Baytex Energy (BTE) 6-K 6 Mar 19 2018 FY Management's Report on Internal Control Over Financial Reporting Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	BAYTEX ENERGY CORP.
Entity Central Index Key	1,279,495
Current Fiscal Year End Date	--12-31
Document Type	6-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Statements of Fina

Consolidated Statements of Financial Position - CAD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets
Trade and other receivables	$ 111,564	$ 112,844
Financial derivatives	79,582	18,510
Current assets	191,146	131,354
Non-current assets
Exploration and evaluation assets	358,935	272,974
Oil and gas properties	5,817,889	3,958,309
Other plant and equipment	9,228	9,474
Assets	6,377,198	4,372,111
Current liabilities
Trade and other payables	258,114	144,542
Financial derivatives	0	50,095
Onerous contracts	1,986	2,574
Current liabilities	260,100	197,211
Non-current liabilities
Bank loan	520,700	212,138
Long-term notes	1,583,240	1,474,184
Asset retirement obligations	646,898	368,995
Deferred income tax liability	310,836	204,698
Liabilities	3,321,774	2,457,226
SHAREHOLDERS’ EQUITY
Shareholders' capital	5,701,516	4,443,576
Contributed surplus	19,137	15,999
Accumulated other comprehensive income	667,874	463,104
Deficit	(3,333,103)	(3,007,794)
Shareholders' equity	3,055,424	1,914,885
Liabilities and shareholders' equity	$ 6,377,198	$ 4,372,111

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - CAD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue, net of royalties
Petroleum and natural gas sales	$ 1,428,870	$ 1,099,867
Royalties	(313,754)	(241,892)
Revenue, net of royalties	1,115,116	857,975
Expenses
Operating	311,592	269,283
Transportation	36,869	33,985
Blending and other	68,832	59,345
General and administrative	45,825	47,389
Transaction costs	13,074	0
Exploration and evaluation	21,729	8,253
Depletion and depreciation	558,684	481,929
Impairment	285,341	0
Share-based compensation	19,534	15,509
Financing and interest	119,086	113,638
Financial derivatives gain	(43,550)	(5,177)
Foreign exchange loss (gain)	108,294	(87,060)
Gain on dispositions	(1,946)	(12,081)
Other expense (income)	(1,172)	2,216
Expenses	1,542,192	927,229
Net loss before income taxes	(427,076)	(69,254)
Income tax (recovery) expense
Current income tax recovery	(35)	(1,085)
Deferred income tax recovery	(101,732)	(155,343)
Income tax (recovery) expense	(101,767)	(156,428)
Net income (loss) attributable to shareholders	(325,309)	87,174
Other comprehensive income (loss)
Foreign currency translation adjustment	204,770	(166,759)
Comprehensive income (loss)	$ (120,539)	$ (79,585)
Net income (loss) per common share
Basic (in cad per share)	$ (0.93)	$ 0.37
Diluted (in cad per share)	$ (0.93)	$ 0.37
Weighted average common shares
Basic (in shares)	351,542	234,787
Diluted (in shares)	351,542	237,249

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, 2016	$ 1,978,961	$ 4,422,661	$ 21,405	$ 629,863	$ (3,094,968)
Share issuance costs	0	20,915	(20,915)
Share-based compensation	15,509		15,509
Comprehensive income (loss) for the year	(79,585)			(166,759)
Profit (loss)	87,174				87,174
Ending balance at Dec. 31, 2017	1,914,885	4,443,576	15,999	463,104	(3,007,794)
Issued on corporate acquisition	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
Comprehensive income (loss) for the year	(120,539)			204,770
Profit (loss)	(325,309)				(325,309)
Ending balance at Dec. 31, 2018	$ 3,055,424	$ 5,701,516	$ 19,137	$ 667,874	$ (3,333,103)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Profit (loss)	$ (325,309)	$ 87,174
Adjustments for:
Share-based compensation	19,534	15,509
Unrealized foreign exchange gain	106,143	(86,649)
Exploration and evaluation	21,729	8,253
Depletion and depreciation	558,684	481,929
Impairment	285,341	0
Non-cash financing and accretion	14,768	13,156
Unrealized financial derivatives (gain) loss	(116,715)	2,439
Gain on disposition	(1,946)	(12,081)
Deferred income tax recovery	(101,732)	(155,343)
Payments on onerous contracts	(588)	(6,746)
Asset retirement obligations settled	(14,035)	(13,471)
Change in non-cash working capital	39,448	(8,962)
Cash provided by (used in) operating activities	485,322	325,208
Financing activities
Increase (decrease) in bank loan	(21,295)	33,347
Common share issuance costs	(755)	0
Redemption of long-term notes	0	(8,582)
Cash provided by financing activities	(22,050)	24,765
Investing activities
Additions to exploration and evaluation assets	(10,567)	(7,118)
Additions to oil and gas properties	(485,154)	(319,148)
Additions to other plant and equipment	(1,804)	(238)
Property acquisitions	(701)	(71,643)
Proceeds from dispositions	2,519	11,786
Change in non-cash working capital	32,435	33,683
Cash used in investing activities	(463,272)	(352,678)
Change in cash	0	(2,705)
Cash, beginning of year	0	2,705
Cash, end of year	0	0
Supplementary information
Interest paid	102,230	98,101
Income taxes paid	$ 0	$ 49

Reporting Entity

Reporting Entity	12 Months Ended
	Dec. 31, 2018
Corporate Information And Statement Of IFRS Compliance [Abstract]
Reporting Entity	REPORTING ENTITY Baytex 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, 2018
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. The consolidated financial statements were approved by the Board of Directors of Baytex on March 5, 2019 . 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 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 ("NGLs") reserves in the calculation of depletion and in the determination of fair value estimates for non-financial assets. The estimation of reserves is a complex process requiring significant judgment. Estimates of the Company's reserves are reviewed annually by independent reserves evaluators and represent the estimated recoverable quantities of crude oil, natural gas and NGLs 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 NGLs and their future net cash flows are based on a number of variable 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. When completing this assessment, management considers internal and external sources of information including changes in future commodity prices, changes in industry regulations or royalty rates, asset performance and changes in the Company's estimates of economically recoverable 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 estimates of reserve quantities, the discount rates used to present value future cash flows, future commodity prices, assumptions regarding the timing and amount of future 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. Joint Arrangements Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint control, management considers whether the decisions regarding the capital and operating activities of the arrangement require unanimous consent. Classification of a joint arrangement once joint control has been established also requires judgment. The type of joint arrangement is determined by assessing the rights and obligations arising from the arrangement given the structure, legal form, and terms agreed upon by the parties sharing control. Arrangements where the controlling parties have rights to the net assets of the arrangement are classified as joint ventures. Arrangements where the controlling parties have rights to the assets and revenues, and obligations for the liabilities and expenses, are classified as joint operations. Baytex does not have any joint arrangements that are structured through joint venture arrangements. Financial Derivatives Financial derivatives are measured at fair value on each reporting date. The Company uses estimates of future commodity 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, 2018
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Significant Accounting Policies	SIGNIFICANT ACCOUNTING POLICIES Changes in significant accounting policies Revenue from contracts with customers Baytex adopted IFRS 15 Revenue from Contracts with Customers with a date of initial application of January 1, 2018, using the retrospective method. Baytex recognizes revenue 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 standard also requires new disclosure, as to the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. Baytex analyzed its revenue streams and its contracts with customers on adoption. For the year ended December 31, 2017, $8.3 million of commodity purchases related to heavy oil sales have been reclassified from petroleum and natural gas sales to blending and other expense to conform to the requirements of IFRS 15. There were no adjustments made to the January 1, 2018 opening statement of financial position on adoption. The additional disclosures required by IFRS 15 are provided in note 13 to these consolidated financial statements, in addition to the new significant accounting policy noted below. Financial instruments Baytex adopted IFRS 9 Financial Instruments, on January 1, 2018. The new standard includes three classifications for financial assets; measurement at amortized cost, fair value through profit or loss and fair value through comprehensive income. Under IFRS 9, where the fair value option is applied to financial liabilities, any change in fair value resulting from an entity’s own credit risk is recorded through other comprehensive income or loss rather than net income or loss. The new standard also introduces a credit loss model for evaluating impairment of financial assets. The adoption of this standard did not result in a change in the recognition or measurement of any of the Company's financial instruments on transition. The table summarizes the change in classification categories for Baytex's financial assets and liabilities. Financial Instrument IAS 39 Classification IFRS 9 Classification Cash and cash equivalents Fair value through profit or loss Amortized cost Trade and other receivables Amortized cost Amortized cost Financial derivatives Fair value through profit or loss Fair value through profit or loss Trade and other payables Amortized cost Amortized cost Bank loan Amortized cost Amortized cost Long-term notes Amortized cost Amortized cost 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., Baytex Energy Limited Partnership and Baytex Energy 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 on 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 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. Field inventory, which is included in other plant and equipment, is valued at the lower of cost, using the weighted average cost method, or net realizable value and is not depreciated. 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. 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 pre-tax 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. 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 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. 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. 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. Debt issuance costs related to the restructuring of credit facilities are capitalized and amortized as financing costs over the term of the credit facilities. 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 within general and administrative expense 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 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 plans from the acquisition of Raging River (see 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. Future Accounting Pronouncements Leases In January 2016, the IASB issued IFRS 16 Leases which replaces IAS 17 Leases. IFRS 16 introduces a single recognition and measurement model for lessees, which will require recognition of lease assets and lease obligations on the balance sheet. Short-term leases and leases for low value assets are exempt from recognition and may be treated as operating leases and recognized through net income or loss. The standard is effective for annual periods beginning on or after January 1, 2019. IFRS 16 is required to be adopted either retrospectively or using the modified retrospective approach. The Company will adopt IFRS 16 on January 1, 2019 using the modified retrospective method. The modified retrospective approach does not require restatement of prior period comparative financial information as the Company will record the cumulative effect of applying the standard as an increase to right of use assets with a corresponding increase to lease obligations. The Company is currently in the process of quantifying the impact of the contracts that fall within the scope of IFRS 16. The Company expects adjustments for its office lease and the related subleases, field office leases, certain vehicles and field equipment, however, the full extent of the impact has not yet been finalized.

Business Combination

Business Combination	12 Months Ended
	Dec. 31, 2018
Business Combinations1 [Abstract]
Property Acquisition	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 . In identifying Baytex as the acquirer, Baytex considered, amongst other things, voting rights of all equity instruments, the intended corporate governance structure and composition of senior management of the combined company, in addition to various metrics used to evaluate the relative size of each company. All factors were considered in arriving at the conclusion that Baytex is the acquirer for accounting purposes. 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. All amounts are final. 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 are 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 of the vested units 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 which matures on June 4, 2020 (see note 9). These consolidated financial statements include the results of operations of Raging River for the period following closing of the transaction on August 22, 2018. For the period from August 22, 2018 to December 31, 2018, the acquisition contributed revenues of $158.8 million and operating income of $98.6 million . Had the acquisition occurred on January 1, 2018, revenues 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. 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, 2018
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 2018 2017 2018 2017 2018 2017 2018 2017 Revenue, net of royalties Petroleum and natural gas sales $ 619,215 $ 478,572 $ 809,655 $ 621,295 $ — $ — $ 1,428,870 $ 1,099,867 Royalties (72,700 ) (58,672 ) (241,054 ) (183,220 ) — — (313,754 ) (241,892 ) 546,515 419,900 568,601 438,075 — — 1,115,116 857,975 Expenses Operating 221,717 181,995 89,875 87,288 — — 311,592 269,283 Transportation 36,869 33,985 — — — — 36,869 33,985 Blending and other 68,832 59,345 — — — — 68,832 59,345 General and administrative — — — — 45,825 47,389 45,825 47,389 Transaction costs — — — — 13,074 — 13,074 — Exploration and evaluation 10,580 8,253 11,149 — — — 21,729 8,253 Depletion and depreciation 294,925 199,149 261,709 280,933 2,050 1,847 558,684 481,929 Impairment 65,000 — 220,341 — — — 285,341 — Share-based compensation — — — — 19,534 15,509 19,534 15,509 Financing and interest — — — — 119,086 113,638 119,086 113,638 Financial derivatives gain — — — — (43,550 ) (5,177 ) (43,550 ) (5,177 ) Foreign exchange loss (gain) — — — — 108,294 (87,060 ) 108,294 (87,060 ) Gain on dispositions (1,946 ) (12,048 ) — (33 ) — — (1,946 ) (12,081 ) Other expense (income) — — — — (1,172 ) 2,216 (1,172 ) 2,216 695,977 470,679 583,074 368,188 263,141 88,362 1,542,192 927,229 Net income (loss) before income taxes (149,462 ) (50,779 ) (14,473 ) 69,887 (263,141 ) (88,362 ) (427,076 ) (69,254 ) Income tax recovery Current income tax recovery — — (35 ) (1,085 ) — — (35 ) (1,085 ) Deferred income tax recovery (40,723 ) 622 (26,049 ) (118,163 ) (34,960 ) (37,802 ) (101,732 ) (155,343 ) (40,723 ) 622 (26,084 ) (119,248 ) (34,960 ) (37,802 ) (101,767 ) (156,428 ) Net income (loss) $ (108,739 ) $ (51,401 ) $ 11,611 $ 189,135 $ (228,181 ) $ (50,560 ) $ (325,309 ) $ 87,174 Total oil and natural gas capital expenditures (1) $ 300,299 $ 173,131 $ 193,604 $ 212,992 $ — $ — $ 493,903 $ 386,123 (1) Includes acquisitions, net of proceeds from divestitures. As at December 31, 2018 December 31, 2017 Canadian assets $ 3,739,029 $ 1,677,821 U.S. assets 2,628,941 2,684,816 Corporate assets 9,228 9,474 Total consolidated assets $ 6,377,198 $ 4,372,111

Exploration and Evaluation Asse

Exploration and Evaluation Assets	12 Months Ended
	Dec. 31, 2018
Exploration For And Evaluation Of Mineral Resources [Abstract]
Exploration and Evaluation Assets	EXPLORATION AND EVALUATION ASSETS December 31, 2018 December 31, 2017 Balance, beginning of year $ 272,974 $ 308,462 Capital expenditures 10,567 7,118 Corporate acquisition (note 4) 97,858 — Property acquisitions 514 — Divestitures (1,021 ) (1,276 ) Exploration and evaluation expense (21,729 ) (8,253 ) Transfers to oil and gas properties (Note 7) (13,866 ) (20,198 ) Foreign currency translation 13,638 (12,879 ) Balance, end of year $ 358,935 $ 272,974 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. At December 31, 2017, there were no indicators of impairment for the Company's exploration and evaluation assets.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2018
Property, plant and equipment [abstract]
Oil and gas properties	OIL AND GAS PROPERTIES Cost Accumulated depletion Net book value Balance, December 31, 2016 $ 7,764,037 $ (3,611,868 ) $ 4,152,169 Capital expenditures 319,148 — 319,148 Property acquisitions 136,007 — 136,007 Transfers from exploration and evaluation assets (note 6) 20,198 — 20,198 Transfers from other assets (note 8) 5,124 — 5,124 Change in asset retirement obligations (Note 11) 42,808 — 42,808 Divestitures (105,272 ) 49,291 (55,981 ) Foreign currency translation (249,723 ) 68,641 (181,082 ) Depletion — (480,082 ) (480,082 ) 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 11) 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 For the year ended December 31, 2018 , the Company identified indicators of impairment for its Conventional and Eagle Ford CGUs and recorded total impairment expense to oil and gas properties of $285.3 million ( 2017 - nil ). There were no indicators of impairment identified for the remaining CGUs as at December 31, 2018. 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 our proved plus probable reserves. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $220.3 million recorded as at December 31, 2018. The recoverable amount of the Eagle Ford CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20% . The recoverable amount of each CGU was calculated at December 31, 2018 using the following benchmark reference prices for the years 2019 to 2023 adjusted for commodity differentials specific to the Company. 2019 2020 2021 2022 2023 WTI crude oil (US$/bbl) 63.00 67.00 70.00 71.40 72.83 LLS crude oil (US$/bbl) 68.40 70.37 71.34 72.76 74.22 Edmonton par (CA$/bbl) 75.27 77.89 82.25 84.79 87.39 NYMEX gas (US$/mmbtu) 3.00 3.25 3.50 3.57 3.64 AECO (CA$/GJ) 1.95 2.44 3.00 3.21 3.30 Exchange rate (CAD/USD) 1.30 1.25 1.25 1.25 1.25 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 2023 have been adjusted for inflation at an annual rate of 2.0% . The following table demonstrates the sensitivity of the estimated recoverable amount of reasonably possible changes in key assumptions inherent in the estimate. Increase in discount rate of 1 percent Decrease in discount rate of 1 percent Increase in oil price of $2.50/bbl Decrease in oil price of $2.50/bbl Increase in gas price of $0.25/mcf Decrease in gas price of $0.25/mcf Conventional CGU $ 4,501 $ (4,673 ) $ (6,000 ) $ 6,000 $ (12,000 ) $ 12,000 Eagle Ford CGU 137,820 (155,562 ) (155,559 ) 155,559 (31,385 ) 31,385 Impairment increase (decrease) $ 142,321 $ (160,235 ) $ (161,559 ) $ 161,559 $ (43,385 ) $ 43,385 OTHER PLANT AND EQUIPMENT Cost Accumulated depreciation Net book value Balance, December 31, 2016 $ 67,698 $ (51,339 ) $ 16,359 Capital expenditures 329 — 329 Dispositions, net of acquisitions (255 ) — (255 ) Transfers to oil and gas properties (note 7) (5,124 ) — (5,124 ) Foreign currency translation — 12 12 Depreciation — (1,847 ) (1,847 ) 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

Other Plant and Equipment

Other Plant and Equipment	12 Months Ended
	Dec. 31, 2018
Property, plant and equipment [abstract]
Other Plant and Equipment	OIL AND GAS PROPERTIES Cost Accumulated depletion Net book value Balance, December 31, 2016 $ 7,764,037 $ (3,611,868 ) $ 4,152,169 Capital expenditures 319,148 — 319,148 Property acquisitions 136,007 — 136,007 Transfers from exploration and evaluation assets (note 6) 20,198 — 20,198 Transfers from other assets (note 8) 5,124 — 5,124 Change in asset retirement obligations (Note 11) 42,808 — 42,808 Divestitures (105,272 ) 49,291 (55,981 ) Foreign currency translation (249,723 ) 68,641 (181,082 ) Depletion — (480,082 ) (480,082 ) 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 11) 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 For the year ended December 31, 2018 , the Company identified indicators of impairment for its Conventional and Eagle Ford CGUs and recorded total impairment expense to oil and gas properties of $285.3 million ( 2017 - nil ). There were no indicators of impairment identified for the remaining CGUs as at December 31, 2018. 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 our proved plus probable reserves. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $220.3 million recorded as at December 31, 2018. The recoverable amount of the Eagle Ford CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20% . The recoverable amount of each CGU was calculated at December 31, 2018 using the following benchmark reference prices for the years 2019 to 2023 adjusted for commodity differentials specific to the Company. 2019 2020 2021 2022 2023 WTI crude oil (US$/bbl) 63.00 67.00 70.00 71.40 72.83 LLS crude oil (US$/bbl) 68.40 70.37 71.34 72.76 74.22 Edmonton par (CA$/bbl) 75.27 77.89 82.25 84.79 87.39 NYMEX gas (US$/mmbtu) 3.00 3.25 3.50 3.57 3.64 AECO (CA$/GJ) 1.95 2.44 3.00 3.21 3.30 Exchange rate (CAD/USD) 1.30 1.25 1.25 1.25 1.25 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 2023 have been adjusted for inflation at an annual rate of 2.0% . The following table demonstrates the sensitivity of the estimated recoverable amount of reasonably possible changes in key assumptions inherent in the estimate. Increase in discount rate of 1 percent Decrease in discount rate of 1 percent Increase in oil price of $2.50/bbl Decrease in oil price of $2.50/bbl Increase in gas price of $0.25/mcf Decrease in gas price of $0.25/mcf Conventional CGU $ 4,501 $ (4,673 ) $ (6,000 ) $ 6,000 $ (12,000 ) $ 12,000 Eagle Ford CGU 137,820 (155,562 ) (155,559 ) 155,559 (31,385 ) 31,385 Impairment increase (decrease) $ 142,321 $ (160,235 ) $ (161,559 ) $ 161,559 $ (43,385 ) $ 43,385 OTHER PLANT AND EQUIPMENT Cost Accumulated depreciation Net book value Balance, December 31, 2016 $ 67,698 $ (51,339 ) $ 16,359 Capital expenditures 329 — 329 Dispositions, net of acquisitions (255 ) — (255 ) Transfers to oil and gas properties (note 7) (5,124 ) — (5,124 ) Foreign currency translation — 12 12 Depreciation — (1,847 ) (1,847 ) 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

Bank Loan

Bank Loan	12 Months Ended
	Dec. 31, 2018
Financial Instruments [Abstract]
Bank Loan	BANK LOAN December 31, 2018 December 31, 2017 Bank loan - U.S. dollar denominated (1) $ 122,388 $ 167,159 Bank loan - Canadian dollar denominated 399,906 46,217 Bank loan - principal 522,294 213,376 Unamortized debt issuance costs (1,594 ) (1,238 ) Bank loan $ 520,700 $ 212,138 (1) U.S. dollar denominated bank loan balance was US $89.7 million as at December 31, 2018 (US $133.5 million as at December 31, 2017 ). Baytex has credit facilities that include US $575 million of revolving credit facilities (the "Revolving Facilities") and a CAD $300 million non-revolving term loan (the "Term Loan"). On August 22, 2018, Baytex amended its credit facilities to include the Term Loan assumed in conjunction with the acquisition of Raging River (note 4) which matures on June 4, 2020. The extendible secured Revolving Facilities are comprised of a US $35 million operating loan and a US $340 million syndicated revolving loan for Baytex and a US $200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. and matures on June 4, 2020. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership and matures on June 4, 2020. 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 on June 4, 2020 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, 2018 and 2017, Baytex had $14.6 million of outstanding letters of credit under the credit facilities. At December 31, 2018 , Baytex was in compliance with all of the covenants contained in the credit facilities including the financial covenants as summarized below. Covenant Description Position as at December 31, 2018 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.64:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 8.00:1.00 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, 2018 , the Company's Senior Secured Debt totaled $536.9 million which includes $522.3 million of principal amounts outstanding and $14.6 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, unrealized gains and losses on financial derivatives, 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, 2018 was $833.7 million . (3) Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended December 31, 2018 were $104.3 million . LONG-TERM NOTES December 31, 2018 December 31, 2017 6.75% notes (US$150,000 – principal) due February 17, 2021 204,683 187,770 5.125% notes (US$400,000 – principal) due June 1, 2021 545,820 500,720 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 545,820 500,720 Total long-term notes - principal 1,596,323 1,489,210 Unamortized debt issuance costs (13,083 ) (15,026 ) Total long-term notes - net of unamortized debt issuance costs $ 1,583,240 $ 1,474,184 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 fixed charge coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 9 ) to financing and interest expenses on a trailing twelve month basis) of 2.50 :1.00. As at December 31, 2018 , the fixed charge coverage ratio was 8.00 :1.00.

Long-Term Notes

Long-Term Notes	12 Months Ended
	Dec. 31, 2018
Financial Instruments [Abstract]
Long-Term Notes	BANK LOAN December 31, 2018 December 31, 2017 Bank loan - U.S. dollar denominated (1) $ 122,388 $ 167,159 Bank loan - Canadian dollar denominated 399,906 46,217 Bank loan - principal 522,294 213,376 Unamortized debt issuance costs (1,594 ) (1,238 ) Bank loan $ 520,700 $ 212,138 (1) U.S. dollar denominated bank loan balance was US $89.7 million as at December 31, 2018 (US $133.5 million as at December 31, 2017 ). Baytex has credit facilities that include US $575 million of revolving credit facilities (the "Revolving Facilities") and a CAD $300 million non-revolving term loan (the "Term Loan"). On August 22, 2018, Baytex amended its credit facilities to include the Term Loan assumed in conjunction with the acquisition of Raging River (note 4) which matures on June 4, 2020. The extendible secured Revolving Facilities are comprised of a US $35 million operating loan and a US $340 million syndicated revolving loan for Baytex and a US $200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. and matures on June 4, 2020. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership and matures on June 4, 2020. 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 on June 4, 2020 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, 2018 and 2017, Baytex had $14.6 million of outstanding letters of credit under the credit facilities. At December 31, 2018 , Baytex was in compliance with all of the covenants contained in the credit facilities including the financial covenants as summarized below. Covenant Description Position as at December 31, 2018 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.64:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 8.00:1.00 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, 2018 , the Company's Senior Secured Debt totaled $536.9 million which includes $522.3 million of principal amounts outstanding and $14.6 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, unrealized gains and losses on financial derivatives, 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, 2018 was $833.7 million . (3) Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended December 31, 2018 were $104.3 million . LONG-TERM NOTES December 31, 2018 December 31, 2017 6.75% notes (US$150,000 – principal) due February 17, 2021 204,683 187,770 5.125% notes (US$400,000 – principal) due June 1, 2021 545,820 500,720 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 545,820 500,720 Total long-term notes - principal 1,596,323 1,489,210 Unamortized debt issuance costs (13,083 ) (15,026 ) Total long-term notes - net of unamortized debt issuance costs $ 1,583,240 $ 1,474,184 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 fixed charge coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 9 ) to financing and interest expenses on a trailing twelve month basis) of 2.50 :1.00. As at December 31, 2018 , the fixed charge coverage ratio was 8.00 :1.00.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS December 31, 2018 December 31, 2017 Balance, beginning of year $ 368,995 $ 331,517 Liabilities incurred 12,537 5,825 Liabilities settled (14,035 ) (13,471 ) Liabilities assumed from corporate acquisition (note 4) 39,960 — Liabilities acquired from property acquisitions 132 22,264 Liabilities divested (580 ) (19,940 ) Accretion (note 17) 10,914 8,682 Change in estimate (1) 33,453 (24,028 ) Changes in discount rates and inflation rates (2) 192,672 61,011 Foreign currency translation 2,850 (2,865 ) Balance, end of year $ 646,898 $ 368,995 (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. (2) Change in discount rates and inflation rates includes $136.8 million to revalue the liabilities acquired in the Raging River acquisition (note 4) using the risk-free discount rate. At the date of acquisition, acquired asset retirement obligation liabilities are fair valued using a market discount rate. The undiscounted amount of estimated cash flows required to settle the asset retirement obligations is $673.1 million ( December 31, 2017 - $420.3 million ). Based on an inflation rate of 2.00% ( December 31, 2017 - 2.00% ), the undiscounted amount of estimated future cash flows required to settle the obligation is $ 1,238.6 million ( December 31, 2017 - $756.7 million ). These costs are expected to be incurred over the next 50 years. The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2018 using an estimated annual inflation rate of 2.00% ( December 31, 2017 - 2.00% ) and discounted at a risk free rate of 2.15% ( December 31, 2017 - 2.50% ) is $646.9 million ( December 31, 2017 - $369.0 million ).

Shareholders' Capital

Shareholders' Capital	12 Months Ended
	Dec. 31, 2018
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, 2018 , 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, 2016 233,449 $ 4,422,661 Transfer from contributed surplus on vesting and conversion of share awards 2,002 20,915 Balance, December 31, 2017 235,451 $ 4,443,576 Transfer from contributed surplus on vesting and conversion 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

Petroleum and Natural Gas Sales

Petroleum and Natural Gas Sales	12 Months Ended
	Dec. 31, 2018
Disclosure of revenue from contracts with customers [Abstract]
Petroleum and Natural Gas Sales	PETROLEUM AND NATURAL GAS SALES Petroleum and natural gas sales primarily consists of revenues earned from the sale of produced oil and natural gas volumes pursuant to fixed or variable price contracts, including the physical delivery contracts for fixed volumes outlined in note 19. The activities that generate petroleum and natural gas sales for the Canadian and U.S. operating segments are described below. Canada Segment Petroleum and natural gas sales for Baytex's Canadian operating segment primarily consists of revenues generated from the Company's interest in operated oil and natural gas properties and production taken in-kind from its interest in non-operated oil and natural gas properties. Under its contracts with customers, Baytex is required to deliver volumes of heavy oil, light oil and condensate, natural gas liquids and natural gas to agreed upon locations where control over the delivered volumes is transferred to the customer. Revenue is recognized when control of each unit of product is transferred to the customer with revenues due on the 25th day of the month following delivery. Baytex's customers are primarily oil and natural gas marketers and partners in joint operations in the oil and natural gas industry. Concentration of credit risk is mitigated by marketing production to several oil and natural gas marketers under customary industry and payment terms. Baytex reviews the credit worthiness and, when prudent, obtains certain financial assurances from customers prior to entering sales contracts. The financial strength of the Company's customers is reviewed on a routine basis. U.S. Segment Petroleum and natural gas sales for Baytex's U.S. operating segment primarily consist of revenues generated from the Company's interest in non-operated oil and natural gas properties where the Company has not elected its right to take its production in-kind. The operator of the oil and natural gas properties that comprise the U.S. operating segment enters contracts with customers, conducts the activities required to transfer control of light oil and condensate, natural gas liquids and natural gas volumes to the customer, and collects and remits payments from the customer to Baytex. The Company's petroleum and natural gas sales from contracts with customers for each reportable segment is set forth in the following table. Year Ended December 31 2018 2017 Canada U.S. Total Canada U.S. Total Light oil and condensate $ 169,335 $ 637,055 $ 806,390 $ 23,876 $ 471,997 $ 495,873 Heavy oil 411,794 — 411,794 414,902 — 414,902 NGL 14,531 97,008 111,539 10,664 76,234 86,898 Natural gas 23,555 75,592 99,147 29,130 73,064 102,194 Total petroleum and natural gas sales $ 619,215 $ 809,655 $ 1,428,870 $ 478,572 $ 621,295 $ 1,099,867 Included in accounts receivable at December 31, 2018 is $77.4 million ( December 31, 2017 - $91.6 million ) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.

Share-Based Compensation Plan

Share-Based Compensation Plan	12 Months Ended
	Dec. 31, 2018
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 $19.5 million for the year ended December 31, 2018 ($ 15.5 million for the year ended December 31, 2017 ). Share Awards The weighted average fair value of share awards granted during the year ended December 31, 2018 was $4.04 per restricted and performance award ( December 31, 2017 - $5.75 ). The number of share awards outstanding is detailed below: (000s) Number of restricted awards Number of performance awards (1) Total number of share awards Balance, December 31, 2016 1,508 1,737 3,245 Granted 1,636 1,584 3,220 Vested and converted to common shares (959 ) (1,043 ) (2,002 ) Forfeited (157 ) (25 ) (182 ) 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 (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 fair value of the vested awards was included in consideration (note 4) performance awards associated with the business combination have a fixed payout multiplier of 1.0 . Share Options On August 22, 2018, Baytex became the successor to Raging River's 2012 Option Plan and Raging River's 2016 Option Plan (collectively, the "Option Plans"). Although no new grants will be made under the Option Plans following completion of the Arrangement, share options held under the Option Plans in existence at August 22, 2018 were converted to share options to purchase shares in Baytex, with an exercise price based on the pre-existing exercise price adjusted based on the exchange ratio. Share options granted under the Option Plans have a maximum term of 3.5 years to expiry. 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, 2018 , 4.9 million share options with a weighted average exercise price of $6.70 were outstanding. The following tables summarize the information about the share options. (000s, except per common share amounts) Number of options Weighted average exercise price Balance, December 31, 2017 — $ — Granted — — Assumed on corporate acquisition (note 4) 9,187 6.63 Forfeited/Expired (4,322 ) 6.57 Balance, December 31, 2018 4,865 $ 6.70 Options Outstanding Options Exercisable Exercise price Number outstanding at December 31, 2018 (000s) Weighted average remaining life (years) Weighted average exercise price Number exercisable at December 31, 2018 (000s) Weighted average exercise price $5.00 - $7.00 3,425 1.28 $ 6.28 2,007 $ 6.28 $7.01 - $9.00 1,440 1.04 7.68 960 7.68 Total 4,865 1.21 $ 6.70 2,967 $ 6.73 The fair value of each option granted was estimated on closing of the business combination (note 4) using the Black-Scholes option-pricing model with the following assumptions. Risk-free interest rate (%) 2.0 % Expected life (years) 0.8 - 2.8 Expected volatility (%) (1) 50 % Dividend per share — Expected forfeiture rate (%) — Weighted average fair value at grant date ($/option) 0.25 (1) Expected volatility has been based on historical share volatility of the Company.

Net Income (Loss) Per Share

Net Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2018
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 converted. 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. Year Ended December 31 2018 2017 Net loss Common shares (000's) Net loss per share Net income Common shares (000's) Net income per share Net income (loss) - basic $ (325,309 ) 351,542 $ (0.93 ) $ 87,174 234,787 $ 0.37 Dilutive effect of share awards — — — — 2,462 — Dilutive effect of share options — — — — — — Net income (loss) - diluted $ (325,309 ) 351,542 $ (0.93 ) $ 87,174 237,249 $ 0.37 For the year ended December 31, 2018 , 6.5 million share awards and 4.9 million share options were excluded from the calculation of diluted earnings per share as the Company recorded a net loss. For the year ended December 31, 2017, no share awards were excluded from the calculation of diluted earnings per share and there were no share options outstanding at the time.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
Income Taxes	INCOME TAXES The provision for income taxes has been computed as follows: Year Ended December 31 2018 2017 Net loss before income taxes $ (427,076 ) $ (69,254 ) Expected income taxes at the statutory rate of 27.00% (2017 – 26.93%) (1) (115,311 ) (18,650 ) (Increase) decrease in income tax recovery resulting from: Share-based compensation 5,185 4,177 Non-taxable portion of foreign exchange (gain) loss 14,467 (11,615 ) Effect of change in income tax rates (1) — (104 ) Effect of rate adjustments for foreign jurisdictions (22,119 ) (42,214 ) Effect of U.S. tax reform (2) — (91,830 ) Effect of change in deferred tax benefit not recognized (3) 14,467 (11,615 ) Adjustments and assessments (4) 1,544 15,423 Income tax recovery $ (101,767 ) $ (156,428 ) (1) Expected income tax rate increased due to an increase in the corporate income tax rate in Saskatchewan (from 11.75% to 12% ). (2) On December 22, 2017, the United States of America (the "U.S.") enacted the Tax Cuts and Jobs Act which altered the federal income tax law that applies to Baytex's U.S. subsidiary. The changes include a reduction of the statutory income tax rate to 21% from 35%, resulting in a $91.8 million deferred tax recovery in 2017. (3) A deferred income tax asset has not been recognized for allowable capital losses of $139 million related to the unrealized foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes ( $86 million as at December 31, 2017 ). (4) The Company is regularly subject to audit by the revenue authorities in the jurisdictions in which it operates. During the year ended December 31, 2017, the Company accepted an audit proposal from the Canada Revenue Agency which reduced certain non-capital loss tax pools by $39.3 million and resulted in a $10.6 million increase in deferred tax expense. In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the “CRA”) that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. These reassessments follow the previously disclosed letter from the CRA received by Baytex in November 2014 proposing to issue such reassessments. Baytex remains confident that the tax filings of the affected entities are correct and in September 2016, filed a notice of objection for each notice of reassessment received. These notices of objection will be reviewed by the Appeals Division of CRA; a process that Baytex estimates could take up to two years . If the Appeals Division upholds the notices of reassessment Baytex has the right to appeal to the Tax Court of Canada; a process that Baytex estimates could take a further two years . Should Baytex be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that Baytex estimates could take another two years and potentially longer. The reassessments do not require Baytex to pay any amounts in order to participate in the appeals process. In July 2018, an Appeals Officer was assigned to its file. By way of background, Baytex acquired all of the interests in several privately held commercial trusts in 2010 with accumulated non-capital losses of $591 million (the “Losses”). The Losses were subsequently used to reduce the taxable income of those trusts. The reassessments disallow the deduction of the Losses under the general anti-avoidance rule of the Income Tax Act (Canada). If, after exhausting available appeals, the deduction of Losses continues to be disallowed, Baytex would owe cash taxes for the years 2012 through 2015 and an additional amount for late payment interest. The amount of cash taxes owing and the late payment interest are dependent upon the amount of unused tax shelter available to offset the reassessed income, including tax shelter from future years that may be applied to the years 2012 through 2015. A continuity of the net deferred income tax liability is detailed in the following tables: 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 8,528 (31,512 ) — 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 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 . As at January 1, 2017 Recognized in Net Loss Share Issuance Costs Business Combination Foreign Currency Translation Adjustment December 31, 2017 Taxable temporary differences: Petroleum and natural gas properties $ (967,579 ) $ 221,697 $ — $ — $ 49,455 $ (696,427 ) Financial derivatives 7,869 659 — — — 8,528 Deferred income (419 ) (17,408 ) — — — (17,827 ) Other (5,018 ) 6,076 — — (7,014 ) (5,956 ) Deductible temporary differences: Asset retirement obligations 93,016 5,925 — — (964 ) 97,977 Non-capital losses 404,952 (48,380 ) — — (25,823 ) 330,749 Finance costs 91,484 (13,226 ) — — — 78,258 Net deferred income tax liability (1) $ (375,695 ) $ 155,343 $ — $ — $ 15,654 $ (204,698 ) (1) Non-capital loss carry-forwards at December 31, 2017 totaled $1,478.5 million and expire from 2023 to 2037 . The following is a summary of Baytex's tax pools. December 31, 2018 December 31, 2017 Canadian Tax Pools Canadian oil and natural gas property expenditures $ 529,044 $ 308,366 Canadian development expenditures 765,289 176,188 Canadian exploration expenditures 8,875 1,343 Undepreciated capital costs 502,320 228,739 Non-capital losses 593,251 337,808 Financing costs and other 33,866 46,986 Total Canadian tax pools $ 2,432,645 $ 1,099,430 U.S. Tax Pools Depletion $ 180,367 $ 183,406 Intangible drilling costs 133,345 204,857 Tangibles 69,138 108,631 Non-capital losses 1,140,579 1,140,673 Other 407,654 303,357 Total U.S. tax pools $ 1,931,083 $ 1,940,924

Financing and Interest

Financing and Interest	12 Months Ended
	Dec. 31, 2018
Analysis of income and expense [abstract]
Financing and Interest	FINANCING AND INTEREST Year Ended December 31 2018 2017 Interest on bank loan $ 15,637 $ 11,439 Interest on long-term notes 88,681 89,043 Non-cash financing 3,854 4,474 Accretion on asset retirement obligations (note 11) 10,914 8,682 Financing and interest $ 119,086 $ 113,638

Foreign Exchange

Foreign Exchange	12 Months Ended
	Dec. 31, 2018
Effects Of Changes In Foreign Exchange Rates [Abstract]
Foreign Exchange	FOREIGN EXCHANGE Year Ended December 31 2018 2017 Unrealized foreign exchange loss (gain) $ 106,143 $ (86,649 ) Realized foreign exchange loss (gain) 2,151 (411 ) Foreign exchange loss (gain) $ 108,294 $ (87,060 )

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2018
Financial Instruments [Abstract]
Financial Instruments and Risk Management	FINANCIAL INSTRUMENTS AND RISK MANAGEMENT The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, bank loan and long-term notes. 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, 2018 December 31, 2017 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 79,582 $ 79,582 $ 18,510 $ 18,510 Level 2 Total $ 79,582 $ 79,582 $ 18,510 $ 18,510 Financial assets at amortized cost Trade and other receivables $ 111,564 $ 111,564 $ 112,844 $ 112,844 — Total $ 111,564 $ 111,564 $ 112,844 $ 112,844 Financial Liabilities FVTPL Financial Derivatives $ — $ — $ (50,095 ) $ (50,095 ) Level 2 Total $ — $ — $ (50,095 ) $ (50,095 ) Financial liabilities at amortized cost Trade and other payables $ (258,114 ) $ (258,114 ) $ (144,542 ) $ (144,542 ) — Bank loan (520,700 ) (522,294 ) (212,138 ) (213,376 ) — Long-term notes (1,583,240 ) (1,492,363 ) (1,474,184 ) (1,430,902 ) Level 1 Total $ (2,362,054 ) $ (2,272,771 ) $ (1,830,864 ) $ (1,788,820 ) There were no transfers of financial instruments between Level 1 and Level 2 in during the years ended December 31, 2018 or 2017 . 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, 2018 and 2017 , 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 approximately $8.8 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, 2018 December 31, 2017 December 31, 2018 December 31, 2017 U.S. dollar denominated US$80,857 US$479 US$963,351 US$1,008,001 Interest Rate Risk The Company's interest rate risk arises from the floating rate Revolving Facilities and Term Loan (note 9) . Based on the Company's principle bank loan outstanding net of the interest rate swap, as at December 31, 2018, a change of 100 basis points in interest rates would have an impact on net income or loss before income taxes of approximately $3.2 million . Interest Rate Swaps Baytex had the following interest rate swaps outstanding as of March 5, 2019 : Contract Type Notional Amount Maturity Date Fixed Contract Price Reference (1) Fair Value ($ millions) Interest rate swap $ 100 million October 2020 2.02 % CDOR $ 0.3 Total $ 0.3 Current asset 0.3 (1) Canadian Dollar Offered Rate. The Company partially mitigates its exposure to interest rate risk by entering into interest rate swap transactions. A change of 100 basis points in the interest rates would impact net income or loss before income taxes for the year ended December 31, 2018 by approximately $0.4 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, 2018 , a US $1.00 /bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $2.9 million . When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2018 , a $0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $1.5 million . Financial Derivative Contracts Baytex had the following financial derivative contracts outstanding as of March 5, 2019 : Remaining Period Volume Price/Unit (1) Index Fair Value (2) ($ millions) Oil Fixed - Sell Jan 2019 to Jun 2019 2,000 bbl/d US$62.85/bbl WTI $ 8.0 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$70.00/US$60.00/US$50.00 WTI $ 7.0 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$72.60/US$65.00/US$55.00 WTI $ 4.0 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$72.50/US$66.00/US$56.00 WTI $ 4.1 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$73.00/US$66.00/US$56.00 WTI $ 4.1 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$73.00/US$67.00/US$57.00 WTI $ 8.3 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$74.00/US$68.00/US$58.00 WTI $ 8.4 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$75.00/US$61.70/US$49.00 WTI $ 9.1 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$75.00/US$69.90/US$60.00 WTI $ 4.3 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$76.00/US$71.00/US$61.00 WTI $ 4.4 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$78.00/US$73.00/US$63.00 WTI $ 4.5 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$75.50/US$65.50/US$55.50 Brent $ 3.1 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$77.55/US$70.00/US$60.00 Brent $ 3.7 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$83.00/US$73.00/US$63.00 Brent $ 4.0 Basis Swap (4) Mar 2019 to Jun 2019 2,000 bbl/d WTI less US$14.75/bbl WCS $ — Basis Swap (4) Apr 2019 to Jun 2019 2,000 bbl/d WTI less US$13.65/bbl WCS $ — Basis Swap (4) Jul 2019 to Sep 2019 4,000 bbl/d WTI less US$17.38/bbl WCS $ — Basis Swap (4) Oct 2019 to Dec 2019 4,000 bbl/d WTI less US$20.88/bbl WCS $ — Natural Gas Fixed - Sell Jan 2019 to Mar 2019 5,000 GJ/d CAD$2.25 AECO $ 0.4 Fixed - Sell Jan 2019 to Dec 2019 5,000 mmbtu/d US$3.15 NYMEX $ 0.8 Fixed - Sell Jan 2019 to Mar 2019 10,000 mmbtu/d US$3.82 NYMEX $ 0.8 Fixed - Sell Apr 2019 to Jun 2019 10,000 mmbtu/d US$2.79 NYMEX $ 0.1 Fixed - Sell Jul 2019 to Sep 2019 10,000 mmbtu/d US$2.79 NYMEX $ 0.1 Fixed - Sell Oct 2019 to Dec 2019 10,000 mmbtu/d US$2.88 NYMEX $ 0.1 Total $ 79.3 Current asset $ 79.3 (1) Based on the weighted average price per unit for the period. (2) Fair values as at December 31, 2018 . For the purposes of the table, contracts entered subsequent to December 31, 2018 will have no fair value assigned. (3) Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US $70.00 /US $60.00 /US $50.00 contract, Baytex receives WTI plus US $10.00 /bbl when WTI is at or below US $50.00 /bbl; Baytex receives US$ 60.00 /bbl when WTI is between US $50.00 /bbl and US $60.00 /bbl; Baytex receives the market price when WTI is between US $60.00 /bbl and US $70.00 /bbl; and Baytex receives US $70.00 /bbl when WTI is above US $70.00 /bbl. (4) Contracts entered subsequent to December 31, 2018 . The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives. Year Ended December 31 2018 2017 Realized financial derivatives loss (gain) $ 73,165 $ (7,616 ) Unrealized financial derivatives loss (gain) (116,715 ) 2,439 Financial derivatives gain $ (43,550 ) $ (5,177 ) Physical Delivery Contracts The following physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with the Company's expected sale requirements. Physical delivery contracts are not considered financial instruments and, as a result, no asset or liability has been recognized in the consolidated statements of financial position. As at March 5, 2019 , Baytex had committed to deliver the following volumes of raw bitumen to market on rail: Period Volume Jan 2019 to Oct 2019 1,000 bbl/d Jan 2019 to Dec 2019 5,000 bbl/d Jan 2019 to Dec 2020 5,000 bbl/d 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, 2018 , Baytex had available unused bank credit facilities in the amount of $547.7 million (as at December 31, 2017 - $494.6 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, 2018 is outlined in the table below: Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Trade and other payables $ 258,114 $ 258,114 $ — $ — $ — Bank loan (1) (2) 522,294 — 522,294 — — Long-term notes (2) 1,596,323 — 750,503 300,000 545,820 Interest on long-term notes (3) 334,028 92,367 156,525 72,350 12,786 $ 2,710,759 $ 350,481 $ 1,429,322 $ 372,350 $ 558,606 (1) The bank loan matures on June 4, 2020 unless maturity is extended at Baytex’s request. (2) Principal amount of instruments. (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, 2018, 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, 2018 relates to accrued revenues for November and December 2018 . Accounts receivables from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25 th day of the month following production, with natural gas sales from the Eagle Ford typically collected on the 25th day of the second month following production. Joint interest receivables are typically collected within one to three months following production. Included in accounts receivable at December 31, 2018 is $77.4 million ( December 31, 2017 - $91.6 million ) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date. 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, 2018 , allowance for doubtful accounts was $1.9 million (as at December 31, 2017 - $1.6 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, 2018 , accounts receivable that Baytex has deemed past due (more than 90 days) but not impaired was $ 2.6 million (as at December 31, 2017 - $0.7 million ). Baytex has estimated the lifetime expected credit loss as at and for the years ended December 31, 2018 to be nominal. The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2018 . Trade and Other Receivables Aging December 31, 2018 December 31, 2017 Current (less than 30 days) $ 104,099 $ 107,796 31-60 days 3,037 2,939 61-90 days 1,842 1,427 Past due (more than 90 days) 2,586 682 $ 111,564 $ 112,844

Supplemental Information

Supplemental Information	12 Months Ended
	Dec. 31, 2018
Additional Information1 [Abstract]
Supplemental Information	SUPPLEMENTAL INFORMATION Change in Non-Cash Working Capital Items Year Ended December 31 2018 2017 Trade and other receivables $ 1,280 $ (673 ) Trade and other payables 113,572 31,569 Non-cash working capital acquired (note 4) (46,773 ) (4,357 ) $ 68,079 $ 26,539 Changes in non-cash working capital related to: Operating activities $ 39,448 $ (8,962 ) Investing activities 32,435 33,683 Foreign currency translation on non-cash working capital (3,804 ) 1,818 $ 68,079 $ 26,539 Onerous Contracts Onerous contracts result from unfavorable leases in which the unavoidable costs of meeting the obligations under the contracts exceed the economic benefits expected to be received. Year Ended December 31 2018 2017 Balance, beginning of year $ 2,574 $ 9,504 Liabilities settled (588 ) (6,746 ) Foreign currency translation — (184 ) Balance, end of year $ 1,986 $ 2,574 As at December 31, 2018 , the Company has a provision totaling $2.0 million for an onerous contract related to office space that has been subleased (as at December 31, 2017 - $2.6 million ). The provision represents the difference between the minimum future payments that the Company is required to make and the estimated recoveries from the sublease agreements. 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. Year Ended December 31 2018 2017 Operating $ 12,140 $ 13,424 General and administrative 34,963 36,086 Total employee compensation costs $ 47,103 $ 49,510

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
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, 2018 , and the expected timing of funding of these obligations, are noted in the table below. Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Operating leases $ 22,745 7,484 12,492 2,753 16 Processing agreements 47,717 10,926 15,526 9,039 12,226 Transportation agreements 112,002 14,398 42,054 19,821 35,729 Total $ 182,464 $ 32,808 $ 70,072 $ 31,613 $ 47,971 Baytex also has ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached the end of their economic lives. The present value of the future estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statements of financial position. Programs to abandon and reclaim wellsites and facilities are undertaken regularly in accordance with applicable legislative requirements. Operating lease and sublease payments recognized as an expense during the year ended December 31, 2018 were $6.3 million ( December 31, 2017 - $6.5 million ). Baytex has entered into operating leases on office buildings in the ordinary course of business. The Company's operating lease agreements do not contain any contingent rent clauses. The Company has the option to renew or extend the leases on its office building with the new lease terms to be based on current market prices. None of the operating lease agreements contain purchase options or escalation clauses or any restrictions regarding dividends, further leases or additional debt. The litigation and claims that Baytex is engaged with, which arose in the normal course of operations, are not expected to materially affect the Company's financial position or reported results of operations.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2018
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 (including directors) are noted in the table below. Year Ended December 31 2018 2017 Short-term employee benefits $ 8,703 $ 7,840 Share-based compensation 10,985 3,569 Termination payments 3,025 275 Total compensation for key management personnel $ 22,713 $ 11,684

Capital Disclosures

Capital Disclosures	12 Months Ended
	Dec. 31, 2018
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 our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions and the risk characteristics of our oil and gas properties. At December 31, 2018 , our 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 our capital structure and liquidity, we 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, 2018 , Baytex was in compliance with all of the covenants contained in the credit facilities and had unused capacity of $547.7 million . We consider 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 our abandonment obligations and potential future dividends. We eliminate 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 our capital programs and the maturity of our operating areas. The settlement of abandonment obligations are managed with our 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 we are able to provide a more meaningful measure of our cash flow on a continuing basis. Transaction costs associated with the business combination (note 4) are excluded from adjusted funds flow as we consider the costs non-recurring and not reflective of our 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. Year Ended December 31 2018 2017 Cash flow from operating activities $ 485,322 $ 325,208 Change in non-cash working capital (39,448 ) 8,962 Asset retirement obligations settled 14,035 13,471 Transaction costs $ 13,074 $ — Adjusted funds flow $ 472,983 $ 347,641 We believe that net debt assists in providing a more complete understanding of our financial position and provides a key measure to assess our liquidity. We calculate net debt based on the principal amounts of our 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. We use the principal amounts of the bank loan and long-term notes outstanding in the calculation of net debt as these amounts represent our 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, 2018 December 31, 2017 Bank loan - principal $ 522,294 $ 213,376 Long-term notes - principal 1,596,323 1,489,210 Trade and other payables 258,114 144,542 Trade and other receivables (111,564 ) (112,844 ) Net debt $ 2,265,167 $ 1,734,284 At December 31, 2018, Baytex had $547.7 million of undrawn availability under its credit facilities (December 31, 2017 - $494.6 million ).

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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., Baytex Energy Limited Partnership and Baytex Energy 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 on 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.
Pre-license Costs	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 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. Field inventory, which is included in other plant and equipment, is valued at the lower of cost, using the weighted average cost method, or net realizable value and is not depreciated.
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. 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 pre-tax 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.
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 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. 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. 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. Debt issuance costs related to the restructuring of credit facilities are capitalized and amortized as financing costs over the term of the credit facilities. 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 within general and administrative expense in the statement of income or loss.
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 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 plans from the acquisition of Raging River (see 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.
Future Accounting Pronouncements - Leases	Future Accounting Pronouncements Leases In January 2016, the IASB issued IFRS 16 Leases which replaces IAS 17 Leases. IFRS 16 introduces a single recognition and measurement model for lessees, which will require recognition of lease assets and lease obligations on the balance sheet. Short-term leases and leases for low value assets are exempt from recognition and may be treated as operating leases and recognized through net income or loss. The standard is effective for annual periods beginning on or after January 1, 2019. IFRS 16 is required to be adopted either retrospectively or using the modified retrospective approach. The Company will adopt IFRS 16 on January 1, 2019 using the modified retrospective method. The modified retrospective approach does not require restatement of prior period comparative financial information as the Company will record the cumulative effect of applying the standard as an increase to right of use assets with a corresponding increase to lease obligations. The Company is currently in the process of quantifying the impact of the contracts that fall within the scope of IFRS 16. The Company expects adjustments for its office lease and the related subleases, field office leases, certain vehicles and field equipment, however, the full extent of the impact has not yet been finalized.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
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 depletion Net book value Balance, December 31, 2016 $ 7,764,037 $ (3,611,868 ) $ 4,152,169 Capital expenditures 319,148 — 319,148 Property acquisitions 136,007 — 136,007 Transfers from exploration and evaluation assets (note 6) 20,198 — 20,198 Transfers from other assets (note 8) 5,124 — 5,124 Change in asset retirement obligations (Note 11) 42,808 — 42,808 Divestitures (105,272 ) 49,291 (55,981 ) Foreign currency translation (249,723 ) 68,641 (181,082 ) Depletion — (480,082 ) (480,082 ) 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 11) 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 Cost Accumulated depreciation Net book value Balance, December 31, 2016 $ 67,698 $ (51,339 ) $ 16,359 Capital expenditures 329 — 329 Dispositions, net of acquisitions (255 ) — (255 ) Transfers to oil and gas properties (note 7) (5,124 ) — (5,124 ) Foreign currency translation — 12 12 Depreciation — (1,847 ) (1,847 ) 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

Business Combination (Tables)

Business Combination (Tables)	12 Months Ended
	Dec. 31, 2018
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. All amounts are final. 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 are 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 of the vested units 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 which matures on June 4, 2020 (see note 9).

Segmented Financial Informati_2

Segmented Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2018 2017 2018 2017 2018 2017 Revenue, net of royalties Petroleum and natural gas sales $ 619,215 $ 478,572 $ 809,655 $ 621,295 $ — $ — $ 1,428,870 $ 1,099,867 Royalties (72,700 ) (58,672 ) (241,054 ) (183,220 ) — — (313,754 ) (241,892 ) 546,515 419,900 568,601 438,075 — — 1,115,116 857,975 Expenses Operating 221,717 181,995 89,875 87,288 — — 311,592 269,283 Transportation 36,869 33,985 — — — — 36,869 33,985 Blending and other 68,832 59,345 — — — — 68,832 59,345 General and administrative — — — — 45,825 47,389 45,825 47,389 Transaction costs — — — — 13,074 — 13,074 — Exploration and evaluation 10,580 8,253 11,149 — — — 21,729 8,253 Depletion and depreciation 294,925 199,149 261,709 280,933 2,050 1,847 558,684 481,929 Impairment 65,000 — 220,341 — — — 285,341 — Share-based compensation — — — — 19,534 15,509 19,534 15,509 Financing and interest — — — — 119,086 113,638 119,086 113,638 Financial derivatives gain — — — — (43,550 ) (5,177 ) (43,550 ) (5,177 ) Foreign exchange loss (gain) — — — — 108,294 (87,060 ) 108,294 (87,060 ) Gain on dispositions (1,946 ) (12,048 ) — (33 ) — — (1,946 ) (12,081 ) Other expense (income) — — — — (1,172 ) 2,216 (1,172 ) 2,216 695,977 470,679 583,074 368,188 263,141 88,362 1,542,192 927,229 Net income (loss) before income taxes (149,462 ) (50,779 ) (14,473 ) 69,887 (263,141 ) (88,362 ) (427,076 ) (69,254 ) Income tax recovery Current income tax recovery — — (35 ) (1,085 ) — — (35 ) (1,085 ) Deferred income tax recovery (40,723 ) 622 (26,049 ) (118,163 ) (34,960 ) (37,802 ) (101,732 ) (155,343 ) (40,723 ) 622 (26,084 ) (119,248 ) (34,960 ) (37,802 ) (101,767 ) (156,428 ) Net income (loss) $ (108,739 ) $ (51,401 ) $ 11,611 $ 189,135 $ (228,181 ) $ (50,560 ) $ (325,309 ) $ 87,174 Total oil and natural gas capital expenditures (1) $ 300,299 $ 173,131 $ 193,604 $ 212,992 $ — $ — $ 493,903 $ 386,123 (1) Includes acquisitions, net of proceeds from divestitures.
Assets by segment	As at December 31, 2018 December 31, 2017 Canadian assets $ 3,739,029 $ 1,677,821 U.S. assets 2,628,941 2,684,816 Corporate assets 9,228 9,474 Total consolidated assets $ 6,377,198 $ 4,372,111

Exploration and Evaluation As_2

Exploration and Evaluation Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Exploration For And Evaluation Of Mineral Resources [Abstract]
Exploration and evaluation assets	December 31, 2018 December 31, 2017 Balance, beginning of year $ 272,974 $ 308,462 Capital expenditures 10,567 7,118 Corporate acquisition (note 4) 97,858 — Property acquisitions 514 — Divestitures (1,021 ) (1,276 ) Exploration and evaluation expense (21,729 ) (8,253 ) Transfers to oil and gas properties (Note 7) (13,866 ) (20,198 ) Foreign currency translation 13,638 (12,879 ) Balance, end of year $ 358,935 $ 272,974

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2018
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 depletion Net book value Balance, December 31, 2016 $ 7,764,037 $ (3,611,868 ) $ 4,152,169 Capital expenditures 319,148 — 319,148 Property acquisitions 136,007 — 136,007 Transfers from exploration and evaluation assets (note 6) 20,198 — 20,198 Transfers from other assets (note 8) 5,124 — 5,124 Change in asset retirement obligations (Note 11) 42,808 — 42,808 Divestitures (105,272 ) 49,291 (55,981 ) Foreign currency translation (249,723 ) 68,641 (181,082 ) Depletion — (480,082 ) (480,082 ) 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 11) 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 Cost Accumulated depreciation Net book value Balance, December 31, 2016 $ 67,698 $ (51,339 ) $ 16,359 Capital expenditures 329 — 329 Dispositions, net of acquisitions (255 ) — (255 ) Transfers to oil and gas properties (note 7) (5,124 ) — (5,124 ) Foreign currency translation — 12 12 Depreciation — (1,847 ) (1,847 ) 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
Disclosure of recoverable amount of CGU benchmark reference prices	The recoverable amount of each CGU was calculated at December 31, 2018 using the following benchmark reference prices for the years 2019 to 2023 adjusted for commodity differentials specific to the Company. 2019 2020 2021 2022 2023 WTI crude oil (US$/bbl) 63.00 67.00 70.00 71.40 72.83 LLS crude oil (US$/bbl) 68.40 70.37 71.34 72.76 74.22 Edmonton par (CA$/bbl) 75.27 77.89 82.25 84.79 87.39 NYMEX gas (US$/mmbtu) 3.00 3.25 3.50 3.57 3.64 AECO (CA$/GJ) 1.95 2.44 3.00 3.21 3.30 Exchange rate (CAD/USD) 1.30 1.25 1.25 1.25 1.25
Sensitivity of The Estimated Recoverable Amount of Changes in Assumptions	The following table demonstrates the sensitivity of the estimated recoverable amount of reasonably possible changes in key assumptions inherent in the estimate. Increase in discount rate of 1 percent Decrease in discount rate of 1 percent Increase in oil price of $2.50/bbl Decrease in oil price of $2.50/bbl Increase in gas price of $0.25/mcf Decrease in gas price of $0.25/mcf Conventional CGU $ 4,501 $ (4,673 ) $ (6,000 ) $ 6,000 $ (12,000 ) $ 12,000 Eagle Ford CGU 137,820 (155,562 ) (155,559 ) 155,559 (31,385 ) 31,385 Impairment increase (decrease) $ 142,321 $ (160,235 ) $ (161,559 ) $ 161,559 $ (43,385 ) $ 43,385

Other Plant and Equipment (Tabl

Other Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
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 depletion Net book value Balance, December 31, 2016 $ 7,764,037 $ (3,611,868 ) $ 4,152,169 Capital expenditures 319,148 — 319,148 Property acquisitions 136,007 — 136,007 Transfers from exploration and evaluation assets (note 6) 20,198 — 20,198 Transfers from other assets (note 8) 5,124 — 5,124 Change in asset retirement obligations (Note 11) 42,808 — 42,808 Divestitures (105,272 ) 49,291 (55,981 ) Foreign currency translation (249,723 ) 68,641 (181,082 ) Depletion — (480,082 ) (480,082 ) 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 11) 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 Cost Accumulated depreciation Net book value Balance, December 31, 2016 $ 67,698 $ (51,339 ) $ 16,359 Capital expenditures 329 — 329 Dispositions, net of acquisitions (255 ) — (255 ) Transfers to oil and gas properties (note 7) (5,124 ) — (5,124 ) Foreign currency translation — 12 12 Depreciation — (1,847 ) (1,847 ) 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

Bank Loan (Tables)

Bank Loan (Tables)	12 Months Ended
	Dec. 31, 2018
Financial Instruments [Abstract]
Bank loans	December 31, 2018 December 31, 2017 Bank loan - U.S. dollar denominated (1) $ 122,388 $ 167,159 Bank loan - Canadian dollar denominated 399,906 46,217 Bank loan - principal 522,294 213,376 Unamortized debt issuance costs (1,594 ) (1,238 ) Bank loan $ 520,700 $ 212,138 (1) U.S. dollar denominated bank loan balance was US $89.7 million as at December 31, 2018 (US $133.5 million as at December 31, 2017 ). At December 31, 2018 , Baytex was in compliance with all of the covenants contained in the credit facilities including the financial covenants as summarized below. Covenant Description Position as at December 31, 2018 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.64:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 8.00:1.00 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, 2018 , the Company's Senior Secured Debt totaled $536.9 million which includes $522.3 million of principal amounts outstanding and $14.6 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, unrealized gains and losses on financial derivatives, 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, 2018 was $833.7 million . (3) Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended December 31, 2018 were $104.3 million . December 31, 2018 December 31, 2017 6.75% notes (US$150,000 – principal) due February 17, 2021 204,683 187,770 5.125% notes (US$400,000 – principal) due June 1, 2021 545,820 500,720 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 545,820 500,720 Total long-term notes - principal 1,596,323 1,489,210 Unamortized debt issuance costs (13,083 ) (15,026 ) Total long-term notes - net of unamortized debt issuance costs $ 1,583,240 $ 1,474,184

Long-Term Notes (Tables)

Long-Term Notes (Tables)	12 Months Ended
	Dec. 31, 2018
Financial Instruments [Abstract]
Long-term notes	December 31, 2018 December 31, 2017 Bank loan - U.S. dollar denominated (1) $ 122,388 $ 167,159 Bank loan - Canadian dollar denominated 399,906 46,217 Bank loan - principal 522,294 213,376 Unamortized debt issuance costs (1,594 ) (1,238 ) Bank loan $ 520,700 $ 212,138 (1) U.S. dollar denominated bank loan balance was US $89.7 million as at December 31, 2018 (US $133.5 million as at December 31, 2017 ). At December 31, 2018 , Baytex was in compliance with all of the covenants contained in the credit facilities including the financial covenants as summarized below. Covenant Description Position as at December 31, 2018 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.64:1.00 3.50:1.00 Interest Coverage (3) (Minimum Ratio) 8.00:1.00 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, 2018 , the Company's Senior Secured Debt totaled $536.9 million which includes $522.3 million of principal amounts outstanding and $14.6 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, unrealized gains and losses on financial derivatives, 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, 2018 was $833.7 million . (3) Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended December 31, 2018 were $104.3 million . December 31, 2018 December 31, 2017 6.75% notes (US$150,000 – principal) due February 17, 2021 204,683 187,770 5.125% notes (US$400,000 – principal) due June 1, 2021 545,820 500,720 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 545,820 500,720 Total long-term notes - principal 1,596,323 1,489,210 Unamortized debt issuance costs (13,083 ) (15,026 ) Total long-term notes - net of unamortized debt issuance costs $ 1,583,240 $ 1,474,184

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Change in asset retirement obligations	December 31, 2018 December 31, 2017 Balance, beginning of year $ 368,995 $ 331,517 Liabilities incurred 12,537 5,825 Liabilities settled (14,035 ) (13,471 ) Liabilities assumed from corporate acquisition (note 4) 39,960 — Liabilities acquired from property acquisitions 132 22,264 Liabilities divested (580 ) (19,940 ) Accretion (note 17) 10,914 8,682 Change in estimate (1) 33,453 (24,028 ) Changes in discount rates and inflation rates (2) 192,672 61,011 Foreign currency translation 2,850 (2,865 ) Balance, end of year $ 646,898 $ 368,995 (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. (2) Change in discount rates and inflation rates includes $136.8 million to revalue the liabilities acquired in the Raging River acquisition (note 4) using the risk-free discount rate. At the date of acquisition, acquired asset retirement obligation liabilities are fair valued using a market discount rate. Onerous contracts result from unfavorable leases in which the unavoidable costs of meeting the obligations under the contracts exceed the economic benefits expected to be received. Year Ended December 31 2018 2017 Balance, beginning of year $ 2,574 $ 9,504 Liabilities settled (588 ) (6,746 ) Foreign currency translation — (184 ) Balance, end of year $ 1,986 $ 2,574

Shareholders' Capital (Tables)

Shareholders' Capital (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2016 233,449 $ 4,422,661 Transfer from contributed surplus on vesting and conversion of share awards 2,002 20,915 Balance, December 31, 2017 235,451 $ 4,443,576 Transfer from contributed surplus on vesting and conversion 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

Petroleum and Natural Gas Sal_2

Petroleum and Natural Gas Sales (Tables)	12 Months Ended
	Dec. 31, 2018
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. Year Ended December 31 2018 2017 Canada U.S. Total Canada U.S. Total Light oil and condensate $ 169,335 $ 637,055 $ 806,390 $ 23,876 $ 471,997 $ 495,873 Heavy oil 411,794 — 411,794 414,902 — 414,902 NGL 14,531 97,008 111,539 10,664 76,234 86,898 Natural gas 23,555 75,592 99,147 29,130 73,064 102,194 Total petroleum and natural gas sales $ 619,215 $ 809,655 $ 1,428,870 $ 478,572 $ 621,295 $ 1,099,867

Share-Based Compensation Plan (

Share-Based Compensation Plan (Tables)	12 Months Ended
	Dec. 31, 2018
Share-Based Payment Arrangements [Abstract]
Fair value measurements	The fair value of each option granted was estimated on closing of the business combination (note 4) using the Black-Scholes option-pricing model with the following assumptions. Risk-free interest rate (%) 2.0 % Expected life (years) 0.8 - 2.8 Expected volatility (%) (1) 50 % Dividend per share — Expected forfeiture rate (%) — Weighted average fair value at grant date ($/option) 0.25 (1) Expected volatility has been based on historical share volatility of the Company.
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 exercise price Balance, December 31, 2017 — $ — Granted — — Assumed on corporate acquisition (note 4) 9,187 6.63 Forfeited/Expired (4,322 ) 6.57 Balance, December 31, 2018 4,865 $ 6.70 Options Outstanding Options Exercisable Exercise price Number outstanding at December 31, 2018 (000s) Weighted average remaining life (years) Weighted average exercise price Number exercisable at December 31, 2018 (000s) Weighted average exercise price $5.00 - $7.00 3,425 1.28 $ 6.28 2,007 $ 6.28 $7.01 - $9.00 1,440 1.04 7.68 960 7.68 Total 4,865 1.21 $ 6.70 2,967 $ 6.73
Number of share awards outstanding	The number of share awards outstanding is detailed below: (000s) Number of restricted awards Number of performance awards (1) Total number of share awards Balance, December 31, 2016 1,508 1,737 3,245 Granted 1,636 1,584 3,220 Vested and converted to common shares (959 ) (1,043 ) (2,002 ) Forfeited (157 ) (25 ) (182 ) 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 (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 fair value of the vested awards was included in consideration (note 4) performance awards associated with the business combination have a fixed payout multiplier of 1.0 .

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings per share [abstract]
Net income (loss) per share	Year Ended December 31 2018 2017 Net loss Common shares (000's) Net loss per share Net income Common shares (000's) Net income per share Net income (loss) - basic $ (325,309 ) 351,542 $ (0.93 ) $ 87,174 234,787 $ 0.37 Dilutive effect of share awards — — — — 2,462 — Dilutive effect of share options — — — — — — Net income (loss) - diluted $ (325,309 ) 351,542 $ (0.93 ) $ 87,174 237,249 $ 0.37

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
Provision for income taxes	The provision for income taxes has been computed as follows: Year Ended December 31 2018 2017 Net loss before income taxes $ (427,076 ) $ (69,254 ) Expected income taxes at the statutory rate of 27.00% (2017 – 26.93%) (1) (115,311 ) (18,650 ) (Increase) decrease in income tax recovery resulting from: Share-based compensation 5,185 4,177 Non-taxable portion of foreign exchange (gain) loss 14,467 (11,615 ) Effect of change in income tax rates (1) — (104 ) Effect of rate adjustments for foreign jurisdictions (22,119 ) (42,214 ) Effect of U.S. tax reform (2) — (91,830 ) Effect of change in deferred tax benefit not recognized (3) 14,467 (11,615 ) Adjustments and assessments (4) 1,544 15,423 Income tax recovery $ (101,767 ) $ (156,428 ) (1) Expected income tax rate increased due to an increase in the corporate income tax rate in Saskatchewan (from 11.75% to 12% ). (2) On December 22, 2017, the United States of America (the "U.S.") enacted the Tax Cuts and Jobs Act which altered the federal income tax law that applies to Baytex's U.S. subsidiary. The changes include a reduction of the statutory income tax rate to 21% from 35%, resulting in a $91.8 million deferred tax recovery in 2017. (3) A deferred income tax asset has not been recognized for allowable capital losses of $139 million related to the unrealized foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes ( $86 million as at December 31, 2017 ). (4) The Company is regularly subject to audit by the revenue authorities in the jurisdictions in which it operates. During the year ended December 31, 2017, the Company accepted an audit proposal from the Canada Revenue Agency which reduced certain non-capital loss tax pools by $39.3 million and resulted in a $10.6 million increase in deferred tax expense.
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, 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 8,528 (31,512 ) — 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 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 . As at January 1, 2017 Recognized in Net Loss Share Issuance Costs Business Combination Foreign Currency Translation Adjustment December 31, 2017 Taxable temporary differences: Petroleum and natural gas properties $ (967,579 ) $ 221,697 $ — $ — $ 49,455 $ (696,427 ) Financial derivatives 7,869 659 — — — 8,528 Deferred income (419 ) (17,408 ) — — — (17,827 ) Other (5,018 ) 6,076 — — (7,014 ) (5,956 ) Deductible temporary differences: Asset retirement obligations 93,016 5,925 — — (964 ) 97,977 Non-capital losses 404,952 (48,380 ) — — (25,823 ) 330,749 Finance costs 91,484 (13,226 ) — — — 78,258 Net deferred income tax liability (1) $ (375,695 ) $ 155,343 $ — $ — $ 15,654 $ (204,698 ) (1) Non-capital loss carry-forwards at December 31, 2017 totaled $1,478.5 million and expire from 2023 to 2037 .
Summary of tax pools	The following is a summary of Baytex's tax pools. December 31, 2018 December 31, 2017 Canadian Tax Pools Canadian oil and natural gas property expenditures $ 529,044 $ 308,366 Canadian development expenditures 765,289 176,188 Canadian exploration expenditures 8,875 1,343 Undepreciated capital costs 502,320 228,739 Non-capital losses 593,251 337,808 Financing costs and other 33,866 46,986 Total Canadian tax pools $ 2,432,645 $ 1,099,430 U.S. Tax Pools Depletion $ 180,367 $ 183,406 Intangible drilling costs 133,345 204,857 Tangibles 69,138 108,631 Non-capital losses 1,140,579 1,140,673 Other 407,654 303,357 Total U.S. tax pools $ 1,931,083 $ 1,940,924

Financing and Interest (Tables)

Financing and Interest (Tables)	12 Months Ended
	Dec. 31, 2018
Analysis of income and expense [abstract]
Schedule of financing and interest	Year Ended December 31 2018 2017 Interest on bank loan $ 15,637 $ 11,439 Interest on long-term notes 88,681 89,043 Non-cash financing 3,854 4,474 Accretion on asset retirement obligations (note 11) 10,914 8,682 Financing and interest $ 119,086 $ 113,638

Foreign Exchange (Tables)

Foreign Exchange (Tables)	12 Months Ended
	Dec. 31, 2018
Effects Of Changes In Foreign Exchange Rates [Abstract]
Foreign exchange gains and losses	Year Ended December 31 2018 2017 Unrealized foreign exchange loss (gain) $ 106,143 $ (86,649 ) Realized foreign exchange loss (gain) 2,151 (411 ) Foreign exchange loss (gain) $ 108,294 $ (87,060 )

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 December 31, 2017 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 79,582 $ 79,582 $ 18,510 $ 18,510 Level 2 Total $ 79,582 $ 79,582 $ 18,510 $ 18,510 Financial assets at amortized cost Trade and other receivables $ 111,564 $ 111,564 $ 112,844 $ 112,844 — Total $ 111,564 $ 111,564 $ 112,844 $ 112,844 Financial Liabilities FVTPL Financial Derivatives $ — $ — $ (50,095 ) $ (50,095 ) Level 2 Total $ — $ — $ (50,095 ) $ (50,095 ) Financial liabilities at amortized cost Trade and other payables $ (258,114 ) $ (258,114 ) $ (144,542 ) $ (144,542 ) — Bank loan (520,700 ) (522,294 ) (212,138 ) (213,376 ) — Long-term notes (1,583,240 ) (1,492,363 ) (1,474,184 ) (1,430,902 ) Level 1 Total $ (2,362,054 ) $ (2,272,771 ) $ (1,830,864 ) $ (1,788,820 )
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, 2018 December 31, 2017 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 79,582 $ 79,582 $ 18,510 $ 18,510 Level 2 Total $ 79,582 $ 79,582 $ 18,510 $ 18,510 Financial assets at amortized cost Trade and other receivables $ 111,564 $ 111,564 $ 112,844 $ 112,844 — Total $ 111,564 $ 111,564 $ 112,844 $ 112,844 Financial Liabilities FVTPL Financial Derivatives $ — $ — $ (50,095 ) $ (50,095 ) Level 2 Total $ — $ — $ (50,095 ) $ (50,095 ) Financial liabilities at amortized cost Trade and other payables $ (258,114 ) $ (258,114 ) $ (144,542 ) $ (144,542 ) — Bank loan (520,700 ) (522,294 ) (212,138 ) (213,376 ) — Long-term notes (1,583,240 ) (1,492,363 ) (1,474,184 ) (1,430,902 ) Level 1 Total $ (2,362,054 ) $ (2,272,771 ) $ (1,830,864 ) $ (1,788,820 )
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, 2018 December 31, 2017 December 31, 2018 December 31, 2017 U.S. dollar denominated US$80,857 US$479 US$963,351 US$1,008,001
Disclosure of derivative financial instruments	Baytex had the following interest rate swaps outstanding as of March 5, 2019 : Contract Type Notional Amount Maturity Date Fixed Contract Price Reference (1) Fair Value ($ millions) Interest rate swap $ 100 million October 2020 2.02 % CDOR $ 0.3 Total $ 0.3 Current asset 0.3 (1) Canadian Dollar Offered Rate.
Disclosure of financial derivative contracts	Baytex had the following financial derivative contracts outstanding as of March 5, 2019 : Remaining Period Volume Price/Unit (1) Index Fair Value (2) ($ millions) Oil Fixed - Sell Jan 2019 to Jun 2019 2,000 bbl/d US$62.85/bbl WTI $ 8.0 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$70.00/US$60.00/US$50.00 WTI $ 7.0 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$72.60/US$65.00/US$55.00 WTI $ 4.0 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$72.50/US$66.00/US$56.00 WTI $ 4.1 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$73.00/US$66.00/US$56.00 WTI $ 4.1 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$73.00/US$67.00/US$57.00 WTI $ 8.3 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$74.00/US$68.00/US$58.00 WTI $ 8.4 3-way option (3) Jan 2019 to Dec 2019 2,000 bbl/d US$75.00/US$61.70/US$49.00 WTI $ 9.1 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$75.00/US$69.90/US$60.00 WTI $ 4.3 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$76.00/US$71.00/US$61.00 WTI $ 4.4 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$78.00/US$73.00/US$63.00 WTI $ 4.5 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$75.50/US$65.50/US$55.50 Brent $ 3.1 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$77.55/US$70.00/US$60.00 Brent $ 3.7 3-way option (3) Jan 2019 to Dec 2019 1,000 bbl/d US$83.00/US$73.00/US$63.00 Brent $ 4.0 Basis Swap (4) Mar 2019 to Jun 2019 2,000 bbl/d WTI less US$14.75/bbl WCS $ — Basis Swap (4) Apr 2019 to Jun 2019 2,000 bbl/d WTI less US$13.65/bbl WCS $ — Basis Swap (4) Jul 2019 to Sep 2019 4,000 bbl/d WTI less US$17.38/bbl WCS $ — Basis Swap (4) Oct 2019 to Dec 2019 4,000 bbl/d WTI less US$20.88/bbl WCS $ — Natural Gas Fixed - Sell Jan 2019 to Mar 2019 5,000 GJ/d CAD$2.25 AECO $ 0.4 Fixed - Sell Jan 2019 to Dec 2019 5,000 mmbtu/d US$3.15 NYMEX $ 0.8 Fixed - Sell Jan 2019 to Mar 2019 10,000 mmbtu/d US$3.82 NYMEX $ 0.8 Fixed - Sell Apr 2019 to Jun 2019 10,000 mmbtu/d US$2.79 NYMEX $ 0.1 Fixed - Sell Jul 2019 to Sep 2019 10,000 mmbtu/d US$2.79 NYMEX $ 0.1 Fixed - Sell Oct 2019 to Dec 2019 10,000 mmbtu/d US$2.88 NYMEX $ 0.1 Total $ 79.3 Current asset $ 79.3 (1) Based on the weighted average price per unit for the period. (2) Fair values as at December 31, 2018 . For the purposes of the table, contracts entered subsequent to December 31, 2018 will have no fair value assigned. (3) Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US $70.00 /US $60.00 /US $50.00 contract, Baytex receives WTI plus US $10.00 /bbl when WTI is at or below US $50.00 /bbl; Baytex receives US$ 60.00 /bbl when WTI is between US $50.00 /bbl and US $60.00 /bbl; Baytex receives the market price when WTI is between US $60.00 /bbl and US $70.00 /bbl; and Baytex receives US $70.00 /bbl when WTI is above US $70.00 /bbl. (4) Contracts entered subsequent to December 31, 2018 .
Disclosure of financial derivatives marked-to-market	The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives. Year Ended December 31 2018 2017 Realized financial derivatives loss (gain) $ 73,165 $ (7,616 ) Unrealized financial derivatives loss (gain) (116,715 ) 2,439 Financial derivatives gain $ (43,550 ) $ (5,177 )
Disclosure of physical delivery contracts	The following physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with the Company's expected sale requirements. Physical delivery contracts are not considered financial instruments and, as a result, no asset or liability has been recognized in the consolidated statements of financial position. As at March 5, 2019 , Baytex had committed to deliver the following volumes of raw bitumen to market on rail: Period Volume Jan 2019 to Oct 2019 1,000 bbl/d Jan 2019 to Dec 2019 5,000 bbl/d Jan 2019 to Dec 2020 5,000 bbl/d
Disclosure of cash outflows relating to financial liabilities	The timing of cash outflows relating to financial liabilities as at December 31, 2018 is outlined in the table below: Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Trade and other payables $ 258,114 $ 258,114 $ — $ — $ — Bank loan (1) (2) 522,294 — 522,294 — — Long-term notes (2) 1,596,323 — 750,503 300,000 545,820 Interest on long-term notes (3) 334,028 92,367 156,525 72,350 12,786 $ 2,710,759 $ 350,481 $ 1,429,322 $ 372,350 $ 558,606 (1) The bank loan matures on June 4, 2020 unless maturity is extended at Baytex’s request. (2) Principal amount of instruments. (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, 2018 . Trade and Other Receivables Aging December 31, 2018 December 31, 2017 Current (less than 30 days) $ 104,099 $ 107,796 31-60 days 3,037 2,939 61-90 days 1,842 1,427 Past due (more than 90 days) 2,586 682 $ 111,564 $ 112,844

Supplemental Information (Table

Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2018
Additional information [abstract]
Changes in non-cash working capital items	Year Ended December 31 2018 2017 Trade and other receivables $ 1,280 $ (673 ) Trade and other payables 113,572 31,569 Non-cash working capital acquired (note 4) (46,773 ) (4,357 ) $ 68,079 $ 26,539 Changes in non-cash working capital related to: Operating activities $ 39,448 $ (8,962 ) Investing activities 32,435 33,683 Foreign currency translation on non-cash working capital (3,804 ) 1,818 $ 68,079 $ 26,539
Onerous contracts	December 31, 2018 December 31, 2017 Balance, beginning of year $ 368,995 $ 331,517 Liabilities incurred 12,537 5,825 Liabilities settled (14,035 ) (13,471 ) Liabilities assumed from corporate acquisition (note 4) 39,960 — Liabilities acquired from property acquisitions 132 22,264 Liabilities divested (580 ) (19,940 ) Accretion (note 17) 10,914 8,682 Change in estimate (1) 33,453 (24,028 ) Changes in discount rates and inflation rates (2) 192,672 61,011 Foreign currency translation 2,850 (2,865 ) Balance, end of year $ 646,898 $ 368,995 (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. (2) Change in discount rates and inflation rates includes $136.8 million to revalue the liabilities acquired in the Raging River acquisition (note 4) using the risk-free discount rate. At the date of acquisition, acquired asset retirement obligation liabilities are fair valued using a market discount rate. Onerous contracts result from unfavorable leases in which the unavoidable costs of meeting the obligations under the contracts exceed the economic benefits expected to be received. Year Ended December 31 2018 2017 Balance, beginning of year $ 2,574 $ 9,504 Liabilities settled (588 ) (6,746 ) Foreign currency translation — (184 ) Balance, end of year $ 1,986 $ 2,574
Employee compensation costs	The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense. Year Ended December 31 2018 2017 Operating $ 12,140 $ 13,424 General and administrative 34,963 36,086 Total employee compensation costs $ 47,103 $ 49,510

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies [Abstract]
Financial obligations and expected timing	These obligations as of December 31, 2018 , and the expected timing of funding of these obligations, are noted in the table below. Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Operating leases $ 22,745 7,484 12,492 2,753 16 Processing agreements 47,717 10,926 15,526 9,039 12,226 Transportation agreements 112,002 14,398 42,054 19,821 35,729 Total $ 182,464 $ 32,808 $ 70,072 $ 31,613 $ 47,971

Related Parties (Tables)

Related Parties (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party [Abstract]
Transactions with key management personnel	Transactions with key management personnel (including directors) are noted in the table below. Year Ended December 31 2018 2017 Short-term employee benefits $ 8,703 $ 7,840 Share-based compensation 10,985 3,569 Termination payments 3,025 275 Total compensation for key management personnel $ 22,713 $ 11,684

Capital Disclosures (Tables)

Capital Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
Corporate Information And Statement Of IFRS Compliance [Abstract]
Capital management information	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. Year Ended December 31 2018 2017 Cash flow from operating activities $ 485,322 $ 325,208 Change in non-cash working capital (39,448 ) 8,962 Asset retirement obligations settled 14,035 13,471 Transaction costs $ 13,074 $ — Adjusted funds flow $ 472,983 $ 347,641 We believe that net debt assists in providing a more complete understanding of our financial position and provides a key measure to assess our liquidity. We calculate net debt based on the principal amounts of our 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. We use the principal amounts of the bank loan and long-term notes outstanding in the calculation of net debt as these amounts represent our 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, 2018 December 31, 2017 Bank loan - principal $ 522,294 $ 213,376 Long-term notes - principal 1,596,323 1,489,210 Trade and other payables 258,114 144,542 Trade and other receivables (111,564 ) (112,844 ) Net debt $ 2,265,167 $ 1,734,284 At December 31, 2018, Baytex had $547.7 million of undrawn availability under its credit facilities (December 31, 2017 - $494.6 million ).

Significant Accounting Polici_4

Significant Accounting Policies - Depreciation Methods and Estimated Useful Lives (Details)	12 Months Ended
	Dec. 31, 2018
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%

Significant Accounting Polici_5

Significant Accounting Policies - Additional Information (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of disaggregation of revenue from contracts with customers [line items]
Payables for purchase of energy	$ 1,428,870	$ 1,099,867
Blending and other	$ 68,832	59,345
Maximum percentage of issuable awards to outstanding common stock	3.80%
Fixed multiplier for share awards	100.00%
Scenario, Adjustment
Disclosure of disaggregation of revenue from contracts with customers [line items]
Payables for purchase of energy		8,300
Blending and other		$ 8,300

Business Combination (Details)

Business Combination (Details) - CAD ($) $ in Thousands	Aug. 22, 2018	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Jan. 20, 2017
Disclosure of detailed information about business combination [line items]
Date of acquisition	Aug. 22, 2018
Name of acquiree	Raging River Exploration Inc.
Description of acquiree	publicly traded oil and gas producer with light oil producing properties in southwest Saskatchewan and Alberta
Closing price of common shares	3.93
Consideration
Common shares issued	$ 1,238,995
Share-based compensation	3,100		$ 19,534	$ 15,509
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
Acquisition-related costs recognised as expense for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination			13,074	$ 0
Issuance costs, net of tax			(551)
Oil and Gas Producer Raging River Exploration, Inc.
Disclosure of detailed information about business combination [line items]
Market discount rate					7.50%
Consideration
Total consideration	$ 1,242,095				$ 1,200,000
Fair value of net assets acquired
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
Acquisition-related costs recognised as expense for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination			$ 13,074
Shareholders’ capital
Disclosure of detailed information about business combination [line items]
Number of shares issued	(315,300,000)	315,266,000	315,266,000
Fair value of net assets acquired
Issuance costs, net of tax			$ (551)
Shareholders’ capital | Oil and Gas Producer Raging River Exploration, Inc.
Fair value of net assets acquired
Issuance costs, net of tax			551
Other Inflows (Outflows) Of Cash, Classified As Financing Activities, Net Of Tax			$ 200

Segmented Financial Informati_3

Segmented Financial Information - Information By Reportable Segment (Details) - CAD ($) $ in Thousands	Aug. 22, 2018	Dec. 31, 2018	Dec. 31, 2017
Revenue, net of royalties
Petroleum and natural gas sales		$ 1,428,870	$ 1,099,867
Royalties		(313,754)	(241,892)
Revenue, net of royalties		1,115,116	857,975
Expenses
Operating		311,592	269,283
Transportation		36,869	33,985
Blending and other		68,832	59,345
General and administrative		45,825	47,389
Transaction costs		13,074	0
Exploration and evaluation		21,729	8,253
Depletion and depreciation		558,684	481,929
Impairment		285,341	0
Share-based compensation	$ 3,100	19,534	15,509
Financing and interest		119,086	113,638
Financial derivatives gain		(43,550)	(5,177)
Foreign exchange loss (gain)		108,294	(87,060)
Gain on dispositions		(1,946)	(12,081)
Other expense (income)		(1,172)	2,216
Expenses		1,542,192	927,229
Net loss before income taxes		(427,076)	(69,254)
Income tax (recovery) expense
Current income tax recovery		(35)	(1,085)
Deferred income tax recovery		(101,732)	(155,343)
Income tax (recovery) expense		(101,767)	(156,428)
Net income (loss) attributable to shareholders		(325,309)	87,174
Operating segments | Canada
Revenue, net of royalties
Petroleum and natural gas sales		619,215	478,572
Royalties		(72,700)	(58,672)
Revenue, net of royalties		546,515	419,900
Expenses
Operating		221,717	181,995
Transportation		36,869	33,985
Blending and other		68,832	59,345
General and administrative		0	0
Transaction costs		0	0
Exploration and evaluation		10,580	8,253
Depletion and depreciation		294,925	199,149
Impairment		65,000	0
Share-based compensation		0	0
Financing and interest		0	0
Financial derivatives gain		0	0
Foreign exchange loss (gain)		0	0
Gain on dispositions		(1,946)	(12,048)
Other expense (income)		0	0
Expenses		695,977	470,679
Net loss before income taxes		(149,462)	(50,779)
Income tax (recovery) expense
Current income tax recovery		0	0
Deferred income tax recovery		(40,723)	622
Income tax (recovery) expense		(40,723)	622
Net income (loss) attributable to shareholders		(108,739)	(51,401)
Total oil and natural gas capital expenditures		300,299	173,131
Operating segments | U.S.
Revenue, net of royalties
Petroleum and natural gas sales		809,655	621,295
Royalties		(241,054)	(183,220)
Revenue, net of royalties		568,601	438,075
Expenses
Operating		89,875	87,288
Transportation		0	0
Blending and other		0	0
General and administrative		0	0
Transaction costs		0	0
Exploration and evaluation		11,149	0
Depletion and depreciation		261,709	280,933
Impairment			0
Share-based compensation		0	0
Financing and interest		0	0
Financial derivatives gain		0	0
Foreign exchange loss (gain)		0	0
Gain on dispositions		0	(33)
Other expense (income)		0	0
Expenses		583,074	368,188
Net loss before income taxes		(14,473)	69,887
Income tax (recovery) expense
Current income tax recovery		(35)	(1,085)
Deferred income tax recovery		(26,049)	(118,163)
Income tax (recovery) expense		(26,084)	(119,248)
Net income (loss) attributable to shareholders		11,611	189,135
Total oil and natural gas capital expenditures		193,604	212,992
Corporate
Revenue, net of royalties
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		45,825	47,389
Transaction costs		13,074
Exploration and evaluation		0	0
Depletion and depreciation		2,050	1,847
Impairment		0	0
Share-based compensation		19,534	15,509
Financing and interest		119,086	113,638
Financial derivatives gain		(43,550)	(5,177)
Foreign exchange loss (gain)		108,294	(87,060)
Gain on dispositions		0	0
Other expense (income)		(1,172)	2,216
Expenses		263,141	88,362
Net loss before income taxes		(263,141)	(88,362)
Income tax (recovery) expense
Current income tax recovery		0	0
Deferred income tax recovery		(34,960)	(37,802)
Income tax (recovery) expense		(34,960)	(37,802)
Net income (loss) attributable to shareholders		(228,181)	(50,560)
Total oil and natural gas capital expenditures		0	0
Consolidated
Revenue, net of royalties
Petroleum and natural gas sales		1,428,870	1,099,867
Royalties		(313,754)	(241,892)
Revenue, net of royalties		1,115,116	857,975
Expenses
Operating		311,592	269,283
Transportation		36,869	33,985
Blending and other		68,832	59,345
General and administrative		45,825	47,389
Transaction costs		13,074	0
Exploration and evaluation		21,729	8,253
Depletion and depreciation		558,684	481,929
Impairment		285,341	0
Share-based compensation		19,534	15,509
Financing and interest		119,086	113,638
Financial derivatives gain		(43,550)	(5,177)
Foreign exchange loss (gain)		108,294	(87,060)
Gain on dispositions		(1,946)	(12,081)
Other expense (income)		(1,172)	2,216
Expenses		1,542,192	927,229
Net loss before income taxes		(427,076)	(69,254)
Income tax (recovery) expense
Current income tax recovery		(35)	(1,085)
Deferred income tax recovery		(101,732)	(155,343)
Income tax (recovery) expense		(101,767)	(156,428)
Net income (loss) attributable to shareholders		(325,309)	87,174
Total oil and natural gas capital expenditures		$ 493,903	$ 386,123

Segmented Financial Informati_4

Segmented Financial Information - Assets By Segment (Details) - CAD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Disclosure of operating segments [line items]
Assets	$ 6,377,198	$ 4,372,111
Other plant and equipment	9,228	9,474
Operating segments | Canada
Disclosure of operating segments [line items]
Assets	3,739,029	1,677,821
Operating segments | U.S.
Disclosure of operating segments [line items]
Assets	2,628,941	2,684,816
Corporate
Disclosure of operating segments [line items]
Other plant and equipment	9,228	9,474
Consolidated
Disclosure of operating segments [line items]
Assets	$ 6,377,198	$ 4,372,111

Exploration and Evaluation As_3

Exploration and Evaluation Assets (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in intangible assets other than goodwill [abstract]
Exploration and evaluation assets, beginning of year	$ 272,974
Exploration and evaluation expense	(21,729)	$ (8,253)
Exploration and evaluation assets, end of year	358,935	272,974
Exploration and evaluation assets
Reconciliation of changes in intangible assets other than goodwill [abstract]
Exploration and evaluation assets, beginning of year	272,974	308,462
Capital expenditures	10,567	7,118
Corporate acquisition	97,858	0
Property acquisitions	514	0
Divestitures	(1,021)	(1,276)
Exploration and evaluation expense	(21,729)	(8,253)
Transfers to oil and gas properties (Note 7)	(13,866)	(20,198)
Foreign currency translation	13,638	(12,879)
Exploration and evaluation assets, end of year	$ 358,935	$ 272,974

Oil and Gas Properties - Schedu

Oil and Gas Properties - Schedule of PPE Activity, Oil and Gas (Details) - Oil and gas assets - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	$ 3,958,309	$ 4,152,169
Capital expenditures	485,154	319,148
Corporate acquisition	1,748,368
Property acquisitions	202	136,007
Transfers from exploration and evaluation assets (note 6)	13,866	20,198
Transfers from other assets (note 8)		5,124
Change in asset retirement obligations (Note 11)	238,662	42,808
Divestitures	(15)	(55,981)
Impairment	285,341
Foreign currency translation	215,318	(181,082)
Depletion	(556,634)	(480,082)
Balance, end of year	5,817,889	3,958,309
Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	7,932,327	7,764,037
Capital expenditures	485,154	319,148
Corporate acquisition	1,748,368
Property acquisitions	202	136,007
Transfers from exploration and evaluation assets (note 6)	13,866	20,198
Transfers from other assets (note 8)		5,124
Change in asset retirement obligations (Note 11)	238,662	42,808
Divestitures	(15)	(105,272)
Impairment	0
Foreign currency translation	325,969	(249,723)
Depletion	0	0
Balance, end of year	10,744,533	7,932,327
Accumulated depletion
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	(3,974,018)	(3,611,868)
Capital expenditures	0	0
Corporate acquisition	0
Property acquisitions	0	0
Transfers from exploration and evaluation assets (note 6)	0	0
Transfers from other assets (note 8)		0
Change in asset retirement obligations (Note 11)	0	0
Divestitures	0	49,291
Impairment	285,341	0
Foreign currency translation	(110,651)	68,641
Depletion	(556,634)	(480,082)
Balance, end of year	$ (4,926,644)	$ (3,974,018)

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018CAD ($)$ / $$ / MMBTU$ / bbl	Dec. 31, 2017CAD ($)
Disclosure of detailed information about property, plant and equipment [line items]
Impairment | $	$ 285,341	$ 0
Adjusted inflation for prices and costs subsequent to 2023	0.020
Peace River CGU | Minimum | Oil and gas assets
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections		8.00%
Peace River CGU | Maximum | Oil and gas assets
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections		20.00%
Peace River CGU | 2019
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate | $ / $	1.30
Peace River CGU | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate | $ / $	1.25
Peace River CGU | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate | $ / $	1.25
Peace River CGU | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate | $ / $	1.25
Peace River CGU | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate | $ / $	1.25
Eagle Ford CGU | Minimum | Oil and gas assets
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections		8.00%
Eagle Ford CGU | Maximum | Oil and gas assets
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 loss recognised | $	$ (285,341)
Oil and gas assets | Peace River CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss recognised | $		$ 65,000
WTI | Peace River CGU | Oil reserves | 2019
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	63
WTI | Peace River CGU | Oil reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	67
WTI | Peace River CGU | Oil reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	70
WTI | Peace River CGU | Oil reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	71.40
WTI | Peace River CGU | Oil reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	72.83
LLS | Peace River CGU | Oil reserves | 2019
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	68.40
LLS | Peace River CGU | Oil reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	70.37
LLS | Peace River CGU | Oil reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	71.34
LLS | Peace River CGU | Oil reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	72.76
LLS | Peace River CGU | Oil reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	74.22
Edmonton | Peace River CGU | Oil reserves | 2019
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	75.27
Edmonton | Peace River CGU | Oil reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	77.89
Edmonton | Peace River CGU | Oil reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	82.25
Edmonton | Peace River CGU | Oil reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	84.79
Edmonton | Peace River CGU | Oil reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	87.39
NYMEX | Peace River CGU | Natural gas reserves | 2019
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3
NYMEX | Peace River CGU | Natural gas reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.25
NYMEX | Peace River CGU | Natural gas reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.50
NYMEX | Peace River CGU | Natural gas reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.57
NYMEX | Peace River CGU | Natural gas reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.64
AECO | Peace River CGU | Natural gas reserves | 2019
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | $ / MMBTU	1.95
AECO | Peace River CGU | Natural gas reserves | 2020
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | $ / MMBTU	2.44
AECO | Peace River CGU | Natural gas reserves | 2021
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | $ / MMBTU	3
AECO | Peace River CGU | Natural gas reserves | 2022
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | $ / MMBTU	3.21
AECO | Peace River CGU | Natural gas reserves | 2023
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | $ / MMBTU	3.30
U.S. | Operating segments
Disclosure of detailed information about property, plant and equipment [line items]
Impairment | $		0
U.S. | Operating segments | Oil and gas assets | Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment | $	$ 220,341
Accumulated depreciation | Oil and gas assets
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss recognised | $	$ (285,341)	$ 0

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, 2018CAD ($)
Disclosure of detailed information about property, plant and equipment [line items]
Sensitivity Analysis Of Discount Rate, Impact of 1 Percent Increase	$ 142,321
Sensitivity Analysis Of Discount Rate, Impact of 1 Percent Decrease	(160,235)
Sensitivity Analysis Of Change In Oil Price, Increase	(161,559)
Sensitivity Analysis Of Change In Oil Price, Decrease	161,559
Sensitivity Analysis Of Change In Gas Price, Increase	(43,385)
Sensitivity Analysis Of Change In Gas Price, Decrease	43,385
Conventional CGU
Disclosure of detailed information about property, plant and equipment [line items]
Sensitivity Analysis Of Discount Rate, Impact of 1 Percent Increase	4,501
Sensitivity Analysis Of Discount Rate, Impact of 1 Percent Decrease	(4,673)
Sensitivity Analysis Of Change In Oil Price, Increase	(6,000)
Sensitivity Analysis Of Change In Oil Price, Decrease	6,000
Sensitivity Analysis Of Change In Gas Price, Increase	(12,000)
Sensitivity Analysis Of Change In Gas Price, Decrease	12,000
Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Sensitivity Analysis Of Discount Rate, Impact of 1 Percent Increase	137,820
Sensitivity Analysis Of Discount Rate, Impact of 1 Percent Decrease	(155,562)
Sensitivity Analysis Of Change In Oil Price, Increase	(155,559)
Sensitivity Analysis Of Change In Oil Price, Decrease	155,559
Sensitivity Analysis Of Change In Gas Price, Increase	(31,385)
Sensitivity Analysis Of Change In Gas Price, Decrease	$ 31,385

Other Plant and Equipment (Deta

Other Plant and Equipment (Details) - Other property, plant and equipment - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	$ 9,474	$ 16,359
Capital expenditures	1,804	329
Dispositions, net of acquisitions		(255)
Transfers to oil and gas properties (note 7)		(5,124)
Foreign currency translation		12
Depreciation	(2,050)	(1,847)
Balance, end of year	9,228	9,474
Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	62,648	67,698
Capital expenditures	1,804	329
Dispositions, net of acquisitions		(255)
Transfers to oil and gas properties (note 7)		(5,124)
Foreign currency translation		0
Depreciation	0	0
Balance, end of year	64,452	62,648
Accumulated depreciation
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	(53,174)	(51,339)
Capital expenditures	0	0
Dispositions, net of acquisitions		0
Transfers to oil and gas properties (note 7)		0
Foreign currency translation		12
Depreciation	(2,050)	(1,847)
Balance, end of year	$ (55,224)	$ (53,174)

Bank Loan - Bank Loan (Details)

Bank Loan - Bank Loan (Details) $ in Thousands, $ in Millions	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)
Disclosure of detailed information about borrowings [line items]
Bank loan		$ 520,700		$ 212,138
Bank loan - U.S. dollar denominated
Disclosure of detailed information about borrowings [line items]
Bank loan		122,388
Bank loan - Canadian dollar denominated
Disclosure of detailed information about borrowings [line items]
Bank loan		399,906
Principal
Disclosure of detailed information about borrowings [line items]
Bank loan		522,294		213,376
Principal | Bank loan - U.S. dollar denominated
Disclosure of detailed information about borrowings [line items]
Bank loan	$ 89.7		$ 133.5	167,159
Principal | Bank loan - Canadian dollar denominated
Disclosure of detailed information about borrowings [line items]
Bank loan				46,217
Unamortized debt issuance costs
Disclosure of detailed information about borrowings [line items]
Bank loan		$ (1,594)		$ (1,238)

Bank Loan - Financial Covenants

Bank Loan - Financial Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	$ 14.6
Senior Secured Debt, as defined	536.9
Bank EBITDA, as defined	833.7
Financing and interest expenses, as defined	$ 104.3
Position as at December 31, 2018
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt to Bank EBITDA (Maximum Ratio)	0.64
Interest Coverage (Minimum Ratio)	8
Covenant
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt to Bank EBITDA (Maximum Ratio)	3.5
Interest Coverage (Minimum Ratio)	2

Bank Loan - Additional Informat

Bank Loan - Additional Information (Details) - Dec. 31, 2018 $ in Millions	USD ($)	CAD ($)
Revolving Facilities
Disclosure of detailed information about borrowings [line items]
Maximum Borrowing Capacity		$ 575
Non-Revolving Facilities
Disclosure of detailed information about borrowings [line items]
Maximum Borrowing Capacity		$ 300
Operating loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	$ 35,000,000
Syndicated loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	340,000,000
Subsidiary syndicated loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	$ 200,000,000

Long-Term Notes (Details)

Long-Term Notes (Details)	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal		$ 1,583,240,000	$ 1,474,184,000
Covenant compliance, minimum fixed charge ratio	2.5
Fixed charge ratio	8
Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal		1,596,323,000	1,489,210,000
Unamortized debt issuance costs
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal		$ (13,083,000)	(15,026,000)
6.75% notes (US$150,000 – principal) due February 17, 2021
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 150,000,000
6.75% notes (US$150,000 – principal) due February 17, 2021 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	6.75%	6.75%
6.75% notes (US$150,000 – principal) due February 17, 2021 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal		$ 204,683,000	187,770,000
5.125% notes (US$400,000 – principal) due June 1, 2021
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 400,000,000
5.125% notes (US$400,000 – principal) due June 1, 2021 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	5.125%	5.125%
5.125% notes (US$400,000 – principal) due June 1, 2021 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal		$ 545,820,000	500,720,000
6.625% notes (Cdn$300,000 – principal) due July 19, 2022
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 300,000,000
6.625% notes (Cdn$300,000 – principal) due July 19, 2022 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	6.625%	6.625%
6.625% notes (Cdn$300,000 – principal) 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 (US$400,000 – principal) due June 1, 2024
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 400,000,000
5.625% notes (US$400,000 – principal) due June 1, 2024 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	5.625%	5.625%
5.625% notes (US$400,000 – principal) due June 1, 2024 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes - principal		$ 545,820,000	$ 500,720,000

Asset Retirement Obligations -

Asset Retirement Obligations - Changes In Asset Retirement Obligations (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in other provisions [Abstract]
Accretion	$ 10,914	$ 8,682
Asset retirement obligation
Reconciliation of changes in other provisions [Abstract]
Balance, beginning of year	368,995	331,517
Liabilities incurred	12,537	5,825
Liabilities settled	(14,035)	(13,471)
Liabilities acquired from property acquisitions	132	22,264
Liabilities divested	(580)	(19,940)
Change in estimate	33,453	(24,028)
Changes in discount rates and inflation rates	192,672	61,011
Foreign currency translation	2,850	(2,865)
Balance, end of the year	646,898	368,995
Asset retirement obligation | Aggregated individually immaterial business combinations
Reconciliation of changes in other provisions [Abstract]
Liabilities assumed from corporate acquisition	39,960	$ 0
Asset retirement obligation | Oil Properties In Peace River Area
Reconciliation of changes in other provisions [Abstract]
Changes in discount rates and inflation rates	$ 136,800

Asset Retirement Obligations _2

Asset Retirement Obligations - Additional Information (Details) - Asset retirement obligation - CAD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of other provisions [line items]
Estimated cash flows, undiscounted amount	$ 673,100	$ 420,300
Estimated inflation rate	2.00%	2.00%
Undiscounted cash flow amount required to settle obligation	$ 1,238,600	$ 756,700
Estimated risk free rate	2.15%	2.50%
Other provisions	$ 646,898	$ 368,995	$ 331,517

Shareholders' Capital (Details)

Shareholders' Capital (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018CAD ($)voteshares	Dec. 31, 2017CAD ($)shares	Aug. 22, 2018shares
Number of Common Shares (000s)
Issued on corporate acquisition	$ 755	$ 0
Changes in equity [abstract]
Beginning balance	1,914,885	1,978,961
Transfer from contributed surplus on vesting and conversion of share awards, amount	0	0
Issued on corporate acquisition, amount	1,242,095
Ending balance	3,055,424	$ 1,914,885
Issue costs not recognised as expense for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination	$ (551)
Shareholders’ capital
Number of shares issued | shares	315,266,000		(315,300,000)
Number of Common Shares (000s)
Beginning balance (in shares) | shares	235,451,000	233,449,000
Transfer from contributed surplus on vesting and conversion of share awards | shares	3,343,000	2,002,000
Ending balance (in shares) | shares	554,060,000	235,451,000
Changes in equity [abstract]
Beginning balance	$ 4,443,576	$ 4,422,661
Transfer from contributed surplus on vesting and conversion of share awards, amount		20,915
Transfer from contributed surplus on vesting and conversion of share awards, amount	19,496	20,915
Issued on corporate acquisition, amount	1,238,995
Ending balance	5,701,516	$ 4,443,576
Issue costs not recognised as expense for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination	$ (551)
Preference shares
Preferred shares without nominal or par value | shares	10,000,000
Number of shares issued | shares	0
Ordinary shares
Voting rights, votes per share | vote	1

Petroleum and Natural Gas Sal_3

Petroleum and Natural Gas Sales (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of operating segments [line items]
Petroleum and natural gas sales	$ 1,428,870	$ 1,099,867
Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	619,215	478,572
U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	809,655	621,295
Light Oil and Condensate
Disclosure of operating segments [line items]
Petroleum and natural gas sales	806,390	495,873
Light Oil and Condensate | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	169,335	23,876
Light Oil and Condensate | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	637,055	471,997
Heavy Oil Properties
Disclosure of operating segments [line items]
Petroleum and natural gas sales	411,794	414,902
Heavy Oil Properties | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	411,794	414,902
Heavy Oil Properties | 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	111,539	86,898
NGL | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	14,531	10,664
NGL | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	97,008	76,234
Natural Gas Sales
Disclosure of operating segments [line items]
Petroleum and natural gas sales	99,147	102,194
Natural Gas Sales | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	23,555	29,130
Natural Gas Sales | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	75,592	73,064
Trade receivable, accrued petroleum and natural gas sales
Disclosure of operating segments [line items]
Included in accounts receivable	$ 77,400	$ 91,600

Share-Based Compensation Plan_2

Share-Based Compensation Plan (Details) shares in Thousands	Aug. 22, 2018CAD ($)	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Compensation expense related to share awards	$ (3,100,000)	$ (19,534,000)	$ (15,509,000)
Total number of share awards
Beginning (in shares) | shares		4,281	3,245
Granted (in shares) | shares		5,384	3,220
Number Of Equity Instruments Assumed, Corporate Acquisition		$ 559,000
Vested and converted to common shares (in shares) | shares		(3,343)	(2,002)
Forfeited (in shares) | shares		(365)	(182)
Ending (in shares) | shares		6,516	4,281
Payout multiplier, percentage		100.00%
Option life, share options granted		3.5
Number of share options outstanding, beginning balance		0
Weighted average exercise price of share options outstanding in share-based payment arrangement		$ 6.70	$ 0
Number of share options granted in share-based payment arrangement		0
Assumed on corporate acquisition		$ 9,187,000
Number of share options forfeited in share-based payment arrangement		(4,322,000)
Number of share options outstanding, ending balance		4,865,000	0
Weighted average exercise price of share options granted in share-based payment arrangement		$ 0
Number of equity instruments assumed		6.63
Weighted Average Exercise Price Of Share Options Outstanding In Share-Based Payment Arrangement, Forfeited		$ 6.57
Weighted average remaining contractual life of outstanding share options		1.21
Number of share options exercisable in share-based payment arrangement		2,967,000
Weighted average exercise price of share options exercisable in share-based payment arrangement		$ 6.73
Interest rate, significant unobservable inputs, assets		2.00%
Expected Volatility, Percentage		$ 0.50
Weighted average cost of capital, significant unobservable inputs, assets		25000.00%
Restricted awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average fair value of share awards		$ 4.04	$ 5.75
Total number of share awards
Beginning (in shares) | shares		2,028	1,508
Granted (in shares) | shares		2,793	1,636
Number Of Equity Instruments Assumed, Corporate Acquisition		$ 302,000
Vested and converted to common shares (in shares) | shares		(1,682)	(959)
Forfeited (in shares) | shares		(198)	(157)
Ending (in shares) | shares		3,243	2,028
Performance awards
Total number of share awards
Beginning (in shares) | shares		2,253	1,737
Granted (in shares) | shares		2,591	1,584
Number Of Equity Instruments Assumed, Corporate Acquisition		$ 257,000
Vested and converted to common shares (in shares) | shares		(1,661)	(1,043)
Forfeited (in shares) | shares		(167)	(25)
Ending (in shares) | shares		3,273	2,253
Minimum
Total number of share awards
Option life, share options granted		800
Maximum
Total number of share awards
Option life, share options granted		2,800
$5.00 - $7.00
Total number of share awards
Weighted average exercise price of share options outstanding in share-based payment arrangement		$ 6.28
Number of share options outstanding, ending balance		3,425,000
Weighted average remaining contractual life of outstanding share options		1.28
Number of share options exercisable in share-based payment arrangement		2,007,000
Weighted average exercise price of share options exercisable in share-based payment arrangement		$ 6.28
$7.01 - $9.00
Total number of share awards
Weighted average exercise price of share options outstanding in share-based payment arrangement		$ 7.68
Number of share options outstanding, ending balance		1,440,000
Weighted average remaining contractual life of outstanding share options		1.04
Number of share options exercisable in share-based payment arrangement		960,000
Weighted average exercise price of share options exercisable in share-based payment arrangement		$ 7.68
Share-based Compensation Award, Tranche One
Total number of share awards
Date of options granted, year one		33.30%
Share-based Compensation Award, Tranche Two
Total number of share awards
Date of options granted, year two		33.30%
Share-based Compensation Award, Tranche Three
Total number of share awards
Date of options granted, year three		33.30%

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Net loss
Profit (loss)	$ (325,309)	$ 87,174
Net income (loss) - diluted	$ (325,309)	$ 87,174
Common shares (000's)
Shares outstanding - basic (in shares)	351,542,000	234,787,000
Dilutive effect of share awards (in shares)	0	2,462,000
Shares outstanding - diluted (in shares)	351,542,000	237,249,000
Net loss per share
Net income (loss) per share - basic (in cad per share)	$ (0.93)	$ 0.37
Net income (loss) per share - diluted (in cad per share)	$ (0.93)	$ 0.37
Antidilutive securities (in shares)	6,500,000	4,900,000

Income Taxes - Provision For In

Income Taxes - Provision For Income Taxes (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net loss before income taxes	$ (427,076)	$ (69,254)
Expected income taxes at the statutory rate of 27.00% (2015 - 26.24%)	$ (115,311)	$ (18,650)
Tax rate	27.00%	26.93%
(Increase) decrease in income tax recovery resulting from:
Share-based compensation	$ 5,185	$ 4,177
Non-taxable portion of foreign exchange (gain) loss	14,467	(11,615)
Effect of change in income tax rates	0	(104)
Effect of rate adjustments for foreign jurisdictions	(22,119)	(42,214)
Effect of U.S. tax reform	0	(91,830)
Effect of change in deferred tax benefit not recognized	14,467	(11,615)
Adjustments and assessments	1,544	15,423
Income tax (recovery) expense	(101,767)	(156,428)
Allowable capital losses	$ 139,000	$ 86,000
Saskatchewan
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Tax rate	12.00%	11.75%
Canada Revenue Agency
(Increase) decrease in income tax recovery resulting from:
Adjustments and assessments		$ 10,600
Decrease in non-capital loss tax pools		$ 39,300

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Income Taxes [Abstract]
Estimated length of notice of objection for tax reassessments	2 years
Accumulated non-capital losses	$ 591

Income Taxes - Continuity of Ne

Income Taxes - Continuity of Net Deferred Income Tax Liability (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Changes in deferred tax liability (asset) [abstract]
Beginning balance	$ (204,698)	$ (375,695)
Recognized in Net Loss	101,732	155,343
Share Issuance Costs	209	0
Increase (decrease) through business combinations, deferred tax liability (asset)	(195,050)
Foreign Currency Translation Adjustment	(13,029)	15,654
Ending balance	(310,836)	(204,698)
Non-capital loss carry-forwards	1,733,800	1,478,500
Petroleum and natural gas properties
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(696,427)	(967,579)
Recognized in Net Loss	(11,639)	221,697
Increase (decrease) through business combinations, deferred tax liability (asset)	(207,337)
Foreign Currency Translation Adjustment	(39,103)	49,455
Ending balance	(954,506)	(696,427)
Financial derivatives
Changes in deferred tax liability (asset) [abstract]
Beginning balance	8,528	7,869
Recognized in Net Loss	(31,512)	659
Increase (decrease) through business combinations, deferred tax liability (asset)	1,498
Ending balance	(21,486)	8,528
Deferred income
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(17,827)	(419)
Recognized in Net Loss	17,827	(17,408)
Ending balance	0	(17,827)
Other
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(5,956)	(5,018)
Recognized in Net Loss	(2,538)	6,076
Share Issuance Costs	209	0
Foreign Currency Translation Adjustment	5,240	(7,014)
Ending balance	(3,045)	(5,956)
Asset retirement obligations
Changes in deferred tax liability (asset) [abstract]
Beginning balance	97,977	93,016
Recognized in Net Loss	62,984	5,925
Increase (decrease) through business combinations, deferred tax liability (asset)	10,789
Foreign Currency Translation Adjustment	609	(964)
Ending balance	172,359	97,977
Non-capital losses
Changes in deferred tax liability (asset) [abstract]
Beginning balance	330,749	404,952
Recognized in Net Loss	48,725	(48,380)
Foreign Currency Translation Adjustment	20,225	(25,823)
Ending balance	399,699	330,749
Finance costs
Changes in deferred tax liability (asset) [abstract]
Beginning balance	78,258	91,484
Recognized in Net Loss	17,885	(13,226)
Ending balance	$ 96,143	$ 78,258

Income Taxes - Domestic and For

Income Taxes - Domestic and Foreign Tax Pools (Details) - CAD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Canadian Tax Pools
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Canadian oil and natural gas property expenditures	$ 529,044	$ 308,366
Canadian development expenditures	765,289	176,188
Canadian exploration expenditures	8,875	1,343
Undepreciated capital costs	502,320	228,739
Non-capital losses	593,251	337,808
Financing costs and other	33,866	46,986
Tax pools, total amount	2,432,645	1,099,430
U.S. Tax Pools
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Non-capital losses	1,140,579	1,140,673
Depletion	180,367	183,406
Intangible drilling costs	133,345	204,857
Tangibles	69,138	108,631
Other	407,654	303,357
Tax pools, total amount	$ 1,931,083	$ 1,940,924

Financing and Interest (Details

Financing and Interest (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Analysis of income and expense [abstract]
Interest on bank loan	$ 15,637	$ 11,439
Interest on long-term notes	88,681	89,043
Non-cash financing	3,854	4,474
Accretion on asset retirement obligations	10,914	8,682
Financing and interest	$ 119,086	$ 113,638

Foreign Exchange (Details)

Foreign Exchange (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Effects Of Changes In Foreign Exchange Rates [Abstract]
Unrealized foreign exchange loss (gain)	$ 106,143	$ (86,649)
Realized foreign exchange loss (gain)	2,151	(411)
Foreign exchange loss (gain)	$ 108,294	$ (87,060)

Financial Instruments and Ris_3

Financial Instruments and Risk Management - Carrying Value and Fair Value of Financial Instruments (Details) - CAD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	$ 0	$ (50,095)
Liabilities, at fair value	0	(50,095)
FVTPL | Financial Derivatives | Level 2
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	0	(50,095)
Liabilities, at fair value	0	(50,095)
Financial liabilities at amortized cost
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(2,362,054)	(1,830,864)
Liabilities, at fair value	(2,272,771)	(1,788,820)
Financial liabilities at amortized cost | Trade and other payables | 0
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(258,114)	(144,542)
Liabilities, at fair value	(258,114)	(144,542)
Financial liabilities at amortized cost | Bank loan | 0
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(520,700)	(212,138)
Liabilities, at fair value	(522,294)	(213,376)
Financial liabilities at amortized cost | Long-term notes | 0
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(1,583,240)	(1,474,184)
Liabilities, at fair value	(1,492,363)	(1,430,902)
FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	79,582	18,510
Financial assets, at fair value	79,582	18,510
FVTPL | Level 2
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	79,582	18,510
Financial assets, at fair value	79,582	18,510
Financial assets at amortized cost
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	111,564	112,844
Financial assets, at fair value	111,564	112,844
Financial assets at amortized cost | 0
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	111,564	112,844
Financial assets, at fair value	$ 111,564	$ 112,844

Financial Instruments and Ris_4

Financial Instruments and Risk Management - Foreign Currency Risk, Interest Rate Risk, and Commodity Price Risk (Details) $ in Thousands	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Bank loan		$ 520,700,000		$ 212,138,000
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		8,800,000
Currency risk | U.S. dollar denominated, liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
U.S. dollar denominated	$ 963,351		$ 1,008,001
Currency risk | U.S. dollar denominated, assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
U.S. dollar denominated	$ 80,857		$ 479
Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Bank loan		522,294,000
Interest rate risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Effect on net income		$ 3,200,000
Impact of base point change on interest rates	100.00%	100.00%

Financial Instruments and Ris_5

Financial Instruments and Risk Management - Interest Rate Swaps (Details)	12 Months Ended
	Dec. 31, 2018CAD ($)
Disclosure of detailed information about financial instruments [line items]
Total	$ 79,300,000
Current asset	79,300,000
Notional Amount	100,000,000
Fixed Contract Price	0.0202
Impact on net income (loss) from change in basis points	400,000
Interest rate swap contract
Disclosure of detailed information about financial instruments [line items]
Total	300,000
Current asset	300,000
Interest rate swap contract | Interest Rate Swap - Maturity October 2020
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ 300,000
Interest rate risk
Disclosure of detailed information about financial instruments [line items]
Change in basis points	.0100

Financial Instruments and Ris_6

Financial Instruments and Risk Management - Financial Derivative Contracts (Details) $ in Millions	Dec. 31, 2018CAD ($)
Disclosure of detailed information about financial instruments [line items]
Financial derivatives	$ 79.3
Current asset	$ 79.3
Derivative price/unit	10
Oil Fixed Sell Jan 2019 To Dec 2019
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (8)
Volume	2,000
Oil Three Way Option Jan 2019 to Dec 2019 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative financial assets	$ 7
Volume	2,000
Oil Three Way Option Jan 2019 to Dec 2019 - 2
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (4)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 3
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (4.1)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 4
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (4.1)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 5
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (8.3)
Volume	2,000
Oil Three Way Option Jan 2019 to Dec 2019 - 6
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (8.4)
Volume	2,000
Oil Three Way Option Jan 2019 to Dec 2019 - 7
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (9.1)
Volume	2,000
Oil Three Way Option Jan 2019 to Dec 2019 - 8
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (4.3)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 9
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (4.4)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 10
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (4.5)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 11
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (3.1)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 12
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (3.7)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 13
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (4)
Volume	1,000
Oil Three Way Option Jan 2019 to Dec 2019 - 14
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ 0
Oil Basis Swap Mar 2019 To Jun 2019
Disclosure of detailed information about financial instruments [line items]
Volume	2,000
Oil Basis Swap Jul 2019 To Sep 2019
Disclosure of detailed information about financial instruments [line items]
Volume	2,000
Oil Basis Swap Oct 2019 To Dec 2019
Disclosure of detailed information about financial instruments [line items]
Volume	4,000
Oil Basis Swap Apr To Jun 2019
Disclosure of detailed information about financial instruments [line items]
Volume	4,000
Natural Gas Fixed Sell Jan 2019 To Mar 2019, GJ/d
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (0.4)
Volume	5,000
Natural Gas Fixed Sell Jan 201 To Dec 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (0.8)
Volume	5,000
Natural Gas Fixed Sell Jan 2019 To Mar 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (0.8)
Volume	10,000
Natural Gas Fixed Sell Apr 2019 To Jun 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (0.1)
Volume	10,000
Natural Gas Fixed Sell Jul 2019 To Sep 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (0.1)
Volume	10,000
Natural Gas Fixed Sell Oct 2019 To Dec 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Interest rate swap	$ (0.1)
Volume	10,000
Commodity price risk | Oil Price
Disclosure of detailed information about financial instruments [line items]
Potential impact of crude oil price changes	100.00%
Potential impact of natural gas price changes	$ (2.9)
Commodity price risk | Natural Gas Price
Disclosure of detailed information about financial instruments [line items]
Potential impact of crude oil price changes	25.00%
Potential impact of natural gas price changes	$ (1.5)
Price One
Disclosure of detailed information about financial instruments [line items]
Derivative financial assets	$ 0
Derivative price/unit	70
Price One | Oil Fixed Sell Jan 2019 To Dec 2019
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	62.85
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	70
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	72.60
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 3
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	72.50
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 4
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	73
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 5
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	73
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 6
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	74
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 7
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	75
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 8
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	75
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 9
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	76
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 10
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	78
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 11
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	75.50
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 12
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	77.55
Price One | Oil Three Way Option Jan 2019 to Dec 2019 - 13
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	83
Price One | Oil Basis Swap Mar 2019 To Jun 2019
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	14.75
Price One | Oil Basis Swap Jul 2019 To Sep 2019
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	13.65
Price One | Oil Basis Swap Oct 2019 To Dec 2019
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	17.38
Price One | Oil Basis Swap Apr To Jun 2019
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	20.88
Price One | Natural Gas Fixed Sell Jan 2019 To Mar 2019, GJ/d
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.25
Price One | Natural Gas Fixed Sell Jan 201 To Dec 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3.15
Price One | Natural Gas Fixed Sell Jan 2019 To Mar 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3.82
Price One | Natural Gas Fixed Sell Apr 2019 To Jun 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.79
Price One | Natural Gas Fixed Sell Jul 2019 To Sep 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.79
Price One | Natural Gas Fixed Sell Oct 2019 To Dec 2019, MMBTU/d
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.88
Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative financial assets	$ 0
Derivative price/unit	60
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	65
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 3
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 4
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 5
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	67
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 6
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	68
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 7
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	61.70
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 8
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	69.90
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 9
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	71
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 10
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	73
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 11
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	65.50
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 12
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	70
Price Two | Oil Three Way Option Jan 2019 to Dec 2019 - 13
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	73
Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative financial assets	$ 0
Derivative price/unit	50
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 1
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 2
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	55
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 3
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	56
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 4
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	56
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 5
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	57
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 6
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	58
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 7
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	49
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 8
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 9
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	61
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 10
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	63
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 11
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	55.50
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 12
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Price Three | Oil Three Way Option Jan 2019 to Dec 2019 - 13
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	63

Financial Instruments and Ris_7

Financial Instruments and Risk Management - Financial Derivatives Marked-To-Market (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Financial Instruments [Abstract]
Realized financial derivatives loss (gain)	$ 73,165	$ (7,616)
Unrealized financial derivatives loss (gain)	(116,715)	2,439
Financial derivatives gain	$ (43,550)	$ (5,177)

Financial Instruments and Ris_8

Financial Instruments and Risk Management - Physical Delivery Contracts (Details)	Dec. 31, 2018bbl / d
Raw Bitumen Physical Delivery Contract Jan 2019 to Oct 2019
Disclosure Of Detailed Information About Non-financial Instruments [Line Items]
Volume	1,000
Raw Bitumen Physical Delivery Contract Jan 2019 to Dec 2019
Disclosure Of Detailed Information About Non-financial Instruments [Line Items]
Volume	5,000
Raw Bitumen Physical Delivery Contract Jan 2019 to Dec 2020
Disclosure Of Detailed Information About Non-financial Instruments [Line Items]
Volume	5,000

Financial Instruments and Ris_9

Financial Instruments and Risk Management - Liquidity Risk (Details) - CAD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables	$ 258,114	$ 144,542
Bank loan	520,700	212,138
Long-term notes	1,583,240	1,474,184
Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Available undrawn credit facilities	547,700	$ 494,600
Trade and other payables	258,114
Bank loan	522,294
Long-term notes	1,596,323
Interest payable	334,028
Financial liabilities	2,710,759
Less than 1 year | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables	258,114
Bank loan	0
Long-term notes	0
Interest payable	92,367
Financial liabilities	350,481
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	522,294
Long-term notes	750,503
Interest payable	156,525
Financial liabilities	1,429,322
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	300,000
Interest payable	72,350
Financial liabilities	372,350
Beyond 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	545,820
Interest payable	12,786
Financial liabilities	$ 558,606

Financial Instruments and Ri_10

Financial Instruments and Risk Management - Credit Risk (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of financial assets [line items]
Current trade receivables	$ 111,564	$ 112,844
Financial assets neither past due nor impaired | Current (less than 30 days)
Disclosure of financial assets [line items]
Current trade receivables	104,099	107,796
Financial assets neither past due nor impaired | 31-60 days
Disclosure of financial assets [line items]
Current trade receivables	3,037	2,939
Financial assets neither past due nor impaired | 61-90 days
Disclosure of financial assets [line items]
Current trade receivables	1,842	1,427
Financial assets past due but not impaired | Past due (more than 90 days)
Disclosure of financial assets [line items]
Current trade receivables	$ 2,586	682
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	$ 77,400	91,600
Trade receivables
Disclosure of financial assets [line items]
Allowance for doubtful accounts	$ 1,900	$ 1,600
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, 2018	Dec. 31, 2017
Additional information [abstract]
Trade and other receivables	$ 1,280	$ (673)
Trade and other payables	113,572	31,569
Non-cash working capital acquired (note 4)	(46,773)	(4,357)
Trade and other receivables/payables	68,079	26,539
Changes in non-cash working capital related to:
Operating activities	39,448	(8,962)
Investing activities	32,435	33,683
Foreign currency translation on non-cash working capital	(3,804)	1,818
Changes in non-cash working capital	$ 68,079	$ 26,539

Supplemental Information - Oner

Supplemental Information - Onerous Contracts (Details) - Onerous contracts - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in other provisions [Abstract]
Balance, beginning of year	$ 2,574	$ 9,504
Liabilities settled	(588)	(6,746)
Foreign currency translation	0	(184)
Balance, end of the year	$ 1,986	$ 2,574

Supplemental Information - Empl

Supplemental Information - Employee Compensation Costs (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	$ 47,103	$ 49,510
Operating
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	12,140	13,424
General and administrative
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	$ 34,963	$ 36,086

Commitments and Contingencies_2

Commitments and Contingencies (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Operating leases	$ 22,745
Processing agreements	47,717
Transportation agreements	112,002
Total	182,464
Operating lease and sublease payments recognized as expense	6,300	$ 6,500
Less than 1 year
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Operating leases	7,484
Processing agreements	10,926
Transportation agreements	14,398
Total	32,808
1-3 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Operating leases	12,492
Processing agreements	15,526
Transportation agreements	42,054
Total	70,072
3-5 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Operating leases	2,753
Processing agreements	9,039
Transportation agreements	19,821
Total	31,613
Beyond 5 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Operating leases	16
Processing agreements	12,226
Transportation agreements	35,729
Total	$ 47,971

Related Parties (Details)

Related Parties (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Related Party [Abstract]
Short-term employee benefits	$ 8,703	$ 7,840
Share-based compensation	10,985	3,569
Termination payments	3,025	275
Total compensation for key management personnel	$ 22,713	$ 11,684

Capital Disclosures - Capital M

Capital Disclosures - Capital Management Information (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Funds From Operations [Abstract]
Cash flow from operating activities	$ 485,322	$ 325,208
Change in non-cash working capital	(39,448)	8,962
Asset retirement obligations settled	14,035	13,471
Acquisition-related costs recognised as expense for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination	13,074	0
Adjusted funds flow	472,983	347,641
Net Debt [Abstract]
Bank loan - principal	520,700	212,138
Long-term notes - principal	1,583,240	1,474,184
Trade and other payables	258,114	144,542
Trade and other receivables	(111,564)	(112,844)
Net debt	2,265,167	1,734,284
Liquidity risk
Net Debt [Abstract]
Trade and other payables	258,114
Undrawn Credit Facilities and Net Debt Ratio [Abstract]
Available undrawn credit facilities	547,700	494,600
Cost
Net Debt [Abstract]
Bank loan - principal	522,294	213,376
Long-term notes - principal	$ 1,596,323	$ 1,489,210