) (1,492,363) Level 1 Lease obligations (13,883) (13,883) — — — Total $ (2,054,924) $ (2,018,625) $ (2,362,054) $ (2,272,771)
Disclosure of financial liabilities	The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories: December 31, 2019 December 31, 2018 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 5,433 $ 5,433 $ 79,582 $ 79,582 Level 2 Total $ 5,433 $ 5,433 $ 79,582 $ 79,582 Financial assets at amortized cost Cash $ 5,572 $ 5,572 $ — $ — — Trade and other receivables 173,762 173,762 111,564 111,564 — Total $ 179,334 $ 179,334 $ 111,564 $ 111,564 Financial Liabilities FVTPL Financial Derivatives $ (8,668) $ (8,668) $ — $ — Level 2 Total $ (8,668) $ (8,668) $ — $ — Financial liabilities at amortized cost Trade and other payables $ (207,454) $ (207,454) $ (258,114) $ (258,114) — Bank loan (505,412) (506,471) (520,700) (522,294) — Long-term notes (1,328,175) (1,290,817) (1,583,240) (1,492,363) Level 1 Lease obligations (13,883) (13,883) — — — Total $ (2,054,924) $ (2,018,625) $ (2,362,054) $ (2,272,771)
Carrying amounts of U.S. dollar denominated monetary assets and liabilities	The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows: Assets Liabilities December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 U.S. dollar denominated US$8,733 US$80,857 US$841,961 US$963,351
Disclosure of financial derivative contracts	Baytex had the following financial derivative contracts outstanding as of March 3, 2020: Remaining Period Volume Price/Unit (1) Index Oil Basis swap Jan 2020 to Dec 2020 2,500 bbl/d WTI less US$16.10/bbl WCS Basis swap (6) Apr 2020 to Dec 2020 4,000 bbl/d WTI less US$16.38/bbl WCS Basis swap Jan 2020 to Dec 2020 2,000 bbl/d WTI less US$6.50/bbl MSW Basis swap (6) Apr 2020 to Dec 2020 3,000 bbl/d WTI less US$5.92/bbl MSW Fixed - Sell Jan 2020 to Mar 2020 6,000 bbl/d US$56.60/bbl WTI Fixed - Sell Jan 2020 to Dec 2020 2,000 bbl/d US$58.00/bbl WTI 3-way option (2) Jan 2020 to Dec 2020 3,000 bbl/d US$50.00/US$56.00/US$61.35 WTI 3-way option (2) Jan 2020 to Dec 2020 3,000 bbl/d US$50.00/US$57.00/US$60.00 WTI 3-way option (2) Jan 2020 to Dec 2020 4,500 bbl/d US$50.00/US$57.00/US$62.00 WTI 3-way option (2) Jan 2020 to Dec 2020 3,000 bbl/d US$50.00/US$58.00/US$62.00 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$58.00/US$60.50 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$58.00/US$60.83 WTI 3-way option (2) Jan 2020 to Dec 2020 1,500 bbl/d US$51.00/US$59.00/US$65.60 WTI 3-way option (2) Jan 2020 to Dec 2020 1,500 bbl/d US$51.00/US$59.00/US$66.00 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$59.50/US$66.15 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$60.00/US$65.60 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$60.00/US$66.00 WTI 3-way option (2) Jan 2020 to Dec 2020 1,000 bbl/d US$51.00/US$60.00/US$66.05 WTI 3-way option (2) Jan 2020 to Dec 2020 2,000 bbl/d US$51.00/US$60.00/US$66.70 WTI Swaption (3) Jan 2021 to Dec 2021 3,000 bbl/d US$64.50/bbl Brent Swaption (4) Jan 2021 to Dec 2021 3,000 bbl/d US$70.00/bbl Brent Swaption (4) Jan 2021 to Dec 2021 3,000 bbl/d US$60.75/bbl WTI Natural Gas 3-way option (2) Jan 2020 to Dec 2020 5,000 mmbtu/d US$2.25/US$2.60/US$2.85 NYMEX Swaption (5) Jan 2021 to Dec 2021 5,000 mmbtu/d US$2.90/mmbtu NYMEX (1) Based on the weighted average price per unit for the period. (2) Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US50/US$58.00/US$62.00 contract, Baytex receives WTI plus US$8.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$58.00/bbl when WTI is between US$50.00/bbl and US$58.00/bbl; Baytex receives the market price when WTI is between US$58.00/bbl and US$62.00/bbl; and Baytex receives US$62.00/bbl when WTI is above US$62.00/bbl. (3) For these contracts, the counterparty has the right, if exercised on September 30, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. (4) For these contracts, the counterparty has the right, if exercised on December 31, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. (5) For these contracts, the counterparty has the right, if exercised on December 23, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. (6) Contracts entered subsequent to December 31, 2019.
Disclosure of financial derivatives marked-to-market	The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives. Years Ended December 31 2019 2018 Realized financial derivatives (gain) loss $ (75,620) $ 73,165 Unrealized financial derivatives loss (gain) 82,817 (116,715) Financial derivatives loss (gain) $ 7,197 $ (43,550)
Disclosure of physical delivery contracts
Disclosure of cash outflows relating to financial liabilities	The timing of cash outflows relating to financial liabilities as at December 31, 2019 is outlined in the table below: Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Trade and other payables $ 207,454 $ 207,454 $ — $ — $ — Bank loan (1)(2) 506,471 — 506,471 — — Long-term notes (2) 1,337,200 — 818,600 518,600 — Interest on long-term notes (3) 217,247 75,625 100,303 41,319 — Lease obligations 14,568 6,216 7,748 604 — $ 2,282,940 $ 289,295 $ 1,433,122 $ 560,523 $ — (1) At December 31, 2019, the bank loan was set to mature on April 2, 2021. On March 3, 2020, Baytex amended the bank loan to extend maturity to April 2, 2024 which will automatically be extended to June 4, 2024 providing the Company has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. (2) Principal amount of instruments. On February 5, 2020, Baytex issued US$500 million principal amount of 8.75% senior unsecured notes due 2027 and issued a redemption notice for the $300 million principal amount of 6.625% senior unsecured notes due 2022 (note 11). The Company expects to complete the redemption of these notes on March 6, 2020. On February 20, 2020 Baytex completed the redemption of the US$400 million principal amount of senior unsecured notes due 2021 (note 11). (3) Excludes interest on bank loan as interest payments on bank loans fluctuate based on amounts outstanding and interest rates.
Trade and other receivables aging	The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2019. Trade and Other Receivables Aging December 31, 2019 December 31, 2018 Current (less than 30 days) $ 169,500 $ 104,099 31-60 days 1,199 3,037 61-90 days 342 1,842 Past due (more than 90 days) 2,721 2,586 $ 173,762 $ 111,564

Supplemental Information (Table

Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2019
Additional information [abstract]
Changes in non-cash working capital items	Years Ended December 31 2019 2018 Trade and other receivables $ (62,198) $ 1,280 Trade and other payables (50,660) 113,572 Non-cash working capital acquired (note 4) — (46,773) $ (112,858) $ 68,079 Changes in non-cash working capital related to: Operating activities $ (52,070) $ 39,448 Investing activities (62,485) 32,435 Foreign currency translation on non-cash working capital 1,697 (3,804) $ (112,858) $ 68,079
Employee compensation costs	The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense. Years Ended December 31 2019 2018 Operating $ 12,918 $ 12,140 General and administrative 33,728 34,963 Total employee compensation costs $ 46,646 $ 47,103

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments And Contingencies [Abstract]
Financial obligations and expected timing	These obligations as of December 31, 2019, and the expected timing of funding of these obligations, are noted in the table below. Total Less than 1-3 years 3-5 years Beyond 5 years Processing agreements 39,352 10,234 10,591 8,848 9,679 Transportation agreements 115,999 11,636 41,263 37,099 26,001 Total $ 155,351 $ 21,870 $ 51,854 $ 45,947 $ 35,680

Related Parties (Tables)

Related Parties (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party [Abstract]
Transactions with key management personnel	Transactions with key management personnel and directors are noted in the table below. Years Ended December 31 2019 2018 Short-term employee benefits $ 6,202 $ 8,703 Share-based compensation 9,188 10,985 Termination payments 2,208 3,025 Total compensation for key management personnel $ 17,598 $ 22,713

Capital Management (Tables)

Capital Management (Tables)	12 Months Ended
	Dec. 31, 2019
Corporate Information And Statement Of IFRS Compliance [Abstract]
Capital management information	It is reconciled to the nearest measure determined in accordance with IFRS, cash flow from operating activities, as set forth below. Years Ended December 31 2019 2018 Cash flow from operating activities $ 834,939 $ 485,322 Change in non-cash working capital 52,070 (39,448) Asset retirement obligations settled 15,417 14,035 Transaction costs — 13,074 Adjusted funds flow $ 902,426 $ 472,983 December 31, 2019 December 31, 2018 Bank loan - principal $ 506,471 $ 522,294 Long-term notes - principal 1,337,200 1,596,323 Trade and other payables 207,454 258,114 Cash (5,572) — Trade and other receivables (173,762) (111,564) Net debt $ 1,871,791 $ 2,265,167

Significant Accounting Polici_4

Significant Accounting Policies - Additional Information (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Disclosure of changes in accounting estimates [line items]
Lease assets	$ 13,619	$ 17,998
Reduction of onerous contracts	0		$ (1,986)
Present value of net lease payments	$ 13,883
Maximum percentage of issuable awards to outstanding common stock	3.80%
Fixed multiplier for share awards	100.00%
In Accordance with IFRS 16
Disclosure of changes in accounting estimates [line items]
Lease assets		18,000
Present value of net lease payments		$ 18,000
Weighted average incremental borrowing rate		3.90%
In Accordance with IFRS 16 | Scenario, Adjustment
Disclosure of changes in accounting estimates [line items]
Reduction of onerous contracts		$ 2,000

Significant Accounting Polici_5

Significant Accounting Policies - Depreciation Methods and Estimated Useful Lives (Details)	12 Months Ended
	Dec. 31, 2019
Motor Vehicles
Disclosure of detailed information about property, plant and equipment [line items]
Depreciation rate	15.00%
Office Equipment
Disclosure of detailed information about property, plant and equipment [line items]
Depreciation rate	20.00%
Computer Hardware
Disclosure of detailed information about property, plant and equipment [line items]
Depreciation rate	30.00%
Furniture and Fixtures
Disclosure of detailed information about property, plant and equipment [line items]
Depreciation rate	10.00%

Business Combination (Details)

Business Combination (Details) - CAD ($) $ / shares in Units, $ in Thousands	Aug. 22, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about business combination [line items]
Common shares issued				$ 1,242,095
Closing price of common shares (in cad per share)	$ 3.93
Consideration
Share-based compensation			$ 15,894	19,534
Fair value of net assets acquired
Transaction costs			$ 0	13,074
Share issuance costs				(551)
Oil and Gas Producer Raging River Exploration, Inc.
Disclosure of detailed information about business combination [line items]
Common shares issued	$ 1,238,995
Market discount rate	7.50%
Consideration
Share-based compensation	$ 3,100
Total consideration	1,242,095
Fair value of net assets acquired
Exploration and evaluation assets	97,858
Oil and gas properties	1,748,368
Working capital deficiency excluding bank debt and financial derivatives	(46,773)
Financial derivatives	(5,548)
Bank debt	(316,800)
Asset retirement obligations	(39,960)
Deferred income tax liability	(195,050)
Net assets acquired	1,242,095
Revenue of acquiree since acquisition date		$ 158,800
Operating income since acquisition date		$ 98,600
Estimated increases in revenues				379,500
Estimated increase in operating income				273,200
Shareholders’ capital
Disclosure of detailed information about business combination [line items]
Common shares issued	$ 1,238,995			1,238,995
Fair value of net assets acquired
Share issuance costs				(551)
Shareholders’ capital | Oil and Gas Producer Raging River Exploration, Inc.
Fair value of net assets acquired
Share issuance costs				(600)
Share issuance costs, net of tax				$ 200

Segmented Financial Informati_3

Segmented Financial Information - Information By Reportable Segment (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue [abstract]
Petroleum and natural gas sales	$ 1,805,919	$ 1,428,870
Royalties	(320,241)	(313,754)
Revenue, net of royalties	1,485,678	1,115,116
Expenses
Operating	397,716	311,592
Transportation	43,942	36,869
Blending and other	68,795	68,832
General and administrative	45,469	45,825
Transaction costs	0	13,074
Exploration and evaluation	11,764	21,729
Depletion and depreciation	731,686	558,684
Impairment	187,822	285,341
Share-based compensation	15,894	19,534
Financing and interest	125,865	119,086
Financial derivatives loss (gain)	7,197	(43,550)
Foreign exchange (gain) loss	(61,787)	108,294
Gain on dispositions	(2,238)	(1,946)
Other income	(7,526)	(1,172)
Total expenses	1,564,599	1,542,192
Net loss before income taxes	(78,921)	(427,076)
Income tax (recovery) expense
Current income tax expense (recovery)	2,093	(35)
Deferred income tax expense (recovery)	(68,555)	(101,732)
Income tax recovery	(66,462)	(101,767)
Net income (loss)	(12,459)	(325,309)
Operating segments | Canada
Revenue [abstract]
Petroleum and natural gas sales	1,077,724	619,215
Royalties	(107,467)	(72,700)
Revenue, net of royalties	970,257	546,515
Expenses
Operating	298,303	221,717
Transportation	43,942	36,869
Blending and other	68,795	68,832
General and administrative	0	0
Transaction costs	0	0
Exploration and evaluation	11,764	10,580
Depletion and depreciation	463,501	294,925
Impairment	187,822	65,000
Share-based compensation	0	0
Financing and interest	0	0
Financial derivatives loss (gain)	0	0
Foreign exchange (gain) loss	0	0
Gain on dispositions	(2,238)	(1,946)
Other income	0	0
Total expenses	1,071,889	695,977
Net loss before income taxes	(101,632)	(149,462)
Income tax (recovery) expense
Current income tax expense (recovery)	101	0
Deferred income tax expense (recovery)	(32,942)	(40,723)
Income tax recovery	(32,841)	(40,723)
Net income (loss)	(68,791)	(108,739)
Total oil and natural gas capital expenditures	376,543	300,299
Operating segments | U.S.
Revenue [abstract]
Petroleum and natural gas sales	728,195	809,655
Royalties	(212,774)	(241,054)
Revenue, net of royalties	515,421	568,601
Expenses
Operating	99,413	89,875
Transportation	0	0
Blending and other	0	0
General and administrative	0	0
Transaction costs	0	0
Exploration and evaluation	0	11,149
Depletion and depreciation	261,766	261,709
Impairment	0	220,341
Share-based compensation	0	0
Financing and interest	0	0
Financial derivatives loss (gain)	0	0
Foreign exchange (gain) loss	0	0
Gain on dispositions	0	0
Other income	0	0
Total expenses	361,179	583,074
Net loss before income taxes	154,242	(14,473)
Income tax (recovery) expense
Current income tax expense (recovery)	1,992	(35)
Deferred income tax expense (recovery)	10,055	(26,049)
Income tax recovery	12,047	(26,084)
Net income (loss)	142,195	11,611
Total oil and natural gas capital expenditures	177,928	193,604
Corporate
Revenue [abstract]
Petroleum and natural gas sales	0	0
Royalties	0	0
Revenue, net of royalties	0	0
Expenses
Operating	0	0
Transportation	0	0
Blending and other	0	0
General and administrative	45,469	45,825
Transaction costs	0	13,074
Exploration and evaluation	0	0
Depletion and depreciation	6,419	2,050
Impairment	0	0
Share-based compensation	15,894	19,534
Financing and interest	125,865	119,086
Financial derivatives loss (gain)	7,197	(43,550)
Foreign exchange (gain) loss	(61,787)	108,294
Gain on dispositions	0	0
Other income	(7,526)	(1,172)
Total expenses	131,531	263,141
Net loss before income taxes	(131,531)	(263,141)
Income tax (recovery) expense
Current income tax expense (recovery)	0	0
Deferred income tax expense (recovery)	(45,668)	(34,960)
Income tax recovery	(45,668)	(34,960)
Net income (loss)	(85,863)	(228,181)
Total oil and natural gas capital expenditures	0	0
Consolidated
Revenue [abstract]
Petroleum and natural gas sales	1,805,919	1,428,870
Royalties	(320,241)	(313,754)
Revenue, net of royalties	1,485,678	1,115,116
Expenses
Operating	397,716	311,592
Transportation	43,942	36,869
Blending and other	68,795	68,832
General and administrative	45,469	45,825
Transaction costs	0	13,074
Exploration and evaluation	11,764	21,729
Depletion and depreciation	731,686	558,684
Impairment	187,822	285,341
Share-based compensation	15,894	19,534
Financing and interest	125,865	119,086
Financial derivatives loss (gain)	7,197	(43,550)
Foreign exchange (gain) loss	(61,787)	108,294
Gain on dispositions	(2,238)	(1,946)
Other income	(7,526)	(1,172)
Total expenses	1,564,599	1,542,192
Net loss before income taxes	(78,921)	(427,076)
Income tax (recovery) expense
Current income tax expense (recovery)	2,093	(35)
Deferred income tax expense (recovery)	(68,555)	(101,732)
Income tax recovery	(66,462)	(101,767)
Net income (loss)	(12,459)	(325,309)
Total oil and natural gas capital expenditures	$ 554,471	$ 493,903

Segmented Financial Informati_4

Segmented Financial Information - Assets By Segment (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Disclosure of operating segments [line items]
Assets	$ 5,914,083	$ 6,377,198
Operating segments | Canada
Disclosure of operating segments [line items]
Assets	3,484,123	3,739,029
Operating segments | U.S.
Disclosure of operating segments [line items]
Assets	2,403,310	2,628,941
Operating segments | Corporate
Disclosure of operating segments [line items]
Assets	$ 26,650	$ 9,228

Exploration and Evaluation As_3

Exploration and Evaluation Assets (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of changes in intangible assets other than goodwill [abstract]
Exploration and evaluation assets, beginning of year	$ 358,935
Exploration and evaluation expense	(11,764)	$ (21,729)
Exploration and evaluation assets, end of year	320,210	358,935
Exploration and evaluation assets
Reconciliation of changes in intangible assets other than goodwill [abstract]
Exploration and evaluation assets, beginning of year	358,935	272,974
Capital expenditures	2,948	10,567
Corporate acquisition	0	97,858
Property acquisitions	1,523	514
Divestitures	(443)	(1,021)
Impairment	(7,822)	0
Property swaps	417	0
Exploration and evaluation expense	(11,764)	(21,729)
Transfers to oil and gas properties	(16,204)	(13,866)
Foreign currency translation	(7,380)	13,638
Exploration and evaluation assets, end of year	$ 320,210	$ 358,935

Oil and Gas Properties - Schedu

Oil and Gas Properties - Schedule of PPE Activity, Oil and Gas (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of changes in property, plant and equipment [abstract]
Impairment	$ (187,822)	$ (285,341)
Oil and gas assets
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	5,817,889	3,958,309
Capital expenditures	549,343	485,154
Corporate acquisition		1,748,368
Property acquisitions	2,636	202
Transfers from exploration and evaluation assets	16,204	13,866
Change in asset retirement obligations	23,894	238,662
Divestitures	(379)	(15)
Property swaps	(1,773)
Impairment	(180,000)	(285,341)
Foreign currency translation	(118,204)	215,318
Depletion	(725,267)	(556,634)
Balance, end of year	5,387,889	5,817,889
Oil and gas assets | Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	10,744,533	7,932,327
Capital expenditures	549,343	485,154
Corporate acquisition		1,748,368
Property acquisitions	2,636	202
Transfers from exploration and evaluation assets	16,204	13,866
Change in asset retirement obligations	23,894	238,662
Divestitures	(2,069)	(15)
Property swaps	(1,773)
Impairment	0	0
Foreign currency translation	(208,017)	325,969
Depletion	0	0
Balance, end of year	11,128,297	10,744,533
Oil and gas assets | Accumulated depletion
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	(4,926,644)	(3,974,018)
Capital expenditures	0	0
Corporate acquisition		0
Property acquisitions	0	0
Transfers from exploration and evaluation assets	0	0
Change in asset retirement obligations	0	0
Divestitures	1,690	0
Property swaps	0
Impairment	(180,000)	(285,341)
Foreign currency translation	89,813	(110,651)
Depletion	(725,267)	(556,634)
Balance, end of year	$ (5,740,408)	$ (4,926,644)

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of detailed information about property, plant and equipment [line items]
Adjusted inflation for prices and costs subsequent to 2023	0.020
Conventional CGU | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections		8.00%
Conventional CGU | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections		20.00%
Eagle Ford CGU | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections		8.00%
Eagle Ford CGU | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections		20.00%
Oil and gas assets
Disclosure of detailed information about property, plant and equipment [line items]
Impairment	$ (180)	$ (285.3)
Discount rate applied to cash flow projections	11.00%
Oil and gas assets | Conventional CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment		(65)
Oil and gas assets | Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment		$ (220.3)

Oil and Gas Properties - Recove

Oil and Gas Properties - Recoverable Amount Of Peace River CGU (Details) - Peace River CGU	12 Months Ended
	Dec. 31, 2019canadianDollarPerUsDollarusdPerBblcadPerBblcadPerGigajoules
2020
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.32
2021
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.30
2022
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
2023
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
2024
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
2025
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
2026
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
2027
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
2028
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
2029
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share) | canadianDollarPerUsDollar	1.27
WTI | Oil reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	61
WTI | Oil reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	63.75
WTI | Oil reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	66.18
WTI | Oil reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	67.91
WTI | Oil reserves | 2024
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	69.48
WTI | Oil reserves | 2025
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	71.07
WTI | Oil reserves | 2026
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	72.68
WTI | Oil reserves | 2027
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	74.24
WTI | Oil reserves | 2028
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	75.73
WTI | Oil reserves | 2029
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	77.24
WCS | Oil reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	57.57
WCS | Oil reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	62.35
WCS | Oil reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	64.33
WCS | Oil reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	66.23
WCS | Oil reserves | 2024
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	67.97
WCS | Oil reserves | 2025
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	69.72
WCS | Oil reserves | 2026
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	71.49
WCS | Oil reserves | 2027
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	73.20
WCS | Oil reserves | 2028
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	74.80
WCS | Oil reserves | 2029
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	76.43
AECO | Natural gas reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	2.04
AECO | Natural gas reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	2.32
AECO | Natural gas reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	2.62
AECO | Natural gas reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	2.71
AECO | Natural gas reserves | 2024
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	2.81
AECO | Natural gas reserves | 2025
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	2.89
AECO | Natural gas reserves | 2026
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	2.96
AECO | Natural gas reserves | 2027
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	3.03
AECO | Natural gas reserves | 2028
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	3.09
AECO | Natural gas reserves | 2029
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerGigajoules	3.16

Oil and Gas Properties - Sensit

Oil and Gas Properties - Sensitivity of the Estimated Recoverable Amount of Possible Changes (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)cadPerBbl
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate	1.00%
Oil price | cadPerBbl	2.50
Peace River CGU
Disclosure of detailed information about property, plant and equipment [line items]
Change in discount rate, impact of 1% decrease	$ 24,000
Change in oil price, impact of increase in oil price of $2.50/bbl	$ 88,000

Other Plant and Equipment (Deta

Other Plant and Equipment (Details) - Other property, plant and equipment - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	$ 9,228	$ 9,474
Capital expenditures	552	1,804
Depreciation	(2,182)	(2,050)
Balance, end of year	7,598	9,228
Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	64,452	62,648
Capital expenditures	552	1,804
Depreciation	0	0
Balance, end of year	65,004	64,452
Accumulated depreciation
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	(55,224)	(53,174)
Capital expenditures	0	0
Depreciation	(2,182)	(2,050)
Balance, end of year	$ (57,406)	$ (55,224)

Leases - Right-Of-Use Assets (D

Leases - Right-Of-Use Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)
Leases [Roll Forward]
Additions	$ 1,827
Modifications	17
Depreciation	(6,223)
Right-of-use assets, ending balance	13,619
Office Leases
Leases [Roll Forward]
Additions	0
Modifications	(6)
Depreciation	(4,904)
Right-of-use assets, ending balance	9,865
Field Equipment
Leases [Roll Forward]
Additions	1,668
Modifications	4
Depreciation	(837)
Right-of-use assets, ending balance	3,089
Vehicles And Other
Leases [Roll Forward]
Additions	159
Modifications	19
Depreciation	(482)
Right-of-use assets, ending balance	$ 665

Leases - Future Commitments (De

Leases - Future Commitments (Details) $ in Thousands	Dec. 31, 2019CAD ($)
Disclosure of maturity analysis of operating lease payments [line items]
Lease obligations	$ 14,568
Amounts representing interest over the term of the lease	(685)
Present value of net lease payments	13,883
Less current portion of lease obligations	5,798
Lease obligations	8,085
Less than 1 year
Disclosure of maturity analysis of operating lease payments [line items]
Lease obligations	6,216
1-3 years
Disclosure of maturity analysis of operating lease payments [line items]
Lease obligations	7,748
3-5 years
Disclosure of maturity analysis of operating lease payments [line items]
Lease obligations	604
After 5 years
Disclosure of maturity analysis of operating lease payments [line items]
Lease obligations	$ 0

Leases - Additional Information

Leases - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)
Leases [Abstract]
Interest on lease obligations	$ 610
Payments on lease obligations	$ (5,956)

Bank Loan - Bank Loan (Details)

Bank Loan - Bank Loan (Details) $ in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Disclosure of detailed information about borrowings [line items]
Secured bank loans received			$ 505,412		$ 520,700
Bank loan - U.S. dollar denominated
Disclosure of detailed information about borrowings [line items]
Secured bank loans received			206,144		122,388
Bank loan - Canadian dollar denominated
Disclosure of detailed information about borrowings [line items]
Secured bank loans received			300,327		399,906
Principal
Disclosure of detailed information about borrowings [line items]
Secured bank loans received			506,471		522,294
Loan repayments	$ 198,100
Changes in reported amount of U.S. denominated debt	61,000
Principal | Bank loan - U.S. dollar denominated
Disclosure of detailed information about borrowings [line items]
Secured bank loans received		$ 159		$ 89.7
Changes in reported amount of U.S. denominated debt	8,700
Principal | Bank loan - Canadian dollar denominated
Disclosure of detailed information about borrowings [line items]
Loan repayments	$ 7,100
Unamortized debt issuance costs
Disclosure of detailed information about borrowings [line items]
Secured bank loans received			$ 1,059		$ 1,594

Bank Loan - Additional Informat

Bank Loan - Additional Information (Details)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit		$ 15,200,000	$ 14,600,000
Revolving Facilities
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	$ 575,000,000
Term Loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity		$ 300,000,000
Operating loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	50,000,000
Syndicated loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	325,000,000
Subsidiary syndicated loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	$ 200,000,000

Bank Loan - Financial Covenants

Bank Loan - Financial Covenants (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt, as defined	$ 521,700
Bank loan - principal	505,412	$ 520,700
Outstanding letters of credit	15,200	14,600
Bank EBITDA, as defined	1,011,900
Financing and interest expenses, as defined	107,400
Cost
Disclosure of detailed information about borrowings [line items]
Bank loan - principal	$ 506,471	$ 522,294
Position as at December 31, 2019
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt to Bank EBITDA (Maximum Ratio)	0.52
Interest Coverage (Minimum Ratio)	9.42
Covenant
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt to Bank EBITDA (Maximum Ratio)	3.50
Interest Coverage (Minimum Ratio)	2

Long-Term Notes (Details)

Long-Term Notes (Details)	Feb. 20, 2020CAD ($)	Feb. 05, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Feb. 20, 2020USD ($)	Feb. 05, 2020USD ($)	Feb. 05, 2020CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Sep. 13, 2019USD ($)
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal				$ 1,583,240,000					$ 1,328,175,000
Repayments of bonds, notes and debentures				0
Covenant compliance, minimum fixed charge ratio			2.50
Fixed charge ratio			8.04
Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal				1,596,323,000					1,337,200,000
Loan repayments			$ 198,100,000
Changes in reported amount of U.S. denominated debt			61,000,000
Unamortized debt issuance costs
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal				13,083,000					9,025,000
6.75% notes due February 17, 2021
Disclosure of detailed information about borrowings [line items]
Notional amount								$ 150,000,000		$ 150,000
Repayments of bonds, notes and debentures			$ 198,128,000
6.75% notes due February 17, 2021 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate										6.75%
6.75% notes due February 17, 2021 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal				204,683,000					0
8.75% Notes Due April 1, 2027 | Debt Issuance Transaction
Disclosure of detailed information about borrowings [line items]
Notional amount						$ 500,000,000
Transaction costs		$ 12,400,000
Proceeds from non-current borrowings	$ 652,300,000	$ 652,300,000
8.75% Notes Due April 1, 2027 | Fixed interest rate | Debt Issuance Transaction
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate						8.75%	8.75%
5.125% notes due June 1, 2021
Disclosure of detailed information about borrowings [line items]
Notional amount								400,000,000
5.125% notes due June 1, 2021 | Debt Issuance Transaction
Disclosure of detailed information about borrowings [line items]
Notional amount					$ 400,000,000
5.125% notes due June 1, 2021 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate					5.125%
5.125% notes due June 1, 2021 | Fixed interest rate | Debt Issuance Transaction
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate					5.125%
5.125% notes due June 1, 2021 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal				545,820,000					518,600,000
6.625% notes due July 19, 2022
Disclosure of detailed information about borrowings [line items]
Notional amount									300,000,000
6.625% notes due July 19, 2022 | Debt Issuance Transaction
Disclosure of detailed information about borrowings [line items]
Notional amount							$ 300,000,000
6.625% notes due July 19, 2022 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate					6.625%
6.625% notes due July 19, 2022 | Fixed interest rate | Debt Issuance Transaction
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate						6.625%	6.625%
Early redemption of notes		101.104%
6.625% notes due July 19, 2022 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal				300,000,000					300,000,000
5.625% notes due June 1, 2024
Disclosure of detailed information about borrowings [line items]
Notional amount								$ 400,000,000
5.625% notes due June 1, 2024 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate					5.625%
5.625% notes due June 1, 2024 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal				$ 545,820,000					$ 518,600,000

Asset Retirement Obligations -

Asset Retirement Obligations - Changes In Asset Retirement Obligations (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of changes in other provisions [Abstract]
Accretion	$ 13,713	$ 10,914
Less current portion of asset retirement obligations	11,579	0
Non-current portion of asset retirement obligations	656,395	646,898
Less current portion of asset retirement obligations	11,579	0
Asset retirement obligation
Reconciliation of changes in other provisions [Abstract]
Balance, beginning of the year	646,898	368,995
Liabilities incurred	21,748	12,537
Liabilities settled	(15,417)	(14,035)
Liabilities acquired from property acquisitions	1,648	132
Liabilities divested	(1,331)	(580)
Property swaps	792	0
Accretion	13,713	10,914
Change in estimate	19,632	33,453
Changes in discount rates and inflation rates	(17,486)	192,672
Foreign currency translation	(2,223)	2,850
Balance, end of the year	667,974	646,898
Asset retirement obligation | Aggregated individually immaterial business combinations
Reconciliation of changes in other provisions [Abstract]
Liabilities assumed from corporate acquisition	$ 0	$ 39,960

Asset Retirement Obligations _2

Asset Retirement Obligations - Additional Information (Details) - Asset retirement obligation - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of other provisions [line items]
Estimated cash flows, undiscounted amount	$ 714,800	$ 673,100
Estimated inflation rate	1.40%	2.00%
Estimated risk free rate	1.80%	2.20%
Other provisions	$ 667,974	$ 646,898	$ 368,995

Shareholders' Capital (Details)

Shareholders' Capital (Details) $ in Thousands	Aug. 22, 2018CAD ($)shares	Dec. 31, 2019CAD ($)sharesvote	Dec. 31, 2018CAD ($)shares
Number of Common Shares (000s)
Vested and converted to common shares (in shares) | shares		4,245,000	3,343,000
Changes in equity [abstract]
Beginning balance		$ 3,055,424	$ 1,914,885
Share-based compensation		15,894	19,534
Common shares issued			1,242,095
Transfer from contributed surplus on vesting and conversion of share awards, amount		0	0
Ending balance		$ 2,947,209	$ 3,055,424
Shareholders’ capital
Issued on corporate acquisition (in shares) | shares	315,266,000
Number of Common Shares (000s)
Beginning balance (in shares) | shares		554,060,000	235,451,000
Vested and converted to common shares (in shares) | shares		4,245,000	3,343,000
Number of shares issued (in shares) | shares	315,266,000
Ending balance (in shares) | shares		558,305,000	554,060,000
Changes in equity [abstract]
Beginning balance		$ 5,701,516	$ 4,443,576
Share-based compensation			19,496
Common shares issued	$ 1,238,995		1,238,995
Issuance costs, net of tax, amount	$ (551)
Transfer from contributed surplus on vesting and conversion of share awards, amount		17,319	19,496
Ending balance		$ 5,718,835	$ 5,701,516
Preference shares
Preferred shares without nominal or par value (in shares) | shares		10,000,000
Issued on corporate acquisition (in shares) | shares		0
Number of Common Shares (000s)
Number of shares issued (in shares) | shares		0
Ordinary shares
Voting rights, votes per share | vote		1

Share-Based Compensation Plan -

Share-Based Compensation Plan - Additional Information (Details) $ / shares in Units, shares in Thousands, share in Thousands	12 Months Ended
	Dec. 31, 2019CAD ($)shares	Dec. 31, 2018CAD ($)share$ / shares	Dec. 31, 2019share	Dec. 31, 2019CAD ($)	Dec. 31, 2019$ / shares	Dec. 31, 2017shares$ / shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Compensation expense related to share awards	$ (15,894,000)	$ (19,534,000)
Options Outstanding, number outstanding at December 31, 2019 (in shares)	2,475	4,865	2,475			0
Options Outstanding, weighted average exercise price (in cad per share) | $ / shares		$ 6.70			$ 6.83	$ 0
Share-based Compensation Award, Tranche One
Disclosure of terms and conditions of share-based payment arrangement [line items]
Date of options granted, year one	33.30%
Share-based Compensation Award, Tranche Two
Disclosure of terms and conditions of share-based payment arrangement [line items]
Date of options granted, year two	33.30%
Share-based Compensation Award, Tranche Three
Disclosure of terms and conditions of share-based payment arrangement [line items]
Date of options granted, year three	33.30%
Restricted awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average fair value of share awards (in cad per share)		$ 4.04		$ 2.63

Share-Based Compensation Plan_2

Share-Based Compensation Plan - Shares Outstanding (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Total number of share awards
Beginning balance (in shares)	6,516	4,281
Granted (in shares)	6,429	5,384
Assumed on corporate acquisition (in shares)		559
Vested and converted to common shares (in shares)	(4,245)	(3,343)
Forfeited (in shares)	(1,764)	(365)
Ending balance (in shares)	6,936	6,516
Payout multiplier	100.00%
Restricted awards
Total number of share awards
Beginning balance (in shares)	3,243	2,028
Granted (in shares)	3,184	2,793
Assumed on corporate acquisition (in shares)		302
Vested and converted to common shares (in shares)	(2,081)	(1,682)
Forfeited (in shares)	(545)	(198)
Ending balance (in shares)	3,801	3,243
Performance awards
Total number of share awards
Beginning balance (in shares)	3,273	2,253
Granted (in shares)	3,245	2,591
Assumed on corporate acquisition (in shares)		257
Vested and converted to common shares (in shares)	(2,164)	(1,661)
Forfeited (in shares)	(1,219)	(167)
Ending balance (in shares)	3,135	3,273

Share-Based Compensation Plan_3

Share-Based Compensation Plan - Share Options (Details) shares in Thousands, share in Thousands	12 Months Ended
	Dec. 31, 2019shares	Dec. 31, 2019share	Dec. 31, 2019$ / shares	Dec. 31, 2018sharesshare$ / shares
Number of options
Number of share options outstanding, beginning balance (in shares)		4,865		0
Assumed on corporate acquisition (in shares) | shares				9,187
Forfeited/Expired (in shares)	(2,390)			(4,322)
Number of share options outstanding, ending balance (in shares)	2,475	2,475		4,865
Weighted average exercise price
Weighted average exercise price of share options outstanding in share-based payment arrangement at beginning of period (in cad per share)			$ 6.70	$ 0
Assumed on corporate acquisition (in cad per share)				6.63
Forfeited/Expired (in cad per share)			6.56	6.57
Weighted average exercise price of share options outstanding in share-based payment arrangement at end of period (in cad per share)			$ 6.83	$ 6.70

Share-Based Compensation Plan_4

Share-Based Compensation Plan - Options Outstanding and Exercisable (Details) shares in Thousands, share in Thousands	12 Months Ended
	Dec. 31, 2019shares$ / shares	Dec. 31, 2019share	Dec. 31, 2019$ / shares	Dec. 31, 2018share$ / shares	Dec. 31, 2017shares$ / shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Options Outstanding, number outstanding at December 31, 2019 (in shares)	2,475	2,475		4,865	0
Options Outstanding, weighted average remaining life	6 months 29 days
Options Outstanding, weighted average exercise price (in cad per share)			$ 6.83	$ 6.70	$ 0
Options exercisable, number exercisable at December 31, 2019 (in shares) | share		2,069
Options Exercisable, weighted average exercise price (in cad per share)	$ 6.94
$5.00 - $7.00
Disclosure of terms and conditions of share-based payment arrangement [line items]
Options Outstanding, number outstanding at December 31, 2019 (in shares) | share		1,654
Options Outstanding, weighted average remaining life	9 months 14 days
Options Outstanding, weighted average exercise price (in cad per share)			6.39
Options exercisable, number exercisable at December 31, 2019 (in shares) | share		1,248
Options Exercisable, weighted average exercise price (in cad per share)	$ 6.42
$7.01 - $9.00
Disclosure of terms and conditions of share-based payment arrangement [line items]
Options Outstanding, number outstanding at December 31, 2019 (in shares) | share		821
Options Outstanding, weighted average remaining life	1 month 24 days
Options Outstanding, weighted average exercise price (in cad per share)			7.73
Options exercisable, number exercisable at December 31, 2019 (in shares) | share		821
Options Exercisable, weighted average exercise price (in cad per share)	$ 7.73
Minimum | $5.00 - $7.00
Disclosure of terms and conditions of share-based payment arrangement [line items]
Exercise price of outstanding share options			5
Minimum | $7.01 - $9.00
Disclosure of terms and conditions of share-based payment arrangement [line items]
Exercise price of outstanding share options			7.01
Maximum | $5.00 - $7.00
Disclosure of terms and conditions of share-based payment arrangement [line items]
Exercise price of outstanding share options			7
Maximum | $7.01 - $9.00
Disclosure of terms and conditions of share-based payment arrangement [line items]
Exercise price of outstanding share options			$ 9

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Net loss
Net loss - basic	$ (12,459)	$ (325,309)
Net loss - diluted	$ (12,459)	$ (325,309)
Weighted average ordinary shares and adjusted weighted average ordinary shares [abstract]
Weighted average common shares - basic (in shares)	557,048	351,542
Dilutive effect of share awards (in shares)	0	0
Dilutive effect of share options (in shares)	0	0
Weighted average common shares - diluted (in shares)	557,048	351,542
Net loss per share
Net income (loss) per share - basic (in cad per share)	$ (0.02)	$ (0.93)
Net income (loss) per share - diluted (in cad per share)	$ (0.02)	$ (0.93)
Antidilutive share awards (in shares)	6,900	6,500
Antidilutive share options (in shares)	2,500	4,900

Petroleum and Natural Gas Sal_3

Petroleum and Natural Gas Sales (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of operating segments [line items]
Petroleum and natural gas sales	$ 1,805,919	$ 1,428,870
Trade receivable, accrued petroleum and natural gas sales
Disclosure of operating segments [line items]
Included in accounts receivable	138,000	77,400
Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	1,077,724	619,215
U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	728,195	809,655
Light oil and condensate
Disclosure of operating segments [line items]
Petroleum and natural gas sales	1,138,650	806,390
Light oil and condensate | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	538,487	169,335
Light oil and condensate | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	600,163	637,055
Heavy oil
Disclosure of operating segments [line items]
Petroleum and natural gas sales	500,187	411,794
Heavy oil | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	500,187	411,794
Heavy oil | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	0	0
NGL
Disclosure of operating segments [line items]
Petroleum and natural gas sales	69,077	111,539
NGL | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	8,430	14,531
NGL | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	60,647	97,008
Natural gas sales
Disclosure of operating segments [line items]
Petroleum and natural gas sales	98,005	99,147
Natural gas sales | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	30,620	23,555
Natural gas sales | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	$ 67,385	$ 75,592

Income Taxes - Provision For In

Income Taxes - Provision For Income Taxes (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net loss before income taxes	$ (78,921)	$ (427,076)
Expected income taxes at the statutory rate	$ (21,088)	$ (115,311)
Tax rate	26.72%	27.00%
Increase (Decrease) From Tax Effects [Abstract]
Share-based compensation	$ 4,247	$ 5,185
Non-taxable portion of foreign exchange (gain) loss	(8,155)	14,467
Effect of change in income tax rates	(6,098)	0
Effect of rate adjustments for foreign jurisdictions	(27,785)	(22,119)
Effect of change in deferred tax benefit not recognized	(7,563)	14,467
Adjustments and assessments	(20)	1,544
Income tax recovery	(66,462)	(101,767)
Allowable capital losses	$ 109,000	$ 139,000

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jun. 30, 2016
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Effect of change in income tax rates	$ (6,098)	$ 0
Provincial tax rate	26.72%	27.00%
Accumulated non-capital losses			$ 591,000

Income Taxes - Continuity of Ne

Income Taxes - Continuity of Net Deferred Income Tax Liability (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in deferred tax liability (asset) [abstract]
Beginning balance	$ (310,836)	$ (204,698)
Recognized in Net Income	68,555	101,732
Share Issuance Costs		209
Increase (decrease) through business combinations, deferred tax liability (asset)		(195,050)
Foreign Currency Translation Adjustment	6,973	(13,029)
Ending balance	(235,308)	(310,836)
Non-capital loss carry-forwards	1,714,600	1,733,800
Petroleum and natural gas properties
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(954,506)	(696,427)
Recognized in Net Income	48,995	(11,639)
Increase (decrease) through business combinations, deferred tax liability (asset)		(207,337)
Foreign Currency Translation Adjustment	23,517	(39,103)
Ending balance	(881,994)	(954,506)
Financial derivatives
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(21,486)	0
Recognized in Net Income	21,486	(22,984)
Increase (decrease) through business combinations, deferred tax liability (asset)		1,498
Ending balance	0	(21,486)
Deferred income
Changes in deferred tax liability (asset) [abstract]
Beginning balance	0	(17,827)
Recognized in Net Income		17,827
Ending balance		0
Other
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(3,045)	(5,956)
Recognized in Net Income	5,192	(2,538)
Share Issuance Costs		209
Foreign Currency Translation Adjustment	(4,550)	5,240
Ending balance	(2,403)	(3,045)
Asset retirement obligations
Changes in deferred tax liability (asset) [abstract]
Beginning balance	172,359	97,977
Recognized in Net Income	(7,364)	62,984
Increase (decrease) through business combinations, deferred tax liability (asset)		10,789
Foreign Currency Translation Adjustment	(472)	609
Ending balance	164,523	172,359
Financial derivatives
Changes in deferred tax liability (asset) [abstract]
Beginning balance		8,528
Recognized in Net Income	802	(8,528)
Ending balance	802
Non-capital losses
Changes in deferred tax liability (asset) [abstract]
Beginning balance	399,699	330,749
Recognized in Net Income	(1,460)	48,725
Foreign Currency Translation Adjustment	(11,522)	20,225
Ending balance	386,717	399,699
Finance costs
Changes in deferred tax liability (asset) [abstract]
Beginning balance	96,143	78,258
Recognized in Net Income	904	17,885
Ending balance	$ 97,047	$ 96,143

Financing and Interest (Details

Financing and Interest (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Analysis of income and expense [abstract]
Interest on bank loan	$ 20,376	$ 15,637
Interest on long-term notes	86,431	88,681
Interest on lease obligations	610
Non-cash financing	4,735	3,854
Accretion on asset retirement obligations	13,713	10,914
Financing and interest	$ 125,865	$ 119,086

Foreign Exchange (Details)

Foreign Exchange (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Effects Of Changes In Foreign Exchange Rates [Abstract]
Unrealized foreign exchange (gain) loss	$ (62,753)	$ 106,143
Realized foreign exchange loss	966	2,151
Foreign exchange (gain) loss	$ (61,787)	$ 108,294

Financial Instruments and Ris_3

Financial Instruments and Risk Management - Carrying Value and Fair Value of Financial Instruments (Details) - CAD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	$ (8,668)	$ 0
Liabilities, at fair value	(8,668)	0
FVTPL | Financial Derivatives | Level 2
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(8,668)	0
Liabilities, at fair value	(8,668)	0
Financial liabilities at amortized cost
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(2,054,924)	(2,362,054)
Liabilities, at fair value	(2,018,625)	(2,272,771)
Financial liabilities at amortized cost | Trade and other payables | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(207,454)	(258,114)
Liabilities, at fair value	(207,454)	(258,114)
Financial liabilities at amortized cost | Bank loan | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(505,412)	(520,700)
Liabilities, at fair value	(506,471)	(522,294)
Financial liabilities at amortized cost | Long-term notes | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(1,328,175)	(1,583,240)
Liabilities, at fair value	(1,290,817)	(1,492,363)
Financial liabilities at amortized cost | Lease obligations | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(13,883)
Liabilities, at fair value	(13,883)
FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	5,433	79,582
Financial assets, at fair value	5,433	79,582
Financial assets	5,433	79,582
Financial assets, at fair value	5,433	79,582
FVTPL | Level 2
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	5,433	79,582
Financial assets, at fair value	5,433	79,582
Financial assets	5,433	79,582
Financial assets, at fair value	5,433	79,582
Financial assets at amortized cost
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	179,334	111,564
Financial assets, at fair value	179,334	111,564
Financial assets	179,334	111,564
Financial assets, at fair value	179,334	111,564
Financial assets at amortized cost | Cash | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	5,572	0
Financial assets, at fair value	5,572	0
Financial assets	5,572	0
Financial assets, at fair value	5,572	0
Financial assets at amortized cost | Trade and Other Receivables | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	173,762	111,564
Financial assets, at fair value	173,762	111,564
Financial assets	173,762	111,564
Financial assets, at fair value	$ 173,762	$ 111,564

Financial Instruments and Ris_4

Financial Instruments and Risk Management - Foreign Currency Risk, Interest Rate Risk, Interest Rate Swaps and Commodity Price Risk (Details) $ in Thousands	Mar. 03, 2020CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
Interest rate swap contract
Disclosure of nature and extent of risks arising from financial instruments [line items]
Interest rate swap fair value			$ 0		$ 300,000
Interest Rate Swap Transaction
Disclosure of nature and extent of risks arising from financial instruments [line items]
Derivative notional amount	$ 100,000,000
Derivative price per unit (in cad per share)	$ 0.0202
Currency risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Increase/decrease risk in foreign exchange rate			0.01
Effect on net income			8,300,000
Currency risk | U.S. dollar denominated, liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
U.S. dollar denominated		$ 841,961		$ 963,351
Currency risk | U.S. dollar denominated, assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
U.S. dollar denominated		$ 8,733		$ 80,857
Interest rate risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Effect on net income			$ 4,100,000
Impact of base point change on interest rates		100.00%	100.00%
Commodity price risk | Oil Price
Disclosure of nature and extent of risks arising from financial instruments [line items]
Potential impact of crude oil price changes		100.00%	100.00%
Potential impact of natural gas price changes			$ 17,500,000
Commodity price risk | Natural Gas Price
Disclosure of nature and extent of risks arising from financial instruments [line items]
Potential impact of crude oil price changes		25.00%	25.00%
Potential impact of natural gas price changes			$ 1,200,000

Financial Instruments and Ris_5

Financial Instruments and Risk Management - Financial Derivative Contracts (Details)	Dec. 31, 2019usdPerBblbblPerDaymmbtuPerDay
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	8
Derivative price/unit	8
Oil Basis Swap Jan 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,500
Oil Basis Swap Apr 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	4,000
Oil Basis Swap Jan 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,000
Oil Basis Swap Apr 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	3,000
Oil Fixed Cell Apr 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	6,000
Oil Fixed Sell Jan 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,000
Oil Three Way Option Jan 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	3,000
Oil Three Way Option Jan 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	3,000
Oil Three Way Option Jan 2020 to Dec 2020 - 3
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	4,500
Oil Three Way Option Jan 2020 to Dec 2020 - 4
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	3,000
Oil Three Way Option Jan 2020 to Dec 2020 - 5
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,000
Oil Three Way Option Jan 2020 to Dec 2020 - 6
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,000
Oil Three Way Option Jan 2020 to Dec 2020 - 7
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,500
Oil Three Way Option Jan 2020 to Dec 2020 - 8
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,500
Oil Three Way Option Jan 2020 to Dec 2020 - 9
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,000
Oil Three Way Option Jan 2020 to Dec 2020 - 10
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,000
Oil Three Way Option Jan 2020 to Dec 2020 - 11
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,000
Oil Three Way Option Jan 2020 to Dec 2020 - 12
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,000
Oil Three Way Option Jan 2020 to Dec 2020 - 13
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,000
Oil Swaption Jan 2021 to Dec 2021 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	3,000
Oil Swaption Jan 2021 to Dec 2021 - 2
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	3,000
Oil Swaption Jan 2021 to Dec 2021 - 3
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	3,000
Natural Gas Three Way Option Jan 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	5,000
Natural Gas Swaption Jan 2021 to Dec 2021
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	5,000
Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Derivative price/unit	50
Price One | Oil Basis Swap Jan 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	16.10
Derivative price/unit	16.10
Price One | Oil Basis Swap Apr 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	16.38
Derivative price/unit	16.38
Price One | Oil Basis Swap Jan 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	6.50
Derivative price/unit	6.50
Price One | Oil Basis Swap Apr 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	5.92
Derivative price/unit	5.92
Price One | Oil Fixed Cell Apr 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	56.60
Derivative price/unit	56.60
Price One | Oil Fixed Sell Jan 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	58
Derivative price/unit	58
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Derivative price/unit	50
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Derivative price/unit	50
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 3
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Derivative price/unit	50
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 4
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Derivative price/unit	50
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 5
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 6
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 7
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 8
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 9
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 10
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 11
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 12
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Three Way Option Jan 2020 to Dec 2020 - 13
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	51
Derivative price/unit	51
Price One | Oil Swaption Jan 2021 to Dec 2021 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	64.50
Derivative price/unit	64.50
Price One | Oil Swaption Jan 2021 to Dec 2021 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	70
Derivative price/unit	70
Price One | Oil Swaption Jan 2021 to Dec 2021 - 3
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60.75
Derivative price/unit	60.75
Price One | Natural Gas Three Way Option Jan 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.25
Derivative price/unit	2.25
Price One | Natural Gas Swaption Jan 2021 to Dec 2021
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.90
Derivative price/unit	2.90
Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	58
Derivative price/unit	58
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	56
Derivative price/unit	56
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	57
Derivative price/unit	57
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 3
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	57
Derivative price/unit	57
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 4
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	58
Derivative price/unit	58
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 5
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	58
Derivative price/unit	58
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 6
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	58
Derivative price/unit	58
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 7
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	59
Derivative price/unit	59
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 8
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	59
Derivative price/unit	59
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 9
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	59.50
Derivative price/unit	59.50
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 10
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Derivative price/unit	60
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 11
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Derivative price/unit	60
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 12
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Derivative price/unit	60
Price Two | Oil Three Way Option Jan 2020 to Dec 2020 - 13
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Derivative price/unit	60
Price Two | Natural Gas Three Way Option Jan 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.60
Derivative price/unit	2.60
Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	62
Derivative price/unit	62
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	61.35
Derivative price/unit	61.35
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Derivative price/unit	60
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 3
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	62
Derivative price/unit	62
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 4
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	62
Derivative price/unit	62
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 5
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60.50
Derivative price/unit	60.50
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 6
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60.83
Derivative price/unit	60.83
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 7
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	65.60
Derivative price/unit	65.60
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 8
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66
Derivative price/unit	66
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 9
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66.15
Derivative price/unit	66.15
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 10
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	65.60
Derivative price/unit	65.60
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 11
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66
Derivative price/unit	66
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 12
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66.05
Derivative price/unit	66.05
Price Three | Oil Three Way Option Jan 2020 to Dec 2020 - 13
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66.70
Derivative price/unit	66.70
Price Three | Natural Gas Three Way Option Jan 2020 to Dec 2020
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.85
Derivative price/unit	2.85

Financial Instruments and Ris_6

Financial Instruments and Risk Management - Financial Derivatives Marked-To-Market (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Financial Instruments [Abstract]
Realized financial derivatives (gain) loss	$ (75,620)	$ 73,165
Unrealized financial derivatives loss (gain)	82,817	(116,715)
Financial derivatives loss (gain)	$ 7,197	$ (43,550)

Financial Instruments and Ris_7

Financial Instruments and Risk Management - Liquidity Risk (Details)	Feb. 20, 2020USD ($)	Feb. 20, 2020CAD ($)	Feb. 05, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables					$ 207,454,000	$ 258,114,000
Bank loan					505,412,000	520,700,000
Long-term notes					1,328,175,000	1,583,240,000
Lease obligations					14,568,000
6.625% notes due July 19, 2022
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount					300,000,000
6.625% notes due July 19, 2022 | Fixed interest rate
Disclosure of nature and extent of risks arising from financial instruments [line items]
Borrowings, interest rate	6.625%	6.625%
5.125% notes due June 1, 2021
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount				$ 400,000,000
5.125% notes due June 1, 2021 | Fixed interest rate
Disclosure of nature and extent of risks arising from financial instruments [line items]
Borrowings, interest rate	5.125%	5.125%
Major ordinary share transactions | 8.75% Notes Due April 1, 2027
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount			$ 500,000,000
Major ordinary share transactions | 8.75% Notes Due April 1, 2027 | Fixed interest rate
Disclosure of nature and extent of risks arising from financial instruments [line items]
Borrowings, interest rate			8.75%
Major ordinary share transactions | 6.625% notes due July 19, 2022
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount		$ 300,000,000
Major ordinary share transactions | 6.625% notes due July 19, 2022 | Fixed interest rate
Disclosure of nature and extent of risks arising from financial instruments [line items]
Borrowings, interest rate	6.625%	6.625%
Major ordinary share transactions | 5.125% notes due June 1, 2021
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount	$ 400,000,000
Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Undrawn borrowing facilities					523,800,000	$ 547,700,000
Trade and other payables					207,454,000
Bank loan					506,471,000
Long-term notes					1,337,200,000
Interest on long-term notes					217,247,000
Lease obligations					14,568,000
Financial liabilities					2,282,940,000
Less than 1 year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Lease obligations					6,216,000
Less than 1 year | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables					207,454,000
Bank loan					0
Long-term notes					0
Interest on long-term notes					75,625,000
Lease obligations					6,216,000
Financial liabilities					289,295,000
1-3 years
Disclosure of nature and extent of risks arising from financial instruments [line items]
Lease obligations					7,748,000
1-3 years | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables					0
Bank loan					506,471,000
Long-term notes					818,600,000
Interest on long-term notes					100,303,000
Lease obligations					7,748,000
Financial liabilities					1,433,122,000
3-5 years
Disclosure of nature and extent of risks arising from financial instruments [line items]
Lease obligations					604,000
3-5 years | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables					0
Bank loan					0
Long-term notes					518,600,000
Interest on long-term notes					41,319,000
Lease obligations					604,000
Financial liabilities					560,523,000
After 5 years
Disclosure of nature and extent of risks arising from financial instruments [line items]
Lease obligations					0
After 5 years | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables					0
Bank loan					0
Long-term notes					0
Interest on long-term notes					0
Lease obligations					0
Financial liabilities					$ 0

Financial Instruments and Ris_8

Financial Instruments and Risk Management - Credit Risk (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of financial assets [line items]
Current trade receivables	$ 173,762	$ 111,564
Financial assets neither past due nor impaired | Current (less than 30 days)
Disclosure of financial assets [line items]
Current trade receivables	169,500	104,099
Financial assets neither past due nor impaired | 31-60 days
Disclosure of financial assets [line items]
Current trade receivables	1,199	3,037
Financial assets neither past due nor impaired | 61-90 days
Disclosure of financial assets [line items]
Current trade receivables	342	1,842
Financial assets past due but not impaired | Past due (more than 90 days)
Disclosure of financial assets [line items]
Current trade receivables	$ 2,721	2,586
Trade receivable, purchasers of petroleum and natural gas
Disclosure of financial assets [line items]
Trade receivable typical collection period	25 days
Trade receivable, accrued petroleum and natural gas sales
Disclosure of financial assets [line items]
Included in accounts receivable	$ 138,000	77,400
Trade receivables
Disclosure of financial assets [line items]
Allowance for doubtful accounts	$ 1,600	$ 1,900
Minimum | Trade receivable, joint interest receivable
Disclosure of financial assets [line items]
Trade receivable typical collection period	1 month
Maximum | Trade receivable, joint interest receivable
Disclosure of financial assets [line items]
Trade receivable typical collection period	3 months

Supplemental Information - Chan

Supplemental Information - Change in Non-Cash Working Capital Items (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Additional information [abstract]
Trade and other receivables	$ (62,198)	$ 1,280
Trade and other payables	(50,660)	113,572
Non-cash working capital acquired	0	(46,773)
Trade and other receivables/payables	(112,858)	68,079
Changes in non-cash working capital related to:
Change in non-cash working capital	(52,070)	39,448
Investing activities	(62,485)	32,435
Foreign currency translation on non-cash working capital	1,697	(3,804)
Changes in non-cash working capital	$ (112,858)	$ 68,079

Supplemental Information - Empl

Supplemental Information - Employee Compensation Costs (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	$ 46,646	$ 47,103
Operating
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	12,918	12,140
General and administrative
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	$ 33,728	$ 34,963

Commitments and Contingencies_2

Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2019CAD ($)
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	$ 39,352
Transportation agreements	115,999
Total	155,351
Less than 1 year
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	10,234
Transportation agreements	11,636
Total	21,870
1-3 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	10,591
Transportation agreements	41,263
Total	51,854
3-5 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	8,848
Transportation agreements	37,099
Total	45,947
After 5 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	9,679
Transportation agreements	26,001
Total	$ 35,680

Related Parties (Details)

Related Parties (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Related Party [Abstract]
Short-term employee benefits	$ 6,202	$ 8,703
Share-based compensation	9,188	10,985
Termination payments	2,208	3,025
Total compensation for key management personnel	$ 17,598	$ 22,713

Capital Management (Details)

Capital Management (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Funds From Operations [Abstract]
Cash flow from operating activities	$ 834,939	$ 485,322
Change in non-cash working capital	52,070	(39,448)
Asset retirement obligations settled	15,417	14,035
Transaction costs	0	13,074
Adjusted funds flow	902,426	472,983
Net Debt [Abstract]
Bank loan - principal	505,412	520,700
Long-term notes - principal	1,328,175	1,583,240
Trade and other payables	207,454	258,114
Cash	(5,572)	0	$ 0
Trade and other current receivables	(173,762)	(111,564)
Net debt	1,871,791	2,265,167
Cost
Net Debt [Abstract]
Bank loan - principal	506,471	522,294
Long-term notes - principal	1,337,200	1,596,323
Liquidity risk
Undrawn Credit Facilities and Net Debt Ratio [Abstract]
Undrawn borrowing facilities	523,800	$ 547,700
Net Debt [Abstract]
Trade and other payables	$ 207,454

Uncategorized Items - _IXDS

Label	Element	Value
Office Leases [Member]
Right-of-use assets	ifrs-full_RightofuseAssets	$ 14,775,000
Vehicles And Other [Member]
Right-of-use assets	ifrs-full_RightofuseAssets	969,000
Field Equipment [Member]
Right-of-use assets	ifrs-full_RightofuseAssets	$ 2,254,000