Baytex Energy (BTE) 6-K 24 Feb 22 2021 FY Management's Annual Report on Internal Control Over Financial Reporting Financial data

Cover

Cover	12 Months Ended
	Dec. 31, 2021
Document Information [Line Items]
Document Type	6-K
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2021
Entity Registrant Name	BAYTEX ENERGY CORP.
Entity Central Index Key	0001279495
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Statements of Fina

Consolidated Statements of Financial Position - CAD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets
Trade and other receivables	$ 173,409	$ 107,477
Financial derivatives	8,654	5,057
Total current assets	182,063	112,534
Non-current assets
Exploration and evaluation assets	172,824	191,865
Oil and gas properties	4,464,371	3,077,548
Other plant and equipment	7,121	7,996
Lease assets	8,264	11,098
Deferred income tax asset	0	7,055
Total assets	4,834,643	3,408,096
Current liabilities
Trade and other payables	190,692	155,955
Current derivative financial liabilities	134,020	26,792
Less current portion of lease obligations	2,938	4,289
Less current portion of asset retirement obligations	11,080	11,820
Total current liabilities	338,730	198,856
Non-current liabilities
Credit facilities	505,171	649,221
Long-term notes	874,527	1,132,868
Lease obligations	4,827	6,787
Asset retirement obligations	732,603	748,563
Deferred income tax liability	167,456	93,588
Total Liabilities	2,623,314	2,829,883
SHAREHOLDERS’ EQUITY
Shareholders' capital	5,736,593	5,729,418
Contributed surplus	13,559	14,345
Accumulated other comprehensive income	632,103	618,976
Deficit	(4,170,926)	(5,784,526)
Total shareholders' equity	2,211,329	578,213
Total liabilities and shareholders' equity	$ 4,834,643	$ 3,408,096

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - CAD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenue, net of royalties
Petroleum and natural gas sales	$ 1,868,195	$ 975,477
Royalties	(339,156)	(163,735)
Revenue, net of royalties	1,529,039	811,742
Expenses
Operating	343,002	331,345
Transportation	32,261	28,437
Blending and other	85,689	48,381
General and administrative	40,804	34,268
Exploration and evaluation	15,212	14,011
Depletion and depreciation	464,580	486,380
Impairment (impairment reversal)	(1,542,414)	2,360,220
Share-based compensation	11,130	9,469
Financing and interest	111,159	125,441
Financial derivatives loss (gain)	287,872	(29,336)
Foreign exchange (gain) loss	(2,868)	8,688
Gain on dispositions	(9,666)	(901)
Other income	(2,562)	(5,304)
Total expenses	(165,801)	3,411,099
Net income (loss) before income taxes	1,694,840	(2,599,357)
Income tax (recovery) expense
Current income tax expense	1,272	574
Deferred income tax expense (recovery)	79,968	(160,967)
Income tax expense (recovery)	81,240	(160,393)
Net income (loss)	1,613,600	(2,438,964)
Other comprehensive income (loss)
Foreign currency translation adjustment	13,127	62,752
Comprehensive income (loss)	$ 1,626,727	$ (2,376,212)
Net income (loss) per common share
Basic (in cad per share)	$ 2.86	$ (4.35)
Diluted (in cad per share)	$ 2.82	$ (4.35)
Weighted average common shares
Basic (in shares)	563,674	560,657
Diluted (in shares)	571,610	560,657

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, 2019	$ 2,947,209	$ 5,718,835	$ 17,712	$ 556,224	$ (3,345,562)
Vesting of share awards	0	10,583	(10,583)
Share-based compensation	7,216	10,583	7,216
Comprehensive income (loss)	(2,376,212)			62,752	(2,438,964)
Ending balance at Dec. 31, 2020	578,213	5,729,418	14,345	618,976	(5,784,526)
Vesting of share awards	0	7,175	(7,175)
Share-based compensation	6,389	7,175	6,389
Comprehensive income (loss)	1,626,727			13,127	1,613,600
Ending balance at Dec. 31, 2021	$ 2,211,329	$ 5,736,593	$ 13,559	$ 632,103	$ (4,170,926)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Operating activities
Net income (loss)	$ 1,613,600	$ (2,438,964)
Adjustments for:
Share-based compensation	6,389	7,216
Unrealized foreign exchange (gain) loss	(1,905)	9,232
Exploration and evaluation	15,212	14,011
Depletion and depreciation		486,380
Impairment (impairment reversal)	(1,542,414)	2,360,220
Non-cash financing, accretion and early redemption expense	19,090	18,907
Non-cash other income	(2,857)	(2,128)
Unrealized financial derivatives loss	103,631	18,500
Gain on dispositions	(9,666)	(901)
Deferred income tax expense (recovery)	79,968	(160,967)
Asset retirement obligations settled	(6,662)	(7,168)
Change in non-cash working capital	(26,582)	48,758
Cash flows from operating activities	712,384	353,096
Financing activities
(Decrease) increase in credit facilities	(145,321)	143,248
Payments on lease obligations	(4,334)	(5,925)
Net proceeds from issuance of long-term notes	0	652,150
Redemption of long-term notes	(251,969)	(833,672)
Cash flows used in financing activities	(401,624)	(44,199)
Investing activities
Additions to exploration and evaluation assets	(3,298)	(4,490)
Additions to oil and gas properties	(310,005)	(275,850)
Additions to other plant and equipment	(907)	(2,280)
Property acquisitions	(1,557)	0
Proceeds from dispositions	7,804	182
Change in non-cash working capital	(2,797)	(32,031)
Cash flows used in investing activities	(310,760)	(314,469)
Change in cash	0	(5,572)
Cash, beginning of year	0	5,572
Cash, end of year	0	0
Supplementary information
Interest paid	93,114	102,358
Income taxes paid	$ 253	$ 1,155

Reporting Entity

Reporting Entity	12 Months Ended
	Dec. 31, 2021
Corporate Information And Statement Of IFRS Compliance [Abstract]
Reporting Entity	REPORTING ENTITYBaytex Energy Corp. (the “Company” or “Baytex”) is an energy company engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and in Texas, United States. The Company’s common shares are traded on the Toronto 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, 2021
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 February 24, 2022. 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 functional 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. Current Environment and Estimation Uncertainty Management makes judgements and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities. During the year ended December 31, 2021, the global economy continued to show signs of recovery from the impacts of the COVID-19 pandemic. Global spot prices for crude oil have recovered and now exceed pre-pandemic levels as optimism for demand recovery improves with limited production growth from independent producers and ongoing OPEC+ production curtailments. While we have benefited from these improvements in crude oil prices there is a degree of uncertainty related to COVID-19 that has been considered in our estimates for the period ended December 31, 2021. Environmental Reporting Regulations Environmental reporting for public enterprises continues to evolve and we may be subject to additional future disclosure requirements. The International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Securities Administrators have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. We continue to monitor developments on these reporting requirements and have not yet quantified the cost to comply with these regulations. Measurement Uncertainty and Judgments The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available, including considerations related to environmental regulation and related matters, to the Company at the time of financial statement preparation. Actual results can differ from those estimates as the effect of future events cannot be determined with certainty. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below. Reserves The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion, evaluating the recoverability of deferred income tax assets and in the determination of fair value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by independent reserves evaluators and represent the estimated recoverable quantities of oil, natural gas and NGL and the related net cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the Canadian Oil and Gas Evaluation Handbook. Estimates of economically recoverable oil, natural gas and NGL and their future net cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forward price forecasts, production rates, ultimate reserve recovery, timing and amount of capital expenditures, production costs, marketability of oil and natural gas, royalty rates and other geological, economic and technical factors could have a significant impact on reported reserves. Changes in the Company's reserves estimates can have a significant impact on the carrying values of the Company's oil and gas properties, the calculation of depletion, the valuation of deferred income tax assets, the timing of cash flows for asset retirement obligations, asset impairments and estimates of fair value determined in accounting for business combinations. Cash-generating Units ("CGUs") The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash flows that are largely independent of the cash flows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk. Identification of Impairment and Impairment Reversal Indicators Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. The assessment for each CGU considers significant changes in reservoir performance including forecasted production volumes, forecasted royalty, operating, capital and abandonment and reclamation costs, forecasted oil and gas prices and the resulting cash flows from proved plus probable oil and gas reserves. Measurement of Recoverable Amount If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves, the discount rate used to present value future cash flows and assumptions regarding the timing and amount of capital expenditures and future abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets. Exploration and Evaluation ("E&E") Assets Costs associated with acquiring oil and natural gas licenses and exploratory drilling are accumulated as E&E assets pending determination of technical feasibility and commercial viability. The determination of technical feasibility and commercial viability of E&E assets for the purposes of reclassifying such assets to oil and gas properties is subject to management judgment. Management uses the establishment of commercial reserves as the basis for determining technical feasibility and commercial viability. Upon determination of commercial reserves, E&E assets are tested for impairment and reclassified to oil and natural gas properties. 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 Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which 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, 2021
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Significant Accounting Policies	SIGNIFICANT ACCOUNTING POLICIES Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany transactions are eliminated in preparation of the consolidated financial statements. Many of the Company's exploration, development and production activities are conducted through joint arrangements. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by joint arrangements. Business Combinations Business combinations are accounted for using the acquisition method of accounting when the acquired assets meet the definition of a business under IFRS. The cost of an acquisition is measured as cash paid and the fair value of assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair value of the net identifiable assets acquired is recognized as goodwill. If the cost of acquisition is below the fair values of the identifiable net assets acquired, the difference is recognized as a bargain purchase gain in net income or loss. Associated transaction costs are expensed when incurred. Revenue Recognition Revenue from the sale of light oil and condensate, heavy oil, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis when Baytex acts in the capacity of an agent rather than as a principal. The transaction price for variable price contracts in the Canadian and U.S. operating segments is based on a representative commodity price index, and may include adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period. Tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided. E&E 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 commercial 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 are initially recorded at cost and include the costs to acquire, develop, complete geological and geophysical surveys, drill wells, and construct and install infrastructure including 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 economic benefits of the replacement will be realized by the Company in the future. 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 oil and gas properties are depleted on a unit-of-production basis by depletable area over proved plus probable reserves once commercial production has commenced. Future development costs required to bring those reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil equivalent. Impairment and Impairment Reversals 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 or when facts and circumstances suggest that the carrying amount exceeds the recoverable amount. When reviewing for indicators of impairment or impairment reversal, and testing for impairment or impairment reversal when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows include CGU production volumes, royalty obligations, operating costs, capital costs, forecast commodity prices, along with inflation and discount rates used to estimate present value. FVLCD is determined as the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction between willing parties. In determining FVLCD, recent market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a discount rate that reflects current market assessments of the time value of money. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment reduces the carrying amount of any goodwill allocated to the CGU first, with any remaining impairment being allocated to the individual assets in the CGU on a pro-rata basis. Impairments may be reversed for all CGUs and individual assets, other than goodwill, when there is indication that a previously recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. An impairment may be reversed only to the extent that the asset’s revised carrying amount does not exceed the carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized. Impairment recognized in relation to goodwill is not reversed for subsequent increases in its recoverable amount. Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal occurs. 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, discounted 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. Management judgement is required in the designation of a subsidiary's functional currency which is 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 during the 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 assets are initially classified into three categories: 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. 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 Credit facilities 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. Debt issuance costs related to the amendment of our credit facilities or the issuance of long term notes are capitalized and amortized as financing costs over the term of the credit facilities or long term notes. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract. The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The risk management policy permits the use of certain derivative financial instruments, including swaps and collars, to manage these fluctuations. All transactions of this nature entered into by the Company are related to underlying financial instruments or future petroleum and natural gas production. These instruments are classified as FVTPL. The Company does not use financial derivatives for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments by recording an asset or liability on the statements of financial position and recognizing changes in the fair value of the instrument in the statements of income or loss for the current period. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or loss when incurred. The Company has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are recognized in revenue in the period the product is delivered to the sales point. Impairment of financial assets is determined by calculating the expected credit loss ("ECL"). The Company measures an ECL allowance for trade and other receivables. The Company determines the ECL which is the probability of default events related to the financial asset by using historical realized bad debts and forward looking information. The carrying amounts of financial assets are reduced by the amount of the ECL through an allowance account and losses are recognized in the statement of income or loss. Fair Value of Financial Instruments Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments: • Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. • Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. • Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Income Taxes Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized directly in equity, in which case the current and deferred taxes are also recognized directly in equity. Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes the financial statement impact of a tax filing position when it is probable that the position will be sustained upon audit. The liability is measured based on an assessment of possible outcomes and their associated probabilities. The Company follows the 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. Share Awards vest in equal tranches on the first, second and third anniversaries of the grant date. 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, with a corresponding increase to contributed surplus. The payout multiplier is dependent on the performance of the Company relative to predefined 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 has a cash-settled incentive award plan (the "Incentive Award Plan") pursuant to which incentive awards may be granted to officers and employees of the Company and its subsidiaries. Each incentive award entitles the holder to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables.

Segmented Financial Information

Segmented Financial Information	12 Months Ended
	Dec. 31, 2021
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 2021 2020 2021 2020 2021 2020 2021 2020 Revenue, net of royalties Petroleum and natural gas sales $ 1,128,137 $ 571,741 $ 740,058 $ 403,736 $ — $ — $ 1,868,195 $ 975,477 Royalties (121,306) (46,064) (217,850) (117,671) — — (339,156) (163,735) 1,006,831 525,677 522,208 286,065 — — 1,529,039 811,742 Expenses Operating 257,658 247,050 85,344 84,295 — — 343,002 331,345 Transportation 32,261 28,437 — — — — 32,261 28,437 Blending and other 85,689 48,381 — — — — 85,689 48,381 General and administrative — — — — 40,804 34,268 40,804 34,268 Exploration and evaluation 15,212 14,011 — — — — 15,212 14,011 Depletion and depreciation 303,135 309,420 155,806 169,439 5,639 7,521 464,580 486,380 Impairment (reversal) loss (1,100,000) 1,737,000 (442,414) 623,220 — — (1,542,414) 2,360,220 Share-based compensation — — — — 11,130 9,469 11,130 9,469 Financing and interest — — — — 111,159 125,441 111,159 125,441 Financial derivatives loss (gain) — — — — 287,872 (29,336) 287,872 (29,336) Foreign exchange (gain) loss — — — — (2,868) 8,688 (2,868) 8,688 (Gain) loss on dispositions (9,856) (901) 190 — — — (9,666) (901) Other (income) expense (2,857) (2,128) — — 295 (3,176) (2,562) (5,304) (418,758) 2,381,270 (201,074) 876,954 454,031 152,875 (165,801) 3,411,099 Net income (loss) before income taxes 1,425,589 (1,855,593) 723,282 (590,889) (454,031) (152,875) 1,694,840 (2,599,357) Income tax expense (recovery) Current income tax (recovery) expense (548) 469 1,820 105 — — 1,272 574 Deferred income tax expense (recovery) 86,928 (77,201) 72,913 (57,199) (79,873) (26,567) 79,968 (160,967) 86,380 (76,732) 74,733 (57,094) (79,873) (26,567) 81,240 (160,393) Net income (loss) $ 1,339,209 $ (1,778,861) $ 648,549 $ (533,795) $ (374,158) $ (126,308) $ 1,613,600 $ (2,438,964) Additions to exploration and evaluation assets 3,298 4,490 — — — — 3,298 4,490 Additions to oil and gas properties 204,912 170,462 105,093 105,388 — — 310,005 275,850 Property acquisitions 1,557 — — — — — 1,557 — Proceeds from dispositions (7,211) (182) (593) — — — (7,804) (182) As at December 31, 2021 December 31, 2020 Canadian assets $ 2,658,281 $ 1,646,412 U.S. assets 2,152,323 1,737,533 Corporate assets 24,039 24,151 Total consolidated assets $ 4,834,643 $ 3,408,096

Exploration and Evaluation Asse

Exploration and Evaluation Assets	12 Months Ended
	Dec. 31, 2021
Exploration For And Evaluation Of Mineral Resources [Abstract]
Exploration and Evaluation Assets	EXPLORATION AND EVALUATION ASSETS December 31, 2021 December 31, 2020 Balance, beginning of year $ 191,865 $ 320,210 Capital expenditures 3,298 4,490 Property acquisitions 1,100 — Divestitures (166) — Property swaps 408 468 Impairment — (113,058) Exploration and evaluation expense (1) (15,212) (14,011) Transfers to oil and gas properties (note 6) (7,727) (8,585) Foreign currency translation (742) 2,351 Balance, end of year $ 172,824 $ 191,865 (1) Exploration and evaluation expense balance consists of land expiries as at December 31, 2021. At December 31, 2021, there were no indicators of impairment or impairment reversal for exploration and evaluation assets in any of the Company's CGUs. At March 31, 2020, the Company identified indicators of impairment for the exploration and evaluation assets within each of its six CGUs. The estimated recoverable amount was below the carrying value of the exploration and evaluation assets in the Conventional, Peace River, Lloydminster, Viking and Eagle Ford CGUs and an impairment loss of $127.9 million was recorded at March 31, 2020. The recoverable amount of each CGU was based on its "FVLCD" and was estimated with reference to arm's length transactions in comparable locations and the discounted cash flows associated with the Company's future development plans. The following table indicates the impairment loss booked for each CGU at March 31, 2020. Impairment at Conventional CGU $ 4,000 Peace River CGU 20,000 Lloydminster CGU 42,000 Viking CGU 13,000 Eagle Ford CGU 48,861 $ 127,861 At December 31, 2020, the Company estimated the recoverable amount of the exploration and evaluation assets within each of its six CGUs due to the ongoing volatility in future oil and natural gas prices. The recoverable amount supported the carrying amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and no impairment loss or impairment reversal was recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded their carrying amounts which resulted in an impairment reversal of $14.8 million at December 31, 2020. The recoverable amount of each CGU was based on its FVLCD and was estimated with reference to arm's length transaction in comparable locations and the discounted cash flows associated with the Company's future development plans. The following table indicates the impairment reversal booked for the Viking and Eagle Ford CGUs at December 31, 2020. Impairment reversal at December 31, 2020 Viking CGU $ 2,000 Eagle Ford CGU 12,803 $ 14,803

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2021
Property, plant and equipment [abstract]
Oil and gas properties	OIL AND GAS PROPERTIES Cost Accumulated Net book value Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Capital expenditures 275,850 — 275,850 Transfers from exploration and evaluation assets (note 5) 8,585 — 8,585 Change in asset retirement obligations (note 9) 94,994 — 94,994 Property swaps (1,190) 178 (1,012) Impairment — (2,247,162) (2,247,162) Foreign currency translation (82,860) 120,123 37,263 Depletion — (478,859) (478,859) Balance, December 31, 2020 $ 11,423,676 $ (8,346,128) $ 3,077,548 Capital expenditures 310,005 — 310,005 Property acquisitions 274 — 274 Divestitures (37,835) 32,844 (4,991) Property swaps (26,131) 25,900 (231) Transfers from exploration and evaluation assets (note 5) 7,727 — 7,727 Change in asset retirement obligations (note 9) (12,222) — (12,222) Impairment reversal — 1,542,414 1,542,414 Foreign currency translation (31,977) 34,765 2,788 Depletion — (458,941) (458,941) Balance, December 31, 2021 $ 11,633,517 $ (7,169,146) $ 4,464,371 Baytex recorded total impairment reversals related to oil and gas properties of $1.5 billion for the year ended December 31, 2021 and impairment losses related to oil and gas properties of $2.2 billion for the year ended December 31, 2020. 2021 Impairment Reversals At December 31, 2021, we identified indicators of impairment reversal for oil and gas properties in five CGUs due to the increase in forecasted commodity prices in addition to changes in proved plus probable reserves. The recoverable amount for three CGUs exceeded their carrying amounts which resulted in an impairment reversal of $416 million recorded at December 31, 2021. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2021. The after-tax discount rates applied to the cash flows were between 12% and 19%. At December 31, 2021, the recoverable amount of the five CGUs tested were calculated using the following benchmark reference prices for the years 2022 to 2031 adjusted for commodity differentials specific to the CGU. The prices and costs subsequent to 2031 have been adjusted for inflation at an annual rate of 2.0%. 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 WTI crude oil (US$/bbl) 72.83 68.78 66.76 68.09 69.45 70.84 72.26 73.70 75.18 76.68 WCS heavy oil ($/bbl) 74.42 69.17 66.54 67.87 69.23 70.61 72.02 73.46 74.69 76.19 LLS crude oil (US$/bbl) 74.33 70.28 68.27 69.62 71.01 72.41 73.85 75.32 76.82 78.35 Edmonton par oil ($/bbl) 86.82 80.73 78.01 79.57 81.16 82.78 84.44 86.13 87.85 89.61 Henry Hub gas (US$/mmbtu) 3.85 3.44 3.17 3.24 3.30 3.37 3.44 3.50 3.58 3.65 AECO gas ($/mmbtu) 3.56 3.21 3.05 3.11 3.17 3.23 3.30 3.36 3.43 3.50 Exchange rate (CAD/USD) 1.26 1.26 1.26 1.26 1.26 1.26 1.26 1.26 1.26 1.26 The following table summarizes the recoverable amount and impairment reversal at December 31, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the five CGUs with respect to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 77,846 $ 19,000 $ — $ 3,000 $ 8,000 Peace River CGU 489,274 251,000 8,500 53,000 3,500 Lloydminster CGU 479,411 146,000 12,500 52,000 — Viking CGU 1,320,094 — 38,000 85,500 4,500 Eagle Ford CGU 2,008,478 — 97,200 138,800 31,300 $ 4,375,103 $ 416,000 $ 156,200 $ 332,300 $ 47,300 At June 30, 2021, we identified indicators of impairment reversal for oil and gas properties in each of our six CGUs due to the increase in forecasted commodity prices. The recoverable amount for each of our six CGUs exceeded their carrying amounts which resulted in an impairment reversal of $1.1 billion recorded at June 30, 2021. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020 and was adjusted by management for operations between December 31, 2020 and June 30, 2021. The after-tax discount rates applied to the cash flows were between 10% and 16%. At June 30, 2021, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2.0%. 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 WTI crude oil (US$/bbl) 71.33 67.20 63.95 63.23 64.50 65.79 67.10 68.44 69.81 71.21 WCS heavy oil ($/bbl) 72.22 66.84 61.73 60.70 61.91 63.15 64.42 65.70 67.02 68.36 LLS crude oil (US$/bbl) 72.17 68.53 65.80 65.10 66.39 67.71 69.05 70.42 71.82 73.26 Edmonton par oil ($/bbl) 83.20 78.27 74.06 73.05 74.51 76.00 77.52 79.07 80.66 82.27 Henry Hub gas (US$/mmbtu) 3.42 3.19 2.92 2.96 3.02 3.08 3.14 3.21 3.27 3.34 AECO gas ($/mmbtu) 3.46 3.13 2.72 2.71 2.76 2.82 2.88 2.94 2.99 3.05 Exchange rate (CAD/USD) 1.24 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 The following table summarizes the recoverable amount and impairment reversal at June 30, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 57,891 $ 15,000 $ 1,000 $ 1,000 $ 8,000 Peace River CGU 238,714 154,000 4,000 40,000 2,500 Lloydminster CGU 340,730 154,000 12,500 52,000 — Duvernay CGU (1) 115,157 5,000 45,000 44,500 44,500 Viking CGU 1,338,985 356,000 47,000 89,500 4,500 Eagle Ford CGU 2,015,118 442,415 109,400 103,900 24,400 $ 4,106,595 $ 1,126,415 $ 218,900 $ 330,900 $ 83,900 (1) The impairment reversal for the Duvernay CGU was limited to total accumulated impairments less subsequent depletion of $5.0 million. 2020 Impairments At December 31, 2020, the Company estimated the recoverable amount of each of its six CGUs due to the volatility in commodity prices during the year and a reduction in future development costs per well for the Viking and Eagle Ford CGUs. The recoverable amount supported the carrying amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and no impairment or impairment reversal was recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded their carrying amounts which resulted in an impairment reversal of $341.3 million recorded at December 31, 2020. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020. The after-tax discount rates applied to the cash flows were between 10% and 17%. At December 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2%. 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 WTI crude oil (US$/bbl) 47.17 50.17 53.17 54.97 56.07 57.19 58.34 59.50 60.69 61.91 WCS heavy oil ($/bbl) 44.63 48.18 52.10 54.10 55.19 56.29 57.42 58.57 59.74 60.93 LLS crude oil (US$/bbl) 49.50 52.85 55.87 57.69 58.82 59.97 61.15 62.34 63.56 64.83 Edmonton par oil ($/bbl) 55.76 59.89 63.48 65.76 67.13 68.53 69.95 71.40 72.88 74.34 Henry Hub gas (US$/mmbtu) 2.83 2.87 2.90 2.96 3.02 3.08 3.14 3.20 3.26 3.33 AECO gas ($/mmbtu) 2.78 2.70 2.61 2.65 2.70 2.76 2.81 2.87 2.92 2.98 Exchange rate (CAD/USD) 1.30 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 54,265 $ — $ 1,000 $ 3,000 $ 9,000 Peace River CGU 104,225 — 1,000 49,500 3,000 Lloydminster CGU 212,979 — 7,000 57,500 500 Duvernay CGU 70,491 — 5,500 12,000 1,500 Viking CGU 1,026,026 116,000 34,500 106,500 5,000 Eagle Ford CGU 1,609,562 225,326 91,600 157,500 38,400 $ 3,077,548 $ 341,326 $ 140,600 $ 386,000 $ 57,400 At March 31, 2020, the Company identified indicators of impairment for each of its six CGUs due to a significant decline in forecasted commodity prices. The recoverable amount was not sufficient to support the carrying amount which resulted in an impairment of $2.6 billion recorded at March 31, 2020. The recoverable amount of each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2019 and was adjusted for operations between December 31, 2019 and March 31, 2020. The after-tax discount rates applied to the cash flows were between 8% and 14%. At March 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2%. 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 WTI crude oil (US$/bbl) 29.17 40.45 49.17 53.28 55.66 56.87 58.01 59.17 60.35 61.56 WCS heavy oil ($/bbl) 19.21 34.65 46.34 51.25 54.28 55.72 56.96 58.22 59.51 60.82 LLS crude oil (US$/bbl) 32.17 43.80 52.55 56.68 59.10 60.35 61.52 62.72 63.94 65.19 Edmonton par oil ($/bbl) 29.22 46.85 59.27 65.02 68.43 69.81 71.24 72.70 74.19 75.71 Henry Hub gas (US$/mmbtu) 2.10 2.58 2.79 2.86 2.93 3.00 3.07 3.13 3.19 3.25 AECO gas ($/mmbtu) 1.74 2.20 2.38 2.45 2.53 2.60 2.66 2.72 2.79 2.85 Exchange rate (CAD/USD) 1.41 1.37 1.34 1.34 1.34 1.33 1.33 1.33 1.33 1.33 The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 37,444 $ 41,000 $ 3,000 $ 3,500 $ 8,500 Peace River CGU 109,631 345,000 9,500 53,500 3,000 Lloydminster CGU 227,967 470,000 25,000 69,500 — Duvernay CGU 61,197 5,000 5,500 9,500 1,500 Viking CGU 962,134 915,000 57,000 123,000 4,000 Eagle Ford CGU 1,576,423 812,488 120,750 141,500 32,000 $ 2,974,796 $ 2,588,488 $ 220,750 $ 400,500 $ 49,000

Credit Facilities

Credit Facilities	12 Months Ended
	Dec. 31, 2021
Financial Instruments [Abstract]
Credit Facilities	CREDIT FACILITIES December 31, 2021 December 31, 2020 Credit facilities - U.S. dollar denominated (1) $ 156,332 $ 140,815 Credit facilities - Canadian dollar denominated 350,182 510,358 Credit facilities - principal (2) $ 506,514 $ 651,173 Unamortized debt issuance costs (1,343) (1,952) Credit facilities $ 505,171 $ 649,221 (1) U.S. dollar denominated credit facilities balance was US$123.5 million as at December 31, 2021 (December 31, 2020 - US$110.4 million). (2) The decrease in the principal amount of the credit facilities outstanding from December 31, 2020 to December 31, 2021 is the result of net repayments of $145.3 million and an increase in the reported amount of U.S. denominated debt of $0.7 million due to foreign exchange. Baytex has US$575 million of revolving credit facilities (the "Revolving Facilities") and a $300 million non-revolving secured term loan (the "Term Loan") (collectively the "Credit Facilities"). The Credit Facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The $300 million Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership. The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon Baytex's request. Advances (including letters of credit) under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates ("LIBOR"), plus applicable margins. The LIBOR benchmark transition began on December 31, 2021. Certain tenors of the U.S. dollar LIBOR benchmark are no longer published as of December 31, 2021 while some tenors will continue to be published through mid-2023. We expect the U.S. dollar LIBOR benchmarks to be replaced with an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material impact to Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate. The weighted average interest rate on the Credit Facilities was 2.1% for the year ended December 31, 2021 (2.4% for the year ended December 31, 2020). At December 31, 2021, Baytex had $15.0 million of outstanding letters of credit under the Credit Facilities (December 31, 2020 - $15.0 million). At December 31, 2021, Baytex was in compliance with all of the covenants contained in the Credit Facilities and is forecasting compliance with these covenants based on current forward commodity prices. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2021. Covenant Description Position as at December 31, 2021 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.6:1.0 3.5:1.0 Interest Coverage (3) (Minimum Ratio) 9.1:1.0 2.0:1.0 (1) "Senior Secured Debt" is calculated in accordance with the credit facility agreements and is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at December 31, 2021, the Company's Senior Secured Debt totaled $521.5 million. (2) "Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions 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 year ended December 31, 2021 was $836.9 million. (3) "Interest coverage" is calculated in accordance with the credit agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the year ended December 31, 2021 was $91.8 million. December 31, 2021 December 31, 2020 5.625% notes (US$200,000 – principal) due June 1, 2024 253,120 510,200 8.75% notes (US$500,000 – principal) due April 1, 2027 632,800 637,750 Total long-term notes - principal (1) $ 885,920 $ 1,147,950 Unamortized debt issuance costs (11,393) (15,082) Total long-term notes - net of unamortized debt issuance costs $ 874,527 $ 1,132,868 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2020 to December 31, 2021 is the result of principal repayments of $249.4 million and changes in the reported amount of U.S. denominated debt of $12.6 million. During 2021, Baytex repurchased and cancelled principal notes totaling US$200 million of the 5.625% Notes and recorded early redemption expense of $1.9 million. As at December 31, 2021, there was a total of US$200.0 million of the 5.625% Notes that remained outstanding. On February 5, 2020, Baytex issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable at Baytex's option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.2 million. The long-term notes do not contain any significant financial maintenance covenants.

Long-Term Notes

Long-Term Notes	12 Months Ended
	Dec. 31, 2021
Financial Instruments [Abstract]
Long-Term Notes	CREDIT FACILITIES December 31, 2021 December 31, 2020 Credit facilities - U.S. dollar denominated (1) $ 156,332 $ 140,815 Credit facilities - Canadian dollar denominated 350,182 510,358 Credit facilities - principal (2) $ 506,514 $ 651,173 Unamortized debt issuance costs (1,343) (1,952) Credit facilities $ 505,171 $ 649,221 (1) U.S. dollar denominated credit facilities balance was US$123.5 million as at December 31, 2021 (December 31, 2020 - US$110.4 million). (2) The decrease in the principal amount of the credit facilities outstanding from December 31, 2020 to December 31, 2021 is the result of net repayments of $145.3 million and an increase in the reported amount of U.S. denominated debt of $0.7 million due to foreign exchange. Baytex has US$575 million of revolving credit facilities (the "Revolving Facilities") and a $300 million non-revolving secured term loan (the "Term Loan") (collectively the "Credit Facilities"). The Credit Facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The $300 million Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership. The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon Baytex's request. Advances (including letters of credit) under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates ("LIBOR"), plus applicable margins. The LIBOR benchmark transition began on December 31, 2021. Certain tenors of the U.S. dollar LIBOR benchmark are no longer published as of December 31, 2021 while some tenors will continue to be published through mid-2023. We expect the U.S. dollar LIBOR benchmarks to be replaced with an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material impact to Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate. The weighted average interest rate on the Credit Facilities was 2.1% for the year ended December 31, 2021 (2.4% for the year ended December 31, 2020). At December 31, 2021, Baytex had $15.0 million of outstanding letters of credit under the Credit Facilities (December 31, 2020 - $15.0 million). At December 31, 2021, Baytex was in compliance with all of the covenants contained in the Credit Facilities and is forecasting compliance with these covenants based on current forward commodity prices. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2021. Covenant Description Position as at December 31, 2021 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.6:1.0 3.5:1.0 Interest Coverage (3) (Minimum Ratio) 9.1:1.0 2.0:1.0 (1) "Senior Secured Debt" is calculated in accordance with the credit facility agreements and is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at December 31, 2021, the Company's Senior Secured Debt totaled $521.5 million. (2) "Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions 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 year ended December 31, 2021 was $836.9 million. (3) "Interest coverage" is calculated in accordance with the credit agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the year ended December 31, 2021 was $91.8 million. December 31, 2021 December 31, 2020 5.625% notes (US$200,000 – principal) due June 1, 2024 253,120 510,200 8.75% notes (US$500,000 – principal) due April 1, 2027 632,800 637,750 Total long-term notes - principal (1) $ 885,920 $ 1,147,950 Unamortized debt issuance costs (11,393) (15,082) Total long-term notes - net of unamortized debt issuance costs $ 874,527 $ 1,132,868 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2020 to December 31, 2021 is the result of principal repayments of $249.4 million and changes in the reported amount of U.S. denominated debt of $12.6 million. During 2021, Baytex repurchased and cancelled principal notes totaling US$200 million of the 5.625% Notes and recorded early redemption expense of $1.9 million. As at December 31, 2021, there was a total of US$200.0 million of the 5.625% Notes that remained outstanding. On February 5, 2020, Baytex issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable at Baytex's option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.2 million. The long-term notes do not contain any significant financial maintenance covenants.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS December 31, 2021 December 31, 2020 Balance, beginning of year $ 760,383 $ 667,974 Liabilities incurred 14,845 15,189 Liabilities settled (6,662) (7,168) Liabilities acquired from property acquisitions 249 — Liabilities divested (3,161) (721) Property swaps (4,113) (525) Accretion (note 15) 12,381 8,978 Government grants (1) (2,857) (2,128) Change in estimate (9,686) (12,771) Changes in discount rates and inflation rates (2) (17,381) 92,576 Foreign currency translation (315) (1,021) Balance, end of year $ 743,683 $ 760,383 Less current portion of asset retirement obligations 11,080 11,820 Non-current portion of asset retirement obligations $ 732,603 $ 748,563 (1) During 2021, Baytex recognized $2.9 million of non-cash other income and a reduction in asset retirement obligations related to government grants provided by the Government of Alberta and the Government of Saskatchewan ($2.1 million in 2020). (2) The discount and inflation rates at December 31, 2021 were 1.7% and 1.8% respectively (December 31, 2020 - 1.2% and 1.5%). At December 31, 2021, the undiscounted amount of estimated cash flows required to settle the asset retirement obligations is $721.7 million (December 31, 2020 - $721.0 million). The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2021, calculated using an estimated inflation rate of 1.8% (December 31, 2020 - 1.5%) and a risk free discount rate of 1.7% (December 31, 2020 - 1.2%), is $743.7 million (December 31, 2020 - $760.4 million). These costs are expected to be incurred over the next 60 years.

Shareholders' Capital

Shareholders' Capital	12 Months Ended
	Dec. 31, 2021
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, 2021, 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 meeting 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, 2019 558,305 $ 5,718,835 Vesting of share awards 2,922 10,583 Balance, December 31, 2020 561,227 $ 5,729,418 Vesting of share awards 2,986 7,175 Balance, December 31, 2021 564,213 $ 5,736,593

Share-Based Compensation Plan

Share-Based Compensation Plan	12 Months Ended
	Dec. 31, 2021
Share-Based Payment Arrangements [Abstract]
Share-Based Compensation Plan	SHARE-BASED COMPENSATION PLANFor the year ended December 31, 2021, the Company recorded total compensation expense related to the share awards of $11.1 million ($9.5 million for the year ended December 31, 2020) which includes $4.7 million of compensation expense related to the incentive award plan, deferred share unit plan and the associated equity total return swaps ($2.3 million for the year ended December 31, 2020). Share Award Incentive Plan Baytex has a share award plan pursuant to which it issues restricted and performance awards. A restricted award entitles the holder of each award to receive one common share of Baytex at the time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares on vesting; the number of common shares issued is determined by a multiplier. The multiplier, which ranges between zero and two, is calculated based on a number of factors determined and approved by the Board of Directors on an annual basis. The restricted awards and performance awards vest in equal tranches on the first, second and third anniversaries of the grant date. At Baytex's option, these awards may be cash settled at vesting. The weighted average fair value of share awards granted during the year ended December 31, 2021 was $1.31 per restricted and performance award ($1.48 for the year ended December 31, 2020). The number of share awards outstanding is detailed below: (000s) Number of Number of Total number of Balance, December 31, 2019 3,801 3,135 6,936 Granted 2,239 3,253 5,492 Vested and converted to common shares (1,730) (1,192) (2,922) Forfeited (188) (1,108) (1,296) Balance, December 31, 2020 4,122 4,088 8,210 Granted — 4,067 4,067 Added by performance factor — 669 669 Vested and converted to common shares (1,861) (1,152) (3,013) Forfeited (168) (291) (459) Balance, December 31, 2021 2,093 7,381 9,474 Incentive Award Plan Baytex has an incentive award plan (the "Incentive Award" plan) whereby the holder of each incentive award is entitled to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables. During the year ended December 31, 2021, Baytex granted 5.0 million awards under the Incentive Award plan at a fair value of $1.33 per award (2.9 million awards at $1.50 per award for the year ended December 31, 2020). At December 31, 2021 there were 6.4 million awards outstanding under the Incentive Award plan (2.6 million awards outstanding at December 31, 2020). Deferred Share Unit Plan Baytex has a deferred share unit plan (the "DSU" plan) whereby each Director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share on the date on which they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period end and are included in trade and other payables. During the year ended December 31, 2021, Baytex granted 0.9 million awards under the DSU plan at a fair value of $1.29 per award. At December 31, 2021, there were 0.8 million awards outstanding under the DSU plan. The Company uses equity total return swaps on the equivalent number of Baytex common shares in order to fix a portion of the aggregate cost of the Incentive Award plan and the DSU plan at the fair value determined on the grant date. The carrying value of the financial derivatives includes the fair value of the equity total return swap which was an asset of $6.5 million on December 31, 2021 (December 31, 2020 - liability of $1.1 million). At December 31, 2021, an asset of $10.7 million associated with the equity return swap is included in accounts payable as it relates to the settlement of cash compensation payable (December 31, 2020 - a liability of $1.2 million).

Net Income (Loss) Per Share

Net Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2021
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 were converted to common shares. The treasury stock method is used to determine the dilutive effect of share awards whereby the potential conversion of share awards and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the year. Years Ended December 31 2021 2020 Net income Weighted average common shares (000's) Net income per share Net loss Weighted average common shares (000's) Net loss per share Net income (loss) - basic $ 1,613,600 563,674 $ 2.86 $ (2,438,964) 560,657 $ (4.35) Dilutive effect of share awards — 7,936 — — — — Net income (loss) - diluted $ 1,613,600 571,610 $ 2.82 $ (2,438,964) 560,657 $ (4.35)

Petroleum and Natural Gas Sales

Petroleum and Natural Gas Sales	12 Months Ended
	Dec. 31, 2021
Disclosure of revenue from contracts with customers [Abstract]
Petroleum and Natural Gas Sales	PETROLEUM AND NATURAL GAS SALES Petroleum and natural gas sales from contracts with customers for the Company's Canadian and U.S. operating segments is set forth in the following table. Years Ended December 31 2021 2020 Canada U.S. Total Canada U.S. Total Light oil and condensate $ 480,199 $ 585,635 $ 1,065,834 $ 296,125 $ 327,460 $ 623,585 Heavy oil 560,696 — 560,696 236,235 — 236,235 NGL 18,904 75,611 94,515 6,037 34,845 40,882 Natural gas sales 68,338 78,812 147,150 33,344 41,431 74,775 Total petroleum and natural gas sales $ 1,128,137 $ 740,058 $ 1,868,195 $ 571,741 $ 403,736 $ 975,477 Included in accounts receivable at December 31, 2021 is $154.0 million of accrued receivables related to delivered volumes (December 31, 2020 - $81.3 million).

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Taxes [Abstract]
Income Taxes	INCOME TAXES The provision for income taxes has been computed as follows: Years Ended December 31 2021 2020 Net income (loss) before income taxes $ 1,694,840 $ (2,599,357) Expected income taxes at the statutory rate of 25.12% (2020 – 25.42%) 425,744 (660,757) (Increase) decrease in income tax recovery resulting from: Share-based compensation 1,605 1,834 Effect of foreign exchange (841) 1,017 Effect of change in income tax rates (65) 10,969 Effect of rate adjustments for foreign jurisdictions (21,746) 22,375 Effect of change in deferred tax benefit not recognized (325,295) 444,117 Effect of U.S. tax change — 19,807 Adjustments and assessments 1,838 245 Income tax expense (recovery) $ 81,240 $ (160,393) At December 31, 2021, a deferred tax asset of $145.6 million remains unrecognized due to uncertainty surrounding future commodity prices and future capital gains (December 31, 2020 - $469.7 million). These deferred income tax assets relate to capital losses of $237.4 million and non-capital losses of $461.1 million, which expire from 2033 to 2039. In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the “CRA”) that denied $591 million of non-capital loss deductions that relate to the calculation of income taxes for the years 2011 through 2015. In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Officer was assigned to the Company's file in July 2018. Baytex remains confident that the original tax filings are correct and intends to defend those tax filings through the appeals process. A continuity of the net deferred income tax liability is detailed in the following tables: As at January 1, 2021 Recognized in Net Income Foreign Currency Translation Adjustment December 31, 2021 Taxable temporary differences: Petroleum and natural gas properties $ (502,625) $ (257,800) $ (154) $ (760,579) Financial derivatives — — — — Other (22,377) 624 137 (21,616) Deductible temporary differences: Asset retirement obligations 187,840 (2,436) (68) 185,336 Financial derivatives 5,410 26,082 — 31,492 Non-capital losses 241,514 104,479 (3,109) 342,884 Finance costs 3,705 49,083 2,239 55,027 Net deferred income tax liability (1) $ (86,533) $ (79,968) $ (955) $ (167,456) (1) Non-capital loss carry-forwards at December 31, 2021 totaled $2.0 billion and expire from 2033 to 2039. As at January 1, 2020 Recognized in Net Loss Foreign Currency Translation Adjustment December 31, 2020 Taxable temporary differences: Petroleum and natural gas properties $ (881,994) $ 378,321 $ 1,048 $ (502,625) Financial derivatives — — — — Other (2,403) (18,839) (1,135) (22,377) Deductible temporary differences: Asset retirement obligations 164,523 23,432 (115) 187,840 Financial derivatives 802 4,608 — 5,410 Non-capital losses 386,717 (141,468) (3,735) 241,514 Finance costs 97,047 (85,087) (8,255) 3,705 Net deferred income tax liability (1) $ (235,308) $ 160,967 $ (12,192) $ (86,533) (1) Non-capital loss carry-forwards at December 31, 2020 totaled $2.2 billion and expire from 2034 to 2040.

Financing and Interest

Financing and Interest	12 Months Ended
	Dec. 31, 2021
Analysis of income and expense [abstract]
Financing and Interest	FINANCING AND INTEREST Years Ended December 31 2021 2020 Interest on credit facilities $ 13,300 $ 15,256 Interest on long-term notes 78,546 90,830 Interest on lease obligations 223 448 Cash interest $ 92,069 $ 106,534 Amortization of debt issue costs 4,858 6,617 Accretion of asset retirement obligations (note 9) 12,381 8,978 Early redemption expense (note 8) 1,851 3,312 Financing and interest $ 111,159 $ 125,441

Foreign Exchange

Foreign Exchange	12 Months Ended
	Dec. 31, 2021
Effects Of Changes In Foreign Exchange Rates [Abstract]
Foreign Exchange	FOREIGN EXCHANGE Years Ended December 31 2021 2020 Unrealized foreign exchange loss - intercompany notes (1) $ 12,000 $ 31,617 Unrealized foreign exchange gain - long-term notes & credit facilities (13,905) (22,385) Realized foreign exchange gain (963) (544) Foreign exchange (gain) loss $ (2,868) $ 8,688 (1) During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. During 2021, US$150.0 million of these notes were redeemed and cancelled. At December 31, 2021, US$601.0 million of this series of intercompany notes remained outstanding. These notes are eliminated upon consolidation within the Statement of Financial Position and are revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2021
Financial Instruments [Abstract]
Financial Instruments and Risk Management	FINANCIAL INSTRUMENTS AND RISK MANAGEMENTThe Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, credit facilities and long-term notes. The fair value of the credit facilities is equal to the principal amount outstanding as the credit facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices. The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories: December 31, 2021 December 31, 2020 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 8,654 $ 8,654 $ 5,057 $ 5,057 Level 2 Total $ 8,654 $ 8,654 $ 5,057 $ 5,057 Amortized cost Trade and other receivables $ 173,409 $ 173,409 $ 107,477 $ 107,477 — Total $ 173,409 $ 173,409 $ 107,477 $ 107,477 Financial Liabilities FVTPL Financial Derivatives $ (134,020) $ (134,020) $ (26,792) $ (26,792) Level 2 Total $ (134,020) $ (134,020) $ (26,792) $ (26,792) Amortized cost Trade and other payables $ (190,692) $ (190,692) $ (155,955) $ (155,955) — Credit Facilities (505,171) (506,514) (649,221) (651,173) — Long-term notes (874,527) (917,889) (1,132,868) (761,129) Level 1 Total $ (1,570,390) $ (1,615,095) $ (1,938,044) $ (1,568,257) There were no transfers between Level 1 and Level 2 during the years ended December 31, 2021 or 2020. Foreign Currency Risk Baytex is exposed to fluctuations in foreign exchange rates as a result of the U.S. dollar portion of its credit facilities, long-term notes, intercompany 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. 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 $2.3 million. The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows: Assets Liabilities December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 U.S. dollar denominated US$602,503 US$759,508 US$829,934 US$934,731 Interest Rate Risk The Company's interest rate risk arises from borrowing at floating rates under the Credit Facilities (note 7). Based on the principal outstanding on the Credit Facilities as at December 31, 2021, a change of 100 basis points in interest rates would impact net income or loss before income taxes by approximately $5.1 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, 2021, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $10.4 million. When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2021, a US$0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $3.7 million. Financial Derivative Contracts Baytex had the following commodity financial derivative contracts outstanding as at February 24, 2022. Period Volume Price/Unit (1) Index Oil Basis swap Jan 2022 to Dec 2022 12,000 bbl/d WTI less US$12.40/bbl WCS Basis swap Jan 2022 to Dec 2022 4,000 bbl/d WTI less US$4.43/bbl MSW Basis swap (3) Feb 2022 to Jun 2022 1,000 bbl/d WTI less US$3.00/bbl MSW Basis swap (3) Mar 2022 to Dec 2022 2,000 bbl/d WTI less US$2.88/bbl MSW Fixed - Sell Jan 2022 to Dec 2022 10,000 bbl/d US$53.50/bbl WTI 3-way option (2) Jan 2022 to Dec 2022 1,500 bbl/d US$40.00/US$50.00/US$58.10 WTI 3-way option (2) Jan 2022 to Dec 2022 2,000 bbl/d US$46.00/US$56.00/US$66.72 WTI 3-way option (2) Jan 2022 to Dec 2022 2,500 bbl/d US$47.00/US$57.00/US$67.00 WTI 3-way option (2) Jan 2022 to Dec 2022 2,500 bbl/d US$50.00/US$60.00/US$70.00 WTI 3-way option (2) Jan 2022 to Dec 2022 2,000 bbl/d US$53.00/US$63.50/US$72.90 WTI 3-way option (2) Jan 2023 to Dec 2023 2,000 bbl/d US$55.00/US$66.00/US$84.00 WTI 3-way option (2)(3) Jan 2023 to Dec 2023 2,500 bbl/d US$60.00/US$75.00/US$91.54 WTI Natural Gas Fixed - Sell Jan 2022 to Dec 2022 5,000 GJ/d $2.53/GJ AECO 7A Fixed - Sell Jan 2022 to Dec 2022 14,250 GJ/d $2.84/GJ AECO 5A Fixed - Sell Jan 2022 to Dec 2022 1,000 mmbtu/d US$2.94/mmbtu NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.25/US$2.75/US$3.06 NYMEX 3-way option (2) Jan 2022 to Dec 2022 1,500 mmbtu/d US$2.60/US$2.91/US$3.56 NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.60/US$3.00/US$3.83 NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.65/US$2.90/US$3.40 NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$3.00/US$3.75/US$4.40 NYMEX (1) Based on the weighted average price per unit for the period. (2) Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$50.00/US$60.00/US$70.00 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. (3) Contracts entered subsequent to December 31, 2021. The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives. Years Ended December 31 2021 2020 Realized financial derivatives loss (gain) $ 184,241 $ (47,836) Unrealized financial derivatives loss 103,631 18,500 Financial derivatives loss (gain) $ 287,872 $ (29,336) 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, 2021, Baytex had $506.5 million of principal amounts and $15.0 million of letters of credit outstanding on its Credit Facilities (December 31, 2020 - $651.2 million and $15.0 million, respectively) which have total availability of $1.0 billion (December 31, 2020 - $1.0 billion). The timing of cash outflows relating to financial liabilities as at December 31, 2021 is outlined in the table below: Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Trade and other payables $ 190,692 $ 190,692 — $ — $ — Financial derivatives 134,020 134,020 — — — Credit facilities (1)(2) 506,514 — 506,514 — — Long-term notes (1)(3) 885,920 — 253,120 — 632,800 Interest on long-term notes (4) 325,172 69,608 130,868 110,740 13,956 Lease obligations (1) 8,014 3,068 3,989 902 55 $ 2,050,332 $ 397,388 $ 894,491 $ 111,642 $ 646,811 (1) Principal amount of instruments. (2) The credit facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing the Company has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. (3) Principal amount of instruments. The US$500 million principal amount of 8.75% senior unsecured notes is due April 1, 2027 and the US$200 million principal amount of the 5.625% senior unsecured notes is due June 1, 2024 (note 8). (4) Excludes interest on credit facilities as interest payments on credit facilities fluctuate based on amounts outstanding and the prevailing interest rate at the time of borrowing. 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, 2021, the Company is exposed to credit risk with respect to its trade and other receivables and financial derivatives. Baytex manages these risks through the selection and monitoring of credit-worthy counterparties. Most of the Company's trade and other receivables relate to petroleum and natural gas sales. Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts after reviewing the creditworthiness of the entity. 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 trade and other receivables at December 31, 2021 relates to accrued revenues. Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day of the month following production. Joint interest receivables are typically collected within one three Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of trade and other receivables is reduced by adjusting the allowance for doubtful accounts and recording 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, 2021, allowance for doubtful accounts was $2.6 million (December 31, 2020 - $2.0 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, 2021, accounts receivable that Baytex has deemed past due (more than 90 days) but not impaired was $1.8 million (December 31, 2020 - $1.6 million). Baytex has estimated the lifetime expected credit loss as at and for the year ended December 31, 2021 to be nominal. The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2021. Trade and Other Receivables Aging December 31, 2021 December 31, 2020 Current (less than 30 days) $ 171,058 $ 104,210 31-60 days 441 1,493 61-90 days 107 220 Past due (more than 90 days) 1,803 1,554 $ 173,409 $ 107,477

Supplemental Information

Supplemental Information	12 Months Ended
	Dec. 31, 2021
Additional Information1 [Abstract]
Supplemental Information	SUPPLEMENTAL INFORMATION Changes in Non-Cash Working Capital Items Years Ended December 31 2021 2020 Trade and other receivables $ (65,932) $ 66,285 Trade and other payables 34,737 (51,499) $ (31,195) $ 14,786 Changes in non-cash working capital related to: Operating activities $ (26,582) $ 48,758 Investing activities (2,797) (32,031) Foreign currency translation on non-cash working capital (1,816) (1,941) $ (31,195) $ 14,786 Income Statement Presentation Baytex's consolidated statements of income or loss and comprehensive income or loss are prepared primarily according to the nature of expense, with the exception of employee compensation costs which are included in both operating expense and general and administrative expense line items. The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense. Years Ended December 31 2021 2020 Operating $ 11,053 $ 9,065 General and administrative 29,538 22,802 Total employee compensation costs $ 40,591 $ 31,867

Commitments

Commitments	12 Months Ended
	Dec. 31, 2021
Commitments And Contingencies [Abstract]
Commitments	COMMITMENTS 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, 2021, and the expected timing of funding of these obligations, are noted in the table below. Total Less than 1-3 years 3-5 years Beyond 5 years Processing agreements $ 6,090 753 890 530 3,917 Transportation agreements 81,182 20,500 37,825 14,673 8,184 Total $ 87,272 $ 21,253 $ 38,715 $ 15,203 $ 12,101 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.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2021
Related Party [Abstract]
Related Parties	RELATED PARTIES Transactions with key management personnel and directors are noted in the table below. Years Ended December 31 2021 2020 Short-term employee benefits $ 5,995 $ 4,295 Share-based compensation 5,917 4,080 Total compensation for key management personnel $ 11,912 $ 8,375

Capital Management

Capital Management	12 Months Ended
	Dec. 31, 2021
Corporate Information And Statement Of IFRS Compliance [Abstract]
Capital Management	CAPITAL MANAGEMENT The Company's capital management objective is to maintain financial flexibility and sufficient sources of liquidity to execute its capital programs, while meeting short and long-term commitments. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At December 31, 2021, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other payables and the Credit Facilities. In order to manage its capital structure and liquidity, Baytex may from time to time issue equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required. The capital intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Baytex's capital resources consist primarily of Adjusted Funds Flow, available Credit Facilities and proceeds received from the divestiture of oil and gas properties. The following capital management measures and ratios are used to monitor current and projected sources of liquidity. Net Debt The Company uses Net Debt to monitor it's current financial position and to evaluate existing sources of liquidity. Baytex also uses Net Debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. The following table reconciles Net Debt to amounts disclosed in the primary financial statements. December 31, 2021 December 31, 2020 Credit facilities $ 505,171 $ 649,221 Unamortized debt issuance costs - Credit Facilities (note 7) 1,343 1,952 Long-term notes 874,527 1,132,868 Unamortized debt issuance costs - Long-term notes (note 8) 11,393 15,082 Trade and other payables 190,692 155,955 Trade and other receivables (173,409) (107,477) Net Debt $ 1,409,717 $ 1,847,601 Adjusted Funds Flow Adjusted Funds Flow is used to monitor operating performance and the Company's ability to generate funds for exploration and development expenditures, debt repayment, settlement of abandonment obligations and potential future dividends. Baytex also uses a Net Debt to Adjusted Funds Flow ratio calculated on a twelve-month trailing basis to monitor the Company's existing capital structure and future liquidity requirements. Adjusted Funds Flow is reconciled to amounts disclosed in the primary financial statements in the following table. Years Ended December 31 2021 2020 Cash flows from operating activities $ 712,384 $ 353,096 Change in non-cash working capital 26,582 (48,758) Asset retirement obligations settled 6,662 7,168 Adjusted Funds Flow $ 745,628 $ 311,506 Net Debt to Adjusted Funds Flow 1.9 5.9

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Current Environment and Estimation Uncertainty	Current Environment and Estimation Uncertainty Management makes judgements and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities.
Environmental Reporting Regulations	Environmental Reporting Regulations Environmental reporting for public enterprises continues to evolve and we may be subject to additional future disclosure requirements. The International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Securities Administrators have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. We continue to monitor developments on these reporting requirements and have not yet quantified the cost to comply with these regulations.
Measurement Uncertainty and Judgments	Measurement Uncertainty and Judgments The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available, including considerations related to environmental regulation and related matters, to the Company at the time of financial statement preparation. Actual results can differ from those estimates as the effect of future events cannot be determined with certainty. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below. Reserves The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion, evaluating the recoverability of deferred income tax assets and in the determination of fair value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by independent reserves evaluators and represent the estimated recoverable quantities of oil, natural gas and NGL and the related net cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the Canadian Oil and Gas Evaluation Handbook. Estimates of economically recoverable oil, natural gas and NGL and their future net cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forward price forecasts, production rates, ultimate reserve recovery, timing and amount of capital expenditures, production costs, marketability of oil and natural gas, royalty rates and other geological, economic and technical factors could have a significant impact on reported reserves. Changes in the Company's reserves estimates can have a significant impact on the carrying values of the Company's oil and gas properties, the calculation of depletion, the valuation of deferred income tax assets, the timing of cash flows for asset retirement obligations, asset impairments and estimates of fair value determined in accounting for business combinations. Cash-generating Units ("CGUs") The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash flows that are largely independent of the cash flows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk. Identification of Impairment and Impairment Reversal Indicators Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. The assessment for each CGU considers significant changes in reservoir performance including forecasted production volumes, forecasted royalty, operating, capital and abandonment and reclamation costs, forecasted oil and gas prices and the resulting cash flows from proved plus probable oil and gas reserves. Measurement of Recoverable Amount If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves, the discount rate used to present value future cash flows and assumptions regarding the timing and amount of capital expenditures and future abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets. Exploration and Evaluation ("E&E") Assets Costs associated with acquiring oil and natural gas licenses and exploratory drilling are accumulated as E&E assets pending determination of technical feasibility and commercial viability. The determination of technical feasibility and commercial viability of E&E assets for the purposes of reclassifying such assets to oil and gas properties is subject to management judgment. Management uses the establishment of commercial reserves as the basis for determining technical feasibility and commercial viability. Upon determination of commercial reserves, E&E assets are tested for impairment and reclassified to oil and natural gas properties. 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 Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which 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.
Consolidation	Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany transactions are eliminated in preparation of the consolidated financial statements. Many of the Company's exploration, development and production activities are conducted through joint arrangements. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by joint arrangements.
Business Combinations	Business Combinations Business combinations are accounted for using the acquisition method of accounting when the acquired assets meet the definition of a business under IFRS. The cost of an acquisition is measured as cash paid and the fair value of assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair value of the net identifiable assets acquired is recognized as goodwill. If the cost of acquisition is below the fair values of the identifiable net assets acquired, the difference is recognized as a bargain purchase gain in net income or loss. Associated transaction costs are expensed when incurred.
Revenue Recognition	Revenue Recognition Revenue from the sale of light oil and condensate, heavy oil, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis when Baytex acts in the capacity of an agent rather than as a principal. The transaction price for variable price contracts in the Canadian and U.S. operating segments is based on a representative commodity price index, and may include adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period. Tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.
E&E Assets	E&E 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.
Oil and Gas Properties	Oil and Gas Properties Oil and gas properties are initially recorded at cost and include the costs to acquire, develop, complete geological and geophysical surveys, drill wells, and construct and install infrastructure including 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 economic benefits of the replacement will be realized by the Company in the future. 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 oil and gas properties are depleted on a unit-of-production basis by depletable area over proved plus probable reserves once commercial production has commenced. Future development costs required to bring those reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil equivalent.
Impairment and Impairment Reversals	Impairment and Impairment Reversals 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 or when facts and circumstances suggest that the carrying amount exceeds the recoverable amount. When reviewing for indicators of impairment or impairment reversal, and testing for impairment or impairment reversal when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows include CGU production volumes, royalty obligations, operating costs, capital costs, forecast commodity prices, along with inflation and discount rates used to estimate present value. FVLCD is determined as the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction between willing parties. In determining FVLCD, recent market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a discount rate that reflects current market assessments of the time value of money. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment reduces the carrying amount of any goodwill allocated to the CGU first, with any remaining impairment being allocated to the individual assets in the CGU on a pro-rata basis. Impairments may be reversed for all CGUs and individual assets, other than goodwill, when there is indication that a previously recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. An impairment may be reversed only to the extent that the asset’s revised carrying amount does not exceed the carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized. Impairment recognized in relation to goodwill is not reversed for subsequent increases in its recoverable amount. Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal occurs.
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.
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. Management judgement is required in the designation of a subsidiary's functional currency which is 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 during the 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 Financial assets are initially classified into three categories: 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. 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 Credit facilities 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. Debt issuance costs related to the amendment of our credit facilities or the issuance of long term notes are capitalized and amortized as financing costs over the term of the credit facilities or long term notes. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract. The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The risk management policy permits the use of certain derivative financial instruments, including swaps and collars, to manage these fluctuations. All transactions of this nature entered into by the Company are related to underlying financial instruments or future petroleum and natural gas production. These instruments are classified as FVTPL. The Company does not use financial derivatives for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments by recording an asset or liability on the statements of financial position and recognizing changes in the fair value of the instrument in the statements of income or loss for the current period. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or loss when incurred. The Company has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are recognized in revenue in the period the product is delivered to the sales point.
Fair Value of Financial Instruments	Fair Value of Financial Instruments Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments: • Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. • Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. • Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.
Income Taxes	Income Taxes Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized directly in equity, in which case the current and deferred taxes are also recognized directly in equity. Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes the financial statement impact of a tax filing position when it is probable that the position will be sustained upon audit. The liability is measured based on an assessment of possible outcomes and their associated probabilities. The Company follows the 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. Share Awards vest in equal tranches on the first, second and third anniversaries of the grant date. 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, with a corresponding increase to contributed surplus. The payout multiplier is dependent on the performance of the Company relative to predefined 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 has a cash-settled incentive award plan (the "Incentive Award Plan") pursuant to which incentive awards may be granted to officers and employees of the Company and its subsidiaries. Each incentive award entitles the holder to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Depreciation methods and estimated useful lives for other plant and equipment	Cost Accumulated Net book value Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Capital expenditures 275,850 — 275,850 Transfers from exploration and evaluation assets (note 5) 8,585 — 8,585 Change in asset retirement obligations (note 9) 94,994 — 94,994 Property swaps (1,190) 178 (1,012) Impairment — (2,247,162) (2,247,162) Foreign currency translation (82,860) 120,123 37,263 Depletion — (478,859) (478,859) Balance, December 31, 2020 $ 11,423,676 $ (8,346,128) $ 3,077,548 Capital expenditures 310,005 — 310,005 Property acquisitions 274 — 274 Divestitures (37,835) 32,844 (4,991) Property swaps (26,131) 25,900 (231) Transfers from exploration and evaluation assets (note 5) 7,727 — 7,727 Change in asset retirement obligations (note 9) (12,222) — (12,222) Impairment reversal — 1,542,414 1,542,414 Foreign currency translation (31,977) 34,765 2,788 Depletion — (458,941) (458,941) Balance, December 31, 2021 $ 11,633,517 $ (7,169,146) $ 4,464,371

Segmented Financial Informati_2

Segmented Financial Information (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 2021 2020 2021 2020 2021 2020 Revenue, net of royalties Petroleum and natural gas sales $ 1,128,137 $ 571,741 $ 740,058 $ 403,736 $ — $ — $ 1,868,195 $ 975,477 Royalties (121,306) (46,064) (217,850) (117,671) — — (339,156) (163,735) 1,006,831 525,677 522,208 286,065 — — 1,529,039 811,742 Expenses Operating 257,658 247,050 85,344 84,295 — — 343,002 331,345 Transportation 32,261 28,437 — — — — 32,261 28,437 Blending and other 85,689 48,381 — — — — 85,689 48,381 General and administrative — — — — 40,804 34,268 40,804 34,268 Exploration and evaluation 15,212 14,011 — — — — 15,212 14,011 Depletion and depreciation 303,135 309,420 155,806 169,439 5,639 7,521 464,580 486,380 Impairment (reversal) loss (1,100,000) 1,737,000 (442,414) 623,220 — — (1,542,414) 2,360,220 Share-based compensation — — — — 11,130 9,469 11,130 9,469 Financing and interest — — — — 111,159 125,441 111,159 125,441 Financial derivatives loss (gain) — — — — 287,872 (29,336) 287,872 (29,336) Foreign exchange (gain) loss — — — — (2,868) 8,688 (2,868) 8,688 (Gain) loss on dispositions (9,856) (901) 190 — — — (9,666) (901) Other (income) expense (2,857) (2,128) — — 295 (3,176) (2,562) (5,304) (418,758) 2,381,270 (201,074) 876,954 454,031 152,875 (165,801) 3,411,099 Net income (loss) before income taxes 1,425,589 (1,855,593) 723,282 (590,889) (454,031) (152,875) 1,694,840 (2,599,357) Income tax expense (recovery) Current income tax (recovery) expense (548) 469 1,820 105 — — 1,272 574 Deferred income tax expense (recovery) 86,928 (77,201) 72,913 (57,199) (79,873) (26,567) 79,968 (160,967) 86,380 (76,732) 74,733 (57,094) (79,873) (26,567) 81,240 (160,393) Net income (loss) $ 1,339,209 $ (1,778,861) $ 648,549 $ (533,795) $ (374,158) $ (126,308) $ 1,613,600 $ (2,438,964) Additions to exploration and evaluation assets 3,298 4,490 — — — — 3,298 4,490 Additions to oil and gas properties 204,912 170,462 105,093 105,388 — — 310,005 275,850 Property acquisitions 1,557 — — — — — 1,557 — Proceeds from dispositions (7,211) (182) (593) — — — (7,804) (182)
Assets by segment	As at December 31, 2021 December 31, 2020 Canadian assets $ 2,658,281 $ 1,646,412 U.S. assets 2,152,323 1,737,533 Corporate assets 24,039 24,151 Total consolidated assets $ 4,834,643 $ 3,408,096

Exploration and Evaluation As_2

Exploration and Evaluation Assets (Tables)	12 Months Ended
	Dec. 31, 2021
Exploration For And Evaluation Of Mineral Resources [Abstract]
Exploration and evaluation assets	December 31, 2021 December 31, 2020 Balance, beginning of year $ 191,865 $ 320,210 Capital expenditures 3,298 4,490 Property acquisitions 1,100 — Divestitures (166) — Property swaps 408 468 Impairment — (113,058) Exploration and evaluation expense (1) (15,212) (14,011) Transfers to oil and gas properties (note 6) (7,727) (8,585) Foreign currency translation (742) 2,351 Balance, end of year $ 172,824 $ 191,865 (1) Exploration and evaluation expense balance consists of land expiries as at December 31, 2021.
Impairment of cash generating units	The following table indicates the impairment loss booked for each CGU at March 31, 2020. Impairment at Conventional CGU $ 4,000 Peace River CGU 20,000 Lloydminster CGU 42,000 Viking CGU 13,000 Eagle Ford CGU 48,861 $ 127,861
Schedule of impairment and impairment reversal	The following table indicates the impairment reversal booked for the Viking and Eagle Ford CGUs at December 31, 2020. Impairment reversal at December 31, 2020 Viking CGU $ 2,000 Eagle Ford CGU 12,803 $ 14,803

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2021
Property, plant and equipment [abstract]
Plant and equipment	Cost Accumulated Net book value Balance, December 31, 2019 $ 11,128,297 $ (5,740,408) $ 5,387,889 Capital expenditures 275,850 — 275,850 Transfers from exploration and evaluation assets (note 5) 8,585 — 8,585 Change in asset retirement obligations (note 9) 94,994 — 94,994 Property swaps (1,190) 178 (1,012) Impairment — (2,247,162) (2,247,162) Foreign currency translation (82,860) 120,123 37,263 Depletion — (478,859) (478,859) Balance, December 31, 2020 $ 11,423,676 $ (8,346,128) $ 3,077,548 Capital expenditures 310,005 — 310,005 Property acquisitions 274 — 274 Divestitures (37,835) 32,844 (4,991) Property swaps (26,131) 25,900 (231) Transfers from exploration and evaluation assets (note 5) 7,727 — 7,727 Change in asset retirement obligations (note 9) (12,222) — (12,222) Impairment reversal — 1,542,414 1,542,414 Foreign currency translation (31,977) 34,765 2,788 Depletion — (458,941) (458,941) Balance, December 31, 2021 $ 11,633,517 $ (7,169,146) $ 4,464,371
Disclosure of recoverable amount of CGU benchmark reference prices	The prices and costs subsequent to 2031 have been adjusted for inflation at an annual rate of 2.0%. 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 WTI crude oil (US$/bbl) 72.83 68.78 66.76 68.09 69.45 70.84 72.26 73.70 75.18 76.68 WCS heavy oil ($/bbl) 74.42 69.17 66.54 67.87 69.23 70.61 72.02 73.46 74.69 76.19 LLS crude oil (US$/bbl) 74.33 70.28 68.27 69.62 71.01 72.41 73.85 75.32 76.82 78.35 Edmonton par oil ($/bbl) 86.82 80.73 78.01 79.57 81.16 82.78 84.44 86.13 87.85 89.61 Henry Hub gas (US$/mmbtu) 3.85 3.44 3.17 3.24 3.30 3.37 3.44 3.50 3.58 3.65 AECO gas ($/mmbtu) 3.56 3.21 3.05 3.11 3.17 3.23 3.30 3.36 3.43 3.50 Exchange rate (CAD/USD) 1.26 1.26 1.26 1.26 1.26 1.26 1.26 1.26 1.26 1.26 At June 30, 2021, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2.0%. 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 WTI crude oil (US$/bbl) 71.33 67.20 63.95 63.23 64.50 65.79 67.10 68.44 69.81 71.21 WCS heavy oil ($/bbl) 72.22 66.84 61.73 60.70 61.91 63.15 64.42 65.70 67.02 68.36 LLS crude oil (US$/bbl) 72.17 68.53 65.80 65.10 66.39 67.71 69.05 70.42 71.82 73.26 Edmonton par oil ($/bbl) 83.20 78.27 74.06 73.05 74.51 76.00 77.52 79.07 80.66 82.27 Henry Hub gas (US$/mmbtu) 3.42 3.19 2.92 2.96 3.02 3.08 3.14 3.21 3.27 3.34 AECO gas ($/mmbtu) 3.46 3.13 2.72 2.71 2.76 2.82 2.88 2.94 2.99 3.05 Exchange rate (CAD/USD) 1.24 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 At December 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2%. 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 WTI crude oil (US$/bbl) 47.17 50.17 53.17 54.97 56.07 57.19 58.34 59.50 60.69 61.91 WCS heavy oil ($/bbl) 44.63 48.18 52.10 54.10 55.19 56.29 57.42 58.57 59.74 60.93 LLS crude oil (US$/bbl) 49.50 52.85 55.87 57.69 58.82 59.97 61.15 62.34 63.56 64.83 Edmonton par oil ($/bbl) 55.76 59.89 63.48 65.76 67.13 68.53 69.95 71.40 72.88 74.34 Henry Hub gas (US$/mmbtu) 2.83 2.87 2.90 2.96 3.02 3.08 3.14 3.20 3.26 3.33 AECO gas ($/mmbtu) 2.78 2.70 2.61 2.65 2.70 2.76 2.81 2.87 2.92 2.98 Exchange rate (CAD/USD) 1.30 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 At March 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2%. 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 WTI crude oil (US$/bbl) 29.17 40.45 49.17 53.28 55.66 56.87 58.01 59.17 60.35 61.56 WCS heavy oil ($/bbl) 19.21 34.65 46.34 51.25 54.28 55.72 56.96 58.22 59.51 60.82 LLS crude oil (US$/bbl) 32.17 43.80 52.55 56.68 59.10 60.35 61.52 62.72 63.94 65.19 Edmonton par oil ($/bbl) 29.22 46.85 59.27 65.02 68.43 69.81 71.24 72.70 74.19 75.71 Henry Hub gas (US$/mmbtu) 2.10 2.58 2.79 2.86 2.93 3.00 3.07 3.13 3.19 3.25 AECO gas ($/mmbtu) 1.74 2.20 2.38 2.45 2.53 2.60 2.66 2.72 2.79 2.85 Exchange rate (CAD/USD) 1.41 1.37 1.34 1.34 1.34 1.33 1.33 1.33 1.33 1.33
Sensitivity of The Estimated Recoverable Amount of Changes in Assumptions	The following table summarizes the recoverable amount and impairment reversal at December 31, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the five CGUs with respect to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 77,846 $ 19,000 $ — $ 3,000 $ 8,000 Peace River CGU 489,274 251,000 8,500 53,000 3,500 Lloydminster CGU 479,411 146,000 12,500 52,000 — Viking CGU 1,320,094 — 38,000 85,500 4,500 Eagle Ford CGU 2,008,478 — 97,200 138,800 31,300 $ 4,375,103 $ 416,000 $ 156,200 $ 332,300 $ 47,300 The following table summarizes the recoverable amount and impairment reversal at June 30, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 57,891 $ 15,000 $ 1,000 $ 1,000 $ 8,000 Peace River CGU 238,714 154,000 4,000 40,000 2,500 Lloydminster CGU 340,730 154,000 12,500 52,000 — Duvernay CGU (1) 115,157 5,000 45,000 44,500 44,500 Viking CGU 1,338,985 356,000 47,000 89,500 4,500 Eagle Ford CGU 2,015,118 442,415 109,400 103,900 24,400 $ 4,106,595 $ 1,126,415 $ 218,900 $ 330,900 $ 83,900 (1) The impairment reversal for the Duvernay CGU was limited to total accumulated impairments less subsequent depletion of $5.0 million. The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 54,265 $ — $ 1,000 $ 3,000 $ 9,000 Peace River CGU 104,225 — 1,000 49,500 3,000 Lloydminster CGU 212,979 — 7,000 57,500 500 Duvernay CGU 70,491 — 5,500 12,000 1,500 Viking CGU 1,026,026 116,000 34,500 106,500 5,000 Eagle Ford CGU 1,609,562 225,326 91,600 157,500 38,400 $ 3,077,548 $ 341,326 $ 140,600 $ 386,000 $ 57,400 The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably possible changes in key assumptions inherent in the estimate. Recoverable amount Impairment Change in discount rate of 1% Change in oil price of $2.50/bbl Change in gas price of $0.25/mcf Conventional CGU $ 37,444 $ 41,000 $ 3,000 $ 3,500 $ 8,500 Peace River CGU 109,631 345,000 9,500 53,500 3,000 Lloydminster CGU 227,967 470,000 25,000 69,500 — Duvernay CGU 61,197 5,000 5,500 9,500 1,500 Viking CGU 962,134 915,000 57,000 123,000 4,000 Eagle Ford CGU 1,576,423 812,488 120,750 141,500 32,000 $ 2,974,796 $ 2,588,488 $ 220,750 $ 400,500 $ 49,000

Credit Facilities (Tables)

Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2021
Financial Instruments [Abstract]
Bank loans	December 31, 2021 December 31, 2020 Credit facilities - U.S. dollar denominated (1) $ 156,332 $ 140,815 Credit facilities - Canadian dollar denominated 350,182 510,358 Credit facilities - principal (2) $ 506,514 $ 651,173 Unamortized debt issuance costs (1,343) (1,952) Credit facilities $ 505,171 $ 649,221 (1) U.S. dollar denominated credit facilities balance was US$123.5 million as at December 31, 2021 (December 31, 2020 - US$110.4 million). (2) The decrease in the principal amount of the credit facilities outstanding from December 31, 2020 to December 31, 2021 is the result of net repayments of $145.3 million and an increase in the reported amount of U.S. denominated debt of $0.7 million due to foreign exchange. At December 31, 2021, Baytex was in compliance with all of the covenants contained in the Credit Facilities and is forecasting compliance with these covenants based on current forward commodity prices. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2021. Covenant Description Position as at December 31, 2021 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.6:1.0 3.5:1.0 Interest Coverage (3) (Minimum Ratio) 9.1:1.0 2.0:1.0 (1) "Senior Secured Debt" is calculated in accordance with the credit facility agreements and is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at December 31, 2021, the Company's Senior Secured Debt totaled $521.5 million. (2) "Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions 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 year ended December 31, 2021 was $836.9 million. (3) "Interest coverage" is calculated in accordance with the credit agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the year ended December 31, 2021 was $91.8 million. December 31, 2021 December 31, 2020 5.625% notes (US$200,000 – principal) due June 1, 2024 253,120 510,200 8.75% notes (US$500,000 – principal) due April 1, 2027 632,800 637,750 Total long-term notes - principal (1) $ 885,920 $ 1,147,950 Unamortized debt issuance costs (11,393) (15,082) Total long-term notes - net of unamortized debt issuance costs $ 874,527 $ 1,132,868 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2020 to December 31, 2021 is the result of principal repayments of $249.4 million and changes in the reported amount of U.S. denominated debt of $12.6 million.

Long-Term Notes (Tables)

Long-Term Notes (Tables)	12 Months Ended
	Dec. 31, 2021
Financial Instruments [Abstract]
Long-term notes	December 31, 2021 December 31, 2020 Credit facilities - U.S. dollar denominated (1) $ 156,332 $ 140,815 Credit facilities - Canadian dollar denominated 350,182 510,358 Credit facilities - principal (2) $ 506,514 $ 651,173 Unamortized debt issuance costs (1,343) (1,952) Credit facilities $ 505,171 $ 649,221 (1) U.S. dollar denominated credit facilities balance was US$123.5 million as at December 31, 2021 (December 31, 2020 - US$110.4 million). (2) The decrease in the principal amount of the credit facilities outstanding from December 31, 2020 to December 31, 2021 is the result of net repayments of $145.3 million and an increase in the reported amount of U.S. denominated debt of $0.7 million due to foreign exchange. At December 31, 2021, Baytex was in compliance with all of the covenants contained in the Credit Facilities and is forecasting compliance with these covenants based on current forward commodity prices. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2021. Covenant Description Position as at December 31, 2021 Covenant Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.6:1.0 3.5:1.0 Interest Coverage (3) (Minimum Ratio) 9.1:1.0 2.0:1.0 (1) "Senior Secured Debt" is calculated in accordance with the credit facility agreements and is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at December 31, 2021, the Company's Senior Secured Debt totaled $521.5 million. (2) "Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions 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 year ended December 31, 2021 was $836.9 million. (3) "Interest coverage" is calculated in accordance with the credit agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the year ended December 31, 2021 was $91.8 million. December 31, 2021 December 31, 2020 5.625% notes (US$200,000 – principal) due June 1, 2024 253,120 510,200 8.75% notes (US$500,000 – principal) due April 1, 2027 632,800 637,750 Total long-term notes - principal (1) $ 885,920 $ 1,147,950 Unamortized debt issuance costs (11,393) (15,082) Total long-term notes - net of unamortized debt issuance costs $ 874,527 $ 1,132,868 (1) The decrease in the principal amount of long-term notes outstanding from December 31, 2020 to December 31, 2021 is the result of principal repayments of $249.4 million and changes in the reported amount of U.S. denominated debt of $12.6 million.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Change in asset retirement obligations	December 31, 2021 December 31, 2020 Balance, beginning of year $ 760,383 $ 667,974 Liabilities incurred 14,845 15,189 Liabilities settled (6,662) (7,168) Liabilities acquired from property acquisitions 249 — Liabilities divested (3,161) (721) Property swaps (4,113) (525) Accretion (note 15) 12,381 8,978 Government grants (1) (2,857) (2,128) Change in estimate (9,686) (12,771) Changes in discount rates and inflation rates (2) (17,381) 92,576 Foreign currency translation (315) (1,021) Balance, end of year $ 743,683 $ 760,383 Less current portion of asset retirement obligations 11,080 11,820 Non-current portion of asset retirement obligations $ 732,603 $ 748,563 (1) During 2021, Baytex recognized $2.9 million of non-cash other income and a reduction in asset retirement obligations related to government grants provided by the Government of Alberta and the Government of Saskatchewan ($2.1 million in 2020). (2) The discount and inflation rates at December 31, 2021 were 1.7% and 1.8% respectively (December 31, 2020 - 1.2% and 1.5%).

Shareholders' Capital (Tables)

Shareholders' Capital (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2019 558,305 $ 5,718,835 Vesting of share awards 2,922 10,583 Balance, December 31, 2020 561,227 $ 5,729,418 Vesting of share awards 2,986 7,175 Balance, December 31, 2021 564,213 $ 5,736,593

Share-Based Compensation Plan (

Share-Based Compensation Plan (Tables)	12 Months Ended
	Dec. 31, 2021
Share-Based Payment Arrangements [Abstract]
Number of share awards outstanding	The number of share awards outstanding is detailed below: (000s) Number of Number of Total number of Balance, December 31, 2019 3,801 3,135 6,936 Granted 2,239 3,253 5,492 Vested and converted to common shares (1,730) (1,192) (2,922) Forfeited (188) (1,108) (1,296) Balance, December 31, 2020 4,122 4,088 8,210 Granted — 4,067 4,067 Added by performance factor — 669 669 Vested and converted to common shares (1,861) (1,152) (3,013) Forfeited (168) (291) (459) Balance, December 31, 2021 2,093 7,381 9,474

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings per share [abstract]
Net income (loss) per share	Years Ended December 31 2021 2020 Net income Weighted average common shares (000's) Net income per share Net loss Weighted average common shares (000's) Net loss per share Net income (loss) - basic $ 1,613,600 563,674 $ 2.86 $ (2,438,964) 560,657 $ (4.35) Dilutive effect of share awards — 7,936 — — — — Net income (loss) - diluted $ 1,613,600 571,610 $ 2.82 $ (2,438,964) 560,657 $ (4.35)

Petroleum and Natural Gas Sal_2

Petroleum and Natural Gas Sales (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure of revenue from contracts with customers [Abstract]
Disclosure of disaggregation of revenue from contracts with customers	Petroleum and natural gas sales from contracts with customers for the Company's Canadian and U.S. operating segments is set forth in the following table. Years Ended December 31 2021 2020 Canada U.S. Total Canada U.S. Total Light oil and condensate $ 480,199 $ 585,635 $ 1,065,834 $ 296,125 $ 327,460 $ 623,585 Heavy oil 560,696 — 560,696 236,235 — 236,235 NGL 18,904 75,611 94,515 6,037 34,845 40,882 Natural gas sales 68,338 78,812 147,150 33,344 41,431 74,775 Total petroleum and natural gas sales $ 1,128,137 $ 740,058 $ 1,868,195 $ 571,741 $ 403,736 $ 975,477

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Taxes [Abstract]
Provision for income taxes	The provision for income taxes has been computed as follows: Years Ended December 31 2021 2020 Net income (loss) before income taxes $ 1,694,840 $ (2,599,357) Expected income taxes at the statutory rate of 25.12% (2020 – 25.42%) 425,744 (660,757) (Increase) decrease in income tax recovery resulting from: Share-based compensation 1,605 1,834 Effect of foreign exchange (841) 1,017 Effect of change in income tax rates (65) 10,969 Effect of rate adjustments for foreign jurisdictions (21,746) 22,375 Effect of change in deferred tax benefit not recognized (325,295) 444,117 Effect of U.S. tax change — 19,807 Adjustments and assessments 1,838 245 Income tax expense (recovery) $ 81,240 $ (160,393)
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, 2021 Recognized in Net Income Foreign Currency Translation Adjustment December 31, 2021 Taxable temporary differences: Petroleum and natural gas properties $ (502,625) $ (257,800) $ (154) $ (760,579) Financial derivatives — — — — Other (22,377) 624 137 (21,616) Deductible temporary differences: Asset retirement obligations 187,840 (2,436) (68) 185,336 Financial derivatives 5,410 26,082 — 31,492 Non-capital losses 241,514 104,479 (3,109) 342,884 Finance costs 3,705 49,083 2,239 55,027 Net deferred income tax liability (1) $ (86,533) $ (79,968) $ (955) $ (167,456) (1) Non-capital loss carry-forwards at December 31, 2021 totaled $2.0 billion and expire from 2033 to 2039. As at January 1, 2020 Recognized in Net Loss Foreign Currency Translation Adjustment December 31, 2020 Taxable temporary differences: Petroleum and natural gas properties $ (881,994) $ 378,321 $ 1,048 $ (502,625) Financial derivatives — — — — Other (2,403) (18,839) (1,135) (22,377) Deductible temporary differences: Asset retirement obligations 164,523 23,432 (115) 187,840 Financial derivatives 802 4,608 — 5,410 Non-capital losses 386,717 (141,468) (3,735) 241,514 Finance costs 97,047 (85,087) (8,255) 3,705 Net deferred income tax liability (1) $ (235,308) $ 160,967 $ (12,192) $ (86,533) (1) Non-capital loss carry-forwards at December 31, 2020 totaled $2.2 billion and expire from 2034 to 2040.

Financing and Interest (Tables)

Financing and Interest (Tables)	12 Months Ended
	Dec. 31, 2021
Analysis of income and expense [abstract]
Schedule of financing and interest	Years Ended December 31 2021 2020 Interest on credit facilities $ 13,300 $ 15,256 Interest on long-term notes 78,546 90,830 Interest on lease obligations 223 448 Cash interest $ 92,069 $ 106,534 Amortization of debt issue costs 4,858 6,617 Accretion of asset retirement obligations (note 9) 12,381 8,978 Early redemption expense (note 8) 1,851 3,312 Financing and interest $ 111,159 $ 125,441

Foreign Exchange (Tables)

Foreign Exchange (Tables)	12 Months Ended
	Dec. 31, 2021
Effects Of Changes In Foreign Exchange Rates [Abstract]
Foreign exchange gains and losses	Years Ended December 31 2021 2020 Unrealized foreign exchange loss - intercompany notes (1) $ 12,000 $ 31,617 Unrealized foreign exchange gain - long-term notes & credit facilities (13,905) (22,385) Realized foreign exchange gain (963) (544) Foreign exchange (gain) loss $ (2,868) $ 8,688 (1) During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. During 2021, US$150.0 million of these notes were redeemed and cancelled. At December 31, 2021, US$601.0 million of this series of intercompany notes remained outstanding. These notes are eliminated upon consolidation within the Statement of Financial Position and are revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 December 31, 2020 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 8,654 $ 8,654 $ 5,057 $ 5,057 Level 2 Total $ 8,654 $ 8,654 $ 5,057 $ 5,057 Amortized cost Trade and other receivables $ 173,409 $ 173,409 $ 107,477 $ 107,477 — Total $ 173,409 $ 173,409 $ 107,477 $ 107,477 Financial Liabilities FVTPL Financial Derivatives $ (134,020) $ (134,020) $ (26,792) $ (26,792) Level 2 Total $ (134,020) $ (134,020) $ (26,792) $ (26,792) Amortized cost Trade and other payables $ (190,692) $ (190,692) $ (155,955) $ (155,955) — Credit Facilities (505,171) (506,514) (649,221) (651,173) — Long-term notes (874,527) (917,889) (1,132,868) (761,129) Level 1 Total $ (1,570,390) $ (1,615,095) $ (1,938,044) $ (1,568,257)
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, 2021 December 31, 2020 Carrying value Fair value Carrying value Fair value Fair Value Measurement Hierarchy Financial Assets FVTPL Financial Derivatives $ 8,654 $ 8,654 $ 5,057 $ 5,057 Level 2 Total $ 8,654 $ 8,654 $ 5,057 $ 5,057 Amortized cost Trade and other receivables $ 173,409 $ 173,409 $ 107,477 $ 107,477 — Total $ 173,409 $ 173,409 $ 107,477 $ 107,477 Financial Liabilities FVTPL Financial Derivatives $ (134,020) $ (134,020) $ (26,792) $ (26,792) Level 2 Total $ (134,020) $ (134,020) $ (26,792) $ (26,792) Amortized cost Trade and other payables $ (190,692) $ (190,692) $ (155,955) $ (155,955) — Credit Facilities (505,171) (506,514) (649,221) (651,173) — Long-term notes (874,527) (917,889) (1,132,868) (761,129) Level 1 Total $ (1,570,390) $ (1,615,095) $ (1,938,044) $ (1,568,257)
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, 2021 December 31, 2020 December 31, 2021 December 31, 2020 U.S. dollar denominated US$602,503 US$759,508 US$829,934 US$934,731
Disclosure of financial derivative contracts	Baytex had the following commodity financial derivative contracts outstanding as at February 24, 2022. Period Volume Price/Unit (1) Index Oil Basis swap Jan 2022 to Dec 2022 12,000 bbl/d WTI less US$12.40/bbl WCS Basis swap Jan 2022 to Dec 2022 4,000 bbl/d WTI less US$4.43/bbl MSW Basis swap (3) Feb 2022 to Jun 2022 1,000 bbl/d WTI less US$3.00/bbl MSW Basis swap (3) Mar 2022 to Dec 2022 2,000 bbl/d WTI less US$2.88/bbl MSW Fixed - Sell Jan 2022 to Dec 2022 10,000 bbl/d US$53.50/bbl WTI 3-way option (2) Jan 2022 to Dec 2022 1,500 bbl/d US$40.00/US$50.00/US$58.10 WTI 3-way option (2) Jan 2022 to Dec 2022 2,000 bbl/d US$46.00/US$56.00/US$66.72 WTI 3-way option (2) Jan 2022 to Dec 2022 2,500 bbl/d US$47.00/US$57.00/US$67.00 WTI 3-way option (2) Jan 2022 to Dec 2022 2,500 bbl/d US$50.00/US$60.00/US$70.00 WTI 3-way option (2) Jan 2022 to Dec 2022 2,000 bbl/d US$53.00/US$63.50/US$72.90 WTI 3-way option (2) Jan 2023 to Dec 2023 2,000 bbl/d US$55.00/US$66.00/US$84.00 WTI 3-way option (2)(3) Jan 2023 to Dec 2023 2,500 bbl/d US$60.00/US$75.00/US$91.54 WTI Natural Gas Fixed - Sell Jan 2022 to Dec 2022 5,000 GJ/d $2.53/GJ AECO 7A Fixed - Sell Jan 2022 to Dec 2022 14,250 GJ/d $2.84/GJ AECO 5A Fixed - Sell Jan 2022 to Dec 2022 1,000 mmbtu/d US$2.94/mmbtu NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.25/US$2.75/US$3.06 NYMEX 3-way option (2) Jan 2022 to Dec 2022 1,500 mmbtu/d US$2.60/US$2.91/US$3.56 NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.60/US$3.00/US$3.83 NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.65/US$2.90/US$3.40 NYMEX 3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$3.00/US$3.75/US$4.40 NYMEX (1) Based on the weighted average price per unit for the period. (2) Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$50.00/US$60.00/US$70.00 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. (3) Contracts entered subsequent to December 31, 2021.
Disclosure of financial derivatives marked-to-market	The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives. Years Ended December 31 2021 2020 Realized financial derivatives loss (gain) $ 184,241 $ (47,836) Unrealized financial derivatives loss 103,631 18,500 Financial derivatives loss (gain) $ 287,872 $ (29,336)
Disclosure of cash outflows relating to financial liabilities	The timing of cash outflows relating to financial liabilities as at December 31, 2021 is outlined in the table below: Total Less than 1 year 1-3 years 3-5 years Beyond 5 years Trade and other payables $ 190,692 $ 190,692 — $ — $ — Financial derivatives 134,020 134,020 — — — Credit facilities (1)(2) 506,514 — 506,514 — — Long-term notes (1)(3) 885,920 — 253,120 — 632,800 Interest on long-term notes (4) 325,172 69,608 130,868 110,740 13,956 Lease obligations (1) 8,014 3,068 3,989 902 55 $ 2,050,332 $ 397,388 $ 894,491 $ 111,642 $ 646,811 (1) Principal amount of instruments. (2) The credit facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing the Company has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024. (3) Principal amount of instruments. The US$500 million principal amount of 8.75% senior unsecured notes is due April 1, 2027 and the US$200 million principal amount of the 5.625% senior unsecured notes is due June 1, 2024 (note 8). (4) Excludes interest on credit facilities as interest payments on credit facilities fluctuate based on amounts outstanding and the prevailing interest rate at the time of borrowing.
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, 2021. Trade and Other Receivables Aging December 31, 2021 December 31, 2020 Current (less than 30 days) $ 171,058 $ 104,210 31-60 days 441 1,493 61-90 days 107 220 Past due (more than 90 days) 1,803 1,554 $ 173,409 $ 107,477

Supplemental Information (Table

Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2021
Additional information [abstract]
Changes in non-cash working capital items	Years Ended December 31 2021 2020 Trade and other receivables $ (65,932) $ 66,285 Trade and other payables 34,737 (51,499) $ (31,195) $ 14,786 Changes in non-cash working capital related to: Operating activities $ (26,582) $ 48,758 Investing activities (2,797) (32,031) Foreign currency translation on non-cash working capital (1,816) (1,941) $ (31,195) $ 14,786
Employee compensation costs	The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense. Years Ended December 31 2021 2020 Operating $ 11,053 $ 9,065 General and administrative 29,538 22,802 Total employee compensation costs $ 40,591 $ 31,867

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments And Contingencies [Abstract]
Financial obligations and expected timing	These obligations as of December 31, 2021, and the expected timing of funding of these obligations, are noted in the table below. Total Less than 1-3 years 3-5 years Beyond 5 years Processing agreements $ 6,090 753 890 530 3,917 Transportation agreements 81,182 20,500 37,825 14,673 8,184 Total $ 87,272 $ 21,253 $ 38,715 $ 15,203 $ 12,101

Related Parties (Tables)

Related Parties (Tables)	12 Months Ended
	Dec. 31, 2021
Related Party [Abstract]
Transactions with key management personnel	Transactions with key management personnel and directors are noted in the table below. Years Ended December 31 2021 2020 Short-term employee benefits $ 5,995 $ 4,295 Share-based compensation 5,917 4,080 Total compensation for key management personnel $ 11,912 $ 8,375

Capital Management (Tables)

Capital Management (Tables)	12 Months Ended
	Dec. 31, 2021
Corporate Information And Statement Of IFRS Compliance [Abstract]
Net Debt	December 31, 2021 December 31, 2020 Credit facilities $ 505,171 $ 649,221 Unamortized debt issuance costs - Credit Facilities (note 7) 1,343 1,952 Long-term notes 874,527 1,132,868 Unamortized debt issuance costs - Long-term notes (note 8) 11,393 15,082 Trade and other payables 190,692 155,955 Trade and other receivables (173,409) (107,477) Net Debt $ 1,409,717 $ 1,847,601
Adjusted Funds Flow	Adjusted Funds Flow is reconciled to amounts disclosed in the primary financial statements in the following table. Years Ended December 31 2021 2020 Cash flows from operating activities $ 712,384 $ 353,096 Change in non-cash working capital 26,582 (48,758) Asset retirement obligations settled 6,662 7,168 Adjusted Funds Flow $ 745,628 $ 311,506 Net Debt to Adjusted Funds Flow 1.9 5.9

Significant Accounting Polici_4

Significant Accounting Policies - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021
Accounting Policies, Changes In Accounting Policies And Errors [Abstract]
Maximum percentage of issuable awards to outstanding common stock	3.80%

Segmented Financial Informati_3

Segmented Financial Information - Information By Reportable Segment (Details) - CAD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020
Revenue, net of royalties
Petroleum and natural gas sales		$ 1,868,195	$ 975,477
Royalties		(339,156)	(163,735)
Revenue, net of royalties		1,529,039	811,742
Expenses
Operating		343,002	331,345
Transportation		32,261	28,437
Blending and other		85,689	48,381
General and administrative		40,804	34,268
Exploration and evaluation		15,212	14,011
Depletion and depreciation		464,580	486,380
Impairment (reversal) loss	$ 2,588,488	(1,542,414)	2,360,220
Share-based compensation		6,389	7,216
Financing and interest		111,159	125,441
Financial derivatives loss (gain)		287,872	(29,336)
Foreign exchange (gain) loss		(2,868)	8,688
(Gain) loss on dispositions		(9,666)	(901)
Other income		(2,562)	(5,304)
Total expenses		(165,801)	3,411,099
Net income (loss) before income taxes		1,694,840	(2,599,357)
Income tax (recovery) expense
Current income tax expense		1,272	574
Deferred income tax expense (recovery)		79,968	(160,967)
Income tax expense (recovery)		81,240	(160,393)
Net income (loss)		1,613,600	(2,438,964)
Additions to exploration and evaluation assets		(3,298)	(4,490)
Additions to oil and gas properties		310,005	275,850
Property acquisitions		1,557	0
Proceeds from dispositions		7,804	182
Operating segments | Canada
Revenue, net of royalties
Petroleum and natural gas sales		1,128,137	571,741
Royalties		(121,306)	(46,064)
Revenue, net of royalties		1,006,831	525,677
Expenses
Operating		257,658	247,050
Transportation		32,261	28,437
Blending and other		85,689	48,381
General and administrative		0	0
Exploration and evaluation		15,212	14,011
Depletion and depreciation		303,135	309,420
Impairment (reversal) loss		(1,100,000)	1,737,000
Share-based compensation		0	0
Financing and interest		0	0
Financial derivatives loss (gain)		0	0
Foreign exchange (gain) loss		0	0
(Gain) loss on dispositions		(9,856)	(901)
Other income		(2,857)	(2,128)
Total expenses		(418,758)	2,381,270
Net income (loss) before income taxes		1,425,589	(1,855,593)
Income tax (recovery) expense
Current income tax expense		(548)	469
Deferred income tax expense (recovery)		86,928	(77,201)
Income tax expense (recovery)		86,380	(76,732)
Net income (loss)		1,339,209	(1,778,861)
Additions to exploration and evaluation assets		3,298	4,490
Additions to oil and gas properties		204,912	170,462
Property acquisitions		1,557	0
Proceeds from dispositions		(7,211)	(182)
Operating segments | U.S.
Revenue, net of royalties
Petroleum and natural gas sales		740,058	403,736
Royalties		(217,850)	(117,671)
Revenue, net of royalties		522,208	286,065
Expenses
Operating		85,344	84,295
Transportation		0	0
Blending and other		0	0
General and administrative		0	0
Exploration and evaluation		0	0
Depletion and depreciation		155,806	169,439
Impairment (reversal) loss		(442,414)	623,220
Share-based compensation		0	0
Financing and interest		0	0
Financial derivatives loss (gain)		0	0
Foreign exchange (gain) loss		0	0
(Gain) loss on dispositions		190	0
Other income		0	0
Total expenses		(201,074)	876,954
Net income (loss) before income taxes		723,282	(590,889)
Income tax (recovery) expense
Current income tax expense		1,820	105
Deferred income tax expense (recovery)		72,913	(57,199)
Income tax expense (recovery)		74,733	(57,094)
Net income (loss)		648,549	(533,795)
Additions to exploration and evaluation assets		0	0
Additions to oil and gas properties		105,093	105,388
Property acquisitions		0	0
Proceeds from dispositions		(593)	0
Operating segments | 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		40,804	34,268
Exploration and evaluation		0	0
Depletion and depreciation		5,639	7,521
Impairment (reversal) loss		0	0
Share-based compensation		11,130	9,469
Financing and interest		111,159	125,441
Financial derivatives loss (gain)		287,872	(29,336)
Foreign exchange (gain) loss		(2,868)	8,688
(Gain) loss on dispositions		0	0
Other income		295	(3,176)
Total expenses		454,031	152,875
Net income (loss) before income taxes		(454,031)	(152,875)
Income tax (recovery) expense
Current income tax expense		0	0
Deferred income tax expense (recovery)		(79,873)	(26,567)
Income tax expense (recovery)		(79,873)	(26,567)
Net income (loss)		(374,158)	(126,308)
Additions to exploration and evaluation assets		0	0
Additions to oil and gas properties		0	0
Property acquisitions		0	0
Proceeds from dispositions		0	0
Operating segments | Consolidated
Revenue, net of royalties
Petroleum and natural gas sales		1,868,195	975,477
Royalties		(339,156)	(163,735)
Revenue, net of royalties		1,529,039	811,742
Expenses
Operating		343,002	331,345
Transportation		32,261	28,437
Blending and other		85,689	48,381
General and administrative		40,804	34,268
Exploration and evaluation		15,212	14,011
Depletion and depreciation		464,580	486,380
Impairment (reversal) loss		(1,542,414)	2,360,220
Share-based compensation		11,130	9,469
Financing and interest		111,159	125,441
Financial derivatives loss (gain)		287,872	(29,336)
Foreign exchange (gain) loss		(2,868)	8,688
(Gain) loss on dispositions		(9,666)	(901)
Other income		(2,562)	(5,304)
Total expenses		(165,801)	3,411,099
Net income (loss) before income taxes		1,694,840	(2,599,357)
Income tax (recovery) expense
Current income tax expense		1,272	574
Deferred income tax expense (recovery)		79,968	(160,967)
Income tax expense (recovery)		81,240	(160,393)
Net income (loss)		1,613,600	(2,438,964)
Additions to exploration and evaluation assets		3,298	4,490
Additions to oil and gas properties		310,005	275,850
Property acquisitions		1,557	0
Proceeds from dispositions		$ (7,804)	$ (182)

Segmented Financial Informati_4

Segmented Financial Information - Assets By Segment (Details) - CAD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [line items]
Assets	$ 4,834,643	$ 3,408,096
Operating segments | Canada
Disclosure of operating segments [line items]
Assets	2,658,281	1,646,412
Operating segments | U.S.
Disclosure of operating segments [line items]
Assets	2,152,323	1,737,533
Operating segments | Corporate
Disclosure of operating segments [line items]
Assets	$ 24,039	$ 24,151

Exploration and Evaluation As_3

Exploration and Evaluation Assets - Schedule of Assets (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of changes in intangible assets other than goodwill [abstract]
Exploration and evaluation assets, beginning of year	$ 191,865
Exploration and evaluation expense	(15,212)	$ (14,011)
Exploration and evaluation assets, end of year	172,824	191,865
Exploration and evaluation assets
Reconciliation of changes in intangible assets other than goodwill [abstract]
Exploration and evaluation assets, beginning of year	191,865	320,210
Capital expenditures	3,298	4,490
Property acquisitions	1,100	0
Divestitures	(166)	0
Property swaps	408	468
Impairment	0	(113,058)
Exploration and evaluation expense	(15,212)	(14,011)
Transfers to oil and gas properties	(7,727)	(8,585)
Foreign currency translation	(742)	2,351
Exploration and evaluation assets, end of year	$ 172,824	$ 191,865

Exploration and Evaluation As_4

Exploration and Evaluation Assets - Impairment Booked for Cash Generating Untis (Details)	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020CAD ($)cashGeneratingUnit	Jun. 30, 2021CAD ($)cashGeneratingUnit	Dec. 31, 2021CAD ($)cashGeneratingUnit	Dec. 31, 2020CAD ($)cashGeneratingUnit
Disclosure of detailed information about property, plant and equipment [line items]
Number of cash generating units | cashGeneratingUnit	6	6	5	6
Impairment loss (reversal of impairment loss) recognised in profit or loss		$ (1,126,415,000)	$ (416,000,000)
Conventional CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		(15,000,000)	(19,000,000)
Peace River CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		(154,000,000)	(251,000,000)
Lloydminster CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		(154,000,000)	(146,000,000)
Viking CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		(356,000,000)	0
Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		$ (442,415,000)	$ 0
Conventional, Peace River, Lloydminster, And Duvernay
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss				$ 0
Exploration and evaluation assets
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss on financial assets	$ 127,861,000
Exploration and evaluation assets | Conventional CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss on financial assets	4,000,000
Exploration and evaluation assets | Peace River CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss on financial assets	20,000,000
Exploration and evaluation assets | Lloydminster CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss on financial assets	42,000,000
Exploration and evaluation assets | Viking CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss on financial assets	13,000,000
Exploration and evaluation assets | Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss on financial assets	$ 48,861,000

Exploration and Evaluation As_5

Exploration and Evaluation Assets - Impairment Reversal Booked (Details) - CAD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020	Jun. 30, 2021	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		$ (1,126,415)	$ (416,000)
Reversal of impairment loss recognised in profit or loss		1,100,000		$ 341,326
Viking And Eagle Ford Cash Generating Units
Disclosure of detailed information about property, plant and equipment [line items]
Reversal of impairment loss recognised in profit or loss				341,300
Viking CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		(356,000)	0
Reversal of impairment loss recognised in profit or loss				116,000
Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss		$ (442,415)	$ 0
Reversal of impairment loss recognised in profit or loss				225,326
Exploration and evaluation assets
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss on financial assets	$ (127,861)
Exploration and evaluation assets | Viking And Eagle Ford Cash Generating Units
Disclosure of detailed information about property, plant and equipment [line items]
Reversal of impairment loss recognised in profit or loss				14,803
Exploration and evaluation assets | Viking CGU
Disclosure of detailed information about property, plant and equipment [line items]
Reversal of impairment loss recognised in profit or loss				2,000
Impairment loss on financial assets	(13,000)
Exploration and evaluation assets | Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Reversal of impairment loss recognised in profit or loss				$ 12,803
Impairment loss on financial assets	$ (48,861)

Oil and Gas Properties - Schedu

Oil and Gas Properties - Schedule of PPE Activity, Oil and Gas (Details) - CAD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of changes in property, plant and equipment [abstract]
Impairment	$ 1,126,415	$ 416,000
Oil and gas assets
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	3,077,548	3,077,548	$ 5,387,889
Capital expenditures		310,005	275,850
Property acquisitions		274
Divestitures		(4,991)
Transfers from exploration and evaluation assets		7,727	8,585
Change is asset retirement obligations		(12,222)	94,994
Property swaps		(231)	(1,012)
Impairment		1,542,414		$ (2,247,162)
Foreign currency translation		2,788	37,263
Depletion		(458,941)	(478,859)
Balance, end of year		4,464,371	3,077,548	5,387,889
Oil and gas assets | Cost
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	11,423,676	11,423,676	11,128,297
Capital expenditures		310,005	275,850
Property acquisitions		274
Divestitures		(37,835)
Transfers from exploration and evaluation assets		7,727	8,585
Change is asset retirement obligations		(12,222)	94,994
Property swaps		(26,131)	(1,190)
Impairment		0	0
Foreign currency translation		(31,977)	(82,860)
Depletion		0	0
Balance, end of year		11,633,517	11,423,676	11,128,297
Oil and gas assets | Accumulated depletion
Reconciliation of changes in property, plant and equipment [abstract]
Balance, beginning of year	$ (8,346,128)	(8,346,128)	(5,740,408)
Capital expenditures		0	0
Property acquisitions		0
Divestitures		32,844
Transfers from exploration and evaluation assets		0	0
Change is asset retirement obligations		0	0
Property swaps		25,900	178
Impairment		1,542,414	(2,247,162)
Foreign currency translation		34,765	120,123
Depletion		(458,941)	(478,859)
Balance, end of year		$ (7,169,146)	$ (8,346,128)	$ (5,740,408)

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Details)	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020CAD ($)cashGeneratingUnit	Jun. 30, 2021CAD ($)cashGeneratingUnit	Dec. 31, 2021CAD ($)cashGeneratingUnit	Dec. 31, 2020CAD ($)cashGeneratingUnit	Dec. 31, 2019CAD ($)
Disclosure of detailed information about property, plant and equipment [line items]
Number of cash generating units | cashGeneratingUnit	6	6	5	6
Number of cash generating units, with recoverable amounts | cashGeneratingUnit			3
Reversal of impairment loss recognised in profit or loss		$ 1,100,000,000		$ 341,326,000
Impairment loss (reversal of impairment loss) recognised in profit or loss		$ 1,126,415,000	$ 416,000,000
Adjusted inflation for prices and costs subsequent to 2023		0.020	0.020	0.02
Conventional CGU
Disclosure of detailed information about property, plant and equipment [line items]
Reversal of impairment loss recognised in profit or loss				$ 0
Impairment loss (reversal of impairment loss) recognised in profit or loss		$ 15,000,000	$ 19,000,000
Conventional, Peace River, Lloydminster, And Duvernay
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss				0
Viking And Eagle Ford Cash Generating Units
Disclosure of detailed information about property, plant and equipment [line items]
Reversal of impairment loss recognised in profit or loss				341,300,000
Oil and gas assets
Disclosure of detailed information about property, plant and equipment [line items]
Write-downs (reversals of write downs)			(1,500,000,000)	$ 2,200,000,000
Impairment loss (reversal of impairment loss) recognised in profit or loss			$ 1,542,414,000		$ (2,247,162,000)
Impairment	$ (2,600,000,000)
Oil and gas assets | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections	8.00%	10.00%	12.00%	10.00%
Oil and gas assets | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate applied to cash flow projections	14.00%	16.00%	19.00%	17.00%
Oil and gas assets | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss) recognised in profit or loss			$ 1,542,414,000	$ (2,247,162,000)

Oil and Gas Properties - Recove

Oil and Gas Properties - Recoverable Amount Of Company CGUs (Details) - Company's CGUs	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020usdPerBbl$ / MMBTUcadPerBbl$ / MMBTUcanadianDollarPerUsDollar	Jun. 30, 2021cadPerBbl$ / MMBTUusdPerBbl$ / MMBTU$ / $	Dec. 31, 2021usdPerBblcadPerBbl$ / MMBTU$ / $$ / MMBTU	Dec. 31, 2020$ / $usdPerBbl$ / MMBTUcadPerBbl$ / MMBTU
Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.41	1.24	1.26	1.30
Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.37	1.25	1.26	1.31
Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.34	1.25	1.26	1.31
Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.34	1.25	1.26	1.31
Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.34	1.25	1.26	1.31
Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.33	1.25	1.26	1.31
Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.33	1.25	1.26	1.31
Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.33	1.25	1.26	1.31
Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.33	1.25	1.26	1.31
Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Average foreign exchange rate (in dollars per share)	1.33	1.25	1.26	1.31
WTI | Oil reserves | Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	29.17	71.33	72.83	47.17
WTI | Oil reserves | Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	40.45	67.20	68.78	50.17
WTI | Oil reserves | Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	49.17	63.95	66.76	53.17
WTI | Oil reserves | Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	53.28	63.23	68.09	54.97
WTI | Oil reserves | Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	55.66	64.50	69.45	56.07
WTI | Oil reserves | Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	56.87	65.79	70.84	57.19
WTI | Oil reserves | Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	58.01	67.10	72.26	58.34
WTI | Oil reserves | Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	59.17	68.44	73.70	59.50
WTI | Oil reserves | Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	60.35	69.81	75.18	60.69
WTI | Oil reserves | Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	61.56	71.21	76.68	61.91
WCS | Oil reserves | Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	19.21	72.22	74.42	44.63
WCS | Oil reserves | Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	34.65	66.84	69.17	48.18
WCS | Oil reserves | Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	46.34	61.73	66.54	52.10
WCS | Oil reserves | Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	51.25	60.70	67.87	54.10
WCS | Oil reserves | Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	54.28	61.91	69.23	55.19
WCS | Oil reserves | Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	55.72	63.15	70.61	56.29
WCS | Oil reserves | Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	56.96	64.42	72.02	57.42
WCS | Oil reserves | Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	58.22	65.70	73.46	58.57
WCS | Oil reserves | Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	59.51	67.02	74.69	59.74
WCS | Oil reserves | Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	60.82	68.36	76.19	60.93
LLS | Oil reserves | Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	32.17	72.17	74.33	49.50
LLS | Oil reserves | Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	43.80	68.53	70.28	52.85
LLS | Oil reserves | Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	52.55	65.80	68.27	55.87
LLS | Oil reserves | Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	56.68	65.10	69.62	57.69
LLS | Oil reserves | Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	59.10	66.39	71.01	58.82
LLS | Oil reserves | Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	60.35	67.71	72.41	59.97
LLS | Oil reserves | Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	61.52	69.05	73.85	61.15
LLS | Oil reserves | Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	62.72	70.42	75.32	62.34
LLS | Oil reserves | Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	63.94	71.82	76.82	63.56
LLS | Oil reserves | Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | usdPerBbl	65.19	73.26	78.35	64.83
Edmonton Par | Oil reserves | Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	29.22	83.20	86.82	55.76
Edmonton Par | Oil reserves | Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	46.85	78.27	80.73	59.89
Edmonton Par | Oil reserves | Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	59.27	74.06	78.01	63.48
Edmonton Par | Oil reserves | Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	65.02	73.05	79.57	65.76
Edmonton Par | Oil reserves | Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	68.43	74.51	81.16	67.13
Edmonton Par | Oil reserves | Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	69.81	76	82.78	68.53
Edmonton Par | Oil reserves | Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	71.24	77.52	84.44	69.95
Edmonton Par | Oil reserves | Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	72.70	79.07	86.13	71.40
Edmonton Par | Oil reserves | Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	74.19	80.66	87.85	72.88
Edmonton Par | Oil reserves | Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price | cadPerBbl	75.71	82.27	89.61	74.34
Henry Hub | Oil reserves | Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				2.83
Henry Hub | Oil reserves | Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				2.87
Henry Hub | Oil reserves | Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				2.90
Henry Hub | Oil reserves | Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				2.96
Henry Hub | Oil reserves | Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				3.02
Henry Hub | Oil reserves | Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				3.08
Henry Hub | Oil reserves | Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				3.14
Henry Hub | Oil reserves | Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				3.20
Henry Hub | Oil reserves | Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				3.26
Henry Hub | Oil reserves | Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price				3.33
Henry Hub | Natural gas reserves | Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.10	3.42	3.85
Henry Hub | Natural gas reserves | Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.58	3.19	3.44
Henry Hub | Natural gas reserves | Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.79	2.92	3.17
Henry Hub | Natural gas reserves | Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.86	2.96	3.24
Henry Hub | Natural gas reserves | Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.93	3.02	3.30
Henry Hub | Natural gas reserves | Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3	3.08	3.37
Henry Hub | Natural gas reserves | Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.07	3.14	3.44
Henry Hub | Natural gas reserves | Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.13	3.21	3.50
Henry Hub | Natural gas reserves | Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.19	3.27	3.58
Henry Hub | Natural gas reserves | Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	3.25	3.34	3.65
AECO | Natural gas reserves | Year 1
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	1.74	3.46	3.56	2.78
AECO | Natural gas reserves | Year 2
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.20	3.13	3.21	2.70
AECO | Natural gas reserves | Year 3
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.38	2.72	3.05	2.61
AECO | Natural gas reserves | Year 4
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.45	2.71	3.11	2.65
AECO | Natural gas reserves | Year 5
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.53	2.76	3.17	2.70
AECO | Natural gas reserves | Year 6
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.60	2.82	3.23	2.76
AECO | Natural gas reserves | Year 7
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.66	2.88	3.30	2.81
AECO | Natural gas reserves | Year 8
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.72	2.94	3.36	2.87
AECO | Natural gas reserves | Year 9
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.79	2.99	3.43	2.92
AECO | Natural gas reserves | Year 10
Disclosure of detailed information about property, plant and equipment [line items]
Commodity sales price	2.85	3.05	3.50	2.98

Oil and Gas Properties - Sensit

Oil and Gas Properties - Sensitivity of the Estimated Recoverable Amount of Possible Changes (Details) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020CAD ($)cadPerMcf	Jun. 30, 2021CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)cadPerBblcadPerMcf
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate				1.00%
Oil price | cadPerBbl				2.50
Gas price | cadPerMcf	0.25			0.25
Recoverable amount	$ 2,974,796	$ 4,106,595	$ 4,375,103	$ 3,077,548
Impairment		1,126,415	416,000
Impairment (reversal) loss	2,588,488		(1,542,414)	2,360,220
Change in discount rate of 1%	220,750	218,900	156,200	140,600
Change in oil price of $2.50/bbl	400,500	330,900	332,300	386,000
Change in gas price of $0.25/mcf	49,000	83,900	47,300	57,400
Reversal of impairment loss recognised in profit or loss		1,100,000		341,326
Conventional CGU
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount	37,444	57,891	77,846	54,265
Impairment		15,000	19,000
Impairment (reversal) loss	41,000
Change in discount rate of 1%	3,000	1,000	0	1,000
Change in oil price of $2.50/bbl	3,500	1,000	3,000	3,000
Change in gas price of $0.25/mcf	8,500	8,000	8,000	9,000
Reversal of impairment loss recognised in profit or loss				0
Peace River CGU
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount	109,631	238,714	489,274	104,225
Impairment		154,000	251,000
Impairment (reversal) loss	345,000
Change in discount rate of 1%	9,500	4,000	8,500	1,000
Change in oil price of $2.50/bbl	53,500	40,000	53,000	49,500
Change in gas price of $0.25/mcf	3,000	2,500	3,500	3,000
Reversal of impairment loss recognised in profit or loss				0
Lloydminster CGU
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount	227,967	340,730	479,411	212,979
Impairment		154,000	146,000
Impairment (reversal) loss	470,000
Change in discount rate of 1%	25,000	12,500	12,500	7,000
Change in oil price of $2.50/bbl	69,500	52,000	52,000	57,500
Change in gas price of $0.25/mcf	0	0	0	500
Reversal of impairment loss recognised in profit or loss				0
Duvernay CGU
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount	61,197	115,157		70,491
Impairment		5,000
Impairment (reversal) loss	5,000
Change in discount rate of 1%	5,500	45,000		5,500
Change in oil price of $2.50/bbl	9,500	44,500		12,000
Change in gas price of $0.25/mcf	1,500	44,500		1,500
Reversal of impairment loss recognised in profit or loss		5,000		0
Viking CGU
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount	962,134	1,338,985	1,320,094	1,026,026
Impairment		356,000	0
Impairment (reversal) loss	915,000
Change in discount rate of 1%	57,000	47,000	38,000	34,500
Change in oil price of $2.50/bbl	123,000	89,500	85,500	106,500
Change in gas price of $0.25/mcf	4,000	4,500	4,500	5,000
Reversal of impairment loss recognised in profit or loss				116,000
Eagle Ford CGU
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount	1,576,423	2,015,118	2,008,478	1,609,562
Impairment		442,415	0
Impairment (reversal) loss	812,488
Change in discount rate of 1%	120,750	109,400	97,200	91,600
Change in oil price of $2.50/bbl	141,500	103,900	138,800	157,500
Change in gas price of $0.25/mcf	$ 32,000	$ 24,400	$ 31,300	38,400
Reversal of impairment loss recognised in profit or loss				$ 225,326

Credit Facilities - Bank Loan (

Credit Facilities - Bank Loan (Details) $ in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)
Disclosure of detailed information about borrowings [line items]
Secured bank loans received	$ 505,171		$ 649,221
Bank loan - U.S. dollar denominated
Disclosure of detailed information about borrowings [line items]
Secured bank loans received	156,332		140,815
Credit facilities - Canadian dollar denominated
Disclosure of detailed information about borrowings [line items]
Secured bank loans received	350,182		510,358
Principal
Disclosure of detailed information about borrowings [line items]
Secured bank loans received	506,514		651,173
Changes in reported amount of U.S. denominated debt	12,600
Principal | Bank loan - U.S. dollar denominated
Disclosure of detailed information about borrowings [line items]
Secured bank loans received		$ 123.5		$ 110.4
Changes in reported amount of U.S. denominated debt	700
Principal | Credit facilities - Canadian dollar denominated
Disclosure of detailed information about borrowings [line items]
Net draws	145,300
Unamortized debt issuance costs
Disclosure of detailed information about borrowings [line items]
Secured bank loans received	$ (1,343)		$ (1,952)

Credit Facilities - Additional

Credit Facilities - Additional Information (Details) $ in Millions, $ in Millions	Dec. 31, 2021USD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit		$ 15	$ 15
Revolving Facilities
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	$ 575
Term Loan
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	50
Syndicated loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	325
Subsidiary syndicated loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity	$ 200
Long-Term Notes And Credit Facilities | Weighted average [member] | Effective Interest Rate
Disclosure of detailed information about borrowings [line items]
Weighted average interest rate on Credit Facilities	2.10%	2.10%	2.40%

Credit Facilities - Financial C

Credit Facilities - Financial Covenants (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt, as defined	$ 521,500
Credit facilities	505,171	$ 649,221
Outstanding letters of credit	15,000	15,000
Bank EBITDA, as defined	836,900
Financing and interest expenses, as defined	91,800
Cost
Disclosure of detailed information about borrowings [line items]
Credit facilities	$ 506,514	$ 651,173
Position as at December 31, 2021
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt to Bank EBITDA (Maximum Ratio)	0.6
Interest Coverage (Minimum Ratio)	9.1
Covenant
Disclosure of detailed information about borrowings [line items]
Senior Secured Debt to Bank EBITDA (Maximum Ratio)	3.5
Interest Coverage (Minimum Ratio)	2

Long-Term Notes (Details)

Long-Term Notes (Details) $ in Thousands	Feb. 05, 2020CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2021USD ($)	Feb. 05, 2020USD ($)
Disclosure of detailed information about borrowings [line items]
Long-term notes		$ 874,527		$ 1,132,868
Repurchased and cancelled principal notes		251,969		833,672
Early redemption expense		4,858		6,617
Net proceeds from issuance of long-term notes	$ 652,200	0		652,150
Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes		885,920		1,147,950
Loan repayments		249,400
Changes in reported amount of U.S. denominated debt		12,600
Unamortized debt issuance costs
Disclosure of detailed information about borrowings [line items]
Long-term notes		(11,393)		(15,082)
5.625% notes due June 1, 2024
Disclosure of detailed information about borrowings [line items]
Notional amount					$ 200,000,000	$ 200,000,000
Repurchased and cancelled principal notes			$ 200,000,000
Early redemption expense		$ 1,900
5.625% notes due June 1, 2024 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate		5.625%			5.625%	5.625%
5.625% notes due June 1, 2024 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes		$ 253,120		510,200
8.75% Notes Due April 1, 2027
Disclosure of detailed information about borrowings [line items]
Notional amount					$ 500,000,000	$ 500,000,000
Transaction costs	$ 12,500
8.75% Notes Due April 1, 2027 | Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate		8.75%			8.75%	8.75%
8.75% Notes Due April 1, 2027 | Principal
Disclosure of detailed information about borrowings [line items]
Long-term notes		$ 632,800		$ 637,750

Asset Retirement Obligations -

Asset Retirement Obligations - Changes In Asset Retirement Obligations (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of changes in other provisions [Abstract]
Accretion	$ 12,381	$ 8,978
Government grants	(2,857)	(2,128)
Less current portion of asset retirement obligations	11,080	11,820
Non-current portion of asset retirement obligations	732,603	748,563
Asset retirement obligation
Reconciliation of changes in other provisions [Abstract]
Balance, beginning of the year	760,383	667,974
Liabilities incurred	14,845	15,189
Liabilities settled	(6,662)	(7,168)
Liabilities acquired from property acquisitions	249	0
Liabilities divested	(3,161)	(721)
Property swaps	(4,113)	(525)
Accretion	12,381	8,978
Government grants	(2,857)	(2,128)
Change in estimate	(9,686)	(12,771)
Changes in discount rates and inflation rates	(17,381)	92,576
Foreign currency translation	(315)	(1,021)
Balance, end of the year	$ 743,683	$ 760,383

Asset Retirement Obligations _2

Asset Retirement Obligations - Additional Information (Details) - Asset retirement obligation - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of other provisions [line items]
Estimated cash flows, undiscounted amount	$ 721,700	$ 721,000
Estimated inflation rate	1.80%	1.50%
Estimated risk free rate	1.70%	1.20%
Other provisions	$ 743,683	$ 760,383	$ 667,974
Other provisions, period of costs being incurred	60 years

Shareholders' Capital (Details)

Shareholders' Capital (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021CAD ($)sharesvote	Dec. 31, 2020CAD ($)shares
Number of Common Shares
Vesting of share awards (in shares) | shares	3,013,000	2,922,000
Changes in equity [abstract]
Beginning balance | $	$ 578,213	$ 2,947,209
Vesting of share awards | $	6,389	7,216
Ending balance | $	$ 2,211,329	$ 578,213
Shareholders’ capital
Number of Common Shares
Beginning balance (in shares) | shares	561,227,000	558,305,000
Vesting of share awards (in shares) | shares	2,986,000	2,922,000
Ending balance (in shares) | shares	564,213,000	561,227,000
Changes in equity [abstract]
Beginning balance | $	$ 5,729,418	$ 5,718,835
Vesting of share awards | $	7,175	10,583
Ending balance | $	$ 5,736,593	$ 5,729,418
Preference shares
Preferred shares without nominal or par value (in shares) | shares	10,000,000
Issued on corporate acquisition (in shares) | shares	0
Ordinary shares
Voting rights, votes per share | vote	1

Share-Based Compensation Plan -

Share-Based Compensation Plan - Additional Information (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2021CAD ($)sharesshare	Dec. 31, 2020CAD ($)sharesshare	Dec. 31, 2019shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Compensation expense related to share awards	$ 11,130,000	$ 9,469,000
Cash compensation expense related to share awards	$ 4,700,000	$ 2,300,000
Number of other equity instruments outstanding in share-based payment arrangement | shares	9,474	8,210	6,936
Granted (in shares) | shares	4,067	5,492
Current derivative financial liabilities	$ 134,020,000	$ 26,792,000
Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Payout multiplier	0.00%
Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Payout multiplier	200.00%
Incentive Award Plan
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average fair value of share awards (in cad per share)	$ 1.33	$ 1.50
Number of other equity instruments outstanding in share-based payment arrangement | share	6,400,000	2,600,000
Granted (in shares) | share	5,000,000	2,900,000
Deferred Share Unit Plan
Disclosure of terms and conditions of share-based payment arrangement [line items]
Weighted average fair value of share awards (in cad per share)	$ 1.29
Number of other equity instruments outstanding in share-based payment arrangement | share	800,000
Granted (in shares) | share	900,000
Incentive Award Plan And DSU Plan
Disclosure of terms and conditions of share-based payment arrangement [line items]
Current derivative financial assets	$ 6,500,000
Current derivative financial liabilities		$ 1,100,000
Current derivative financial assets, realized portion of swap	$ 10,700,000
Current derivative financial liabilities, realized portion of swap		1,200,000
Restricted awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of common shares entitled by restricted award | share	1
Weighted average fair value of share awards (in cad per share)	$ 1.31	$ 1.48
Number of other equity instruments outstanding in share-based payment arrangement | shares	2,093	4,122	3,801
Granted (in shares) | shares	0	2,239
Performance awards
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of other equity instruments outstanding in share-based payment arrangement | shares	7,381	4,088	3,135
Granted (in shares) | shares	4,067	3,253
Performance awards | Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of common shares entitled by restricted award | share	0
Performance awards | Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of common shares entitled by restricted award | share	2

Share-Based Compensation Plan_2

Share-Based Compensation Plan - Shares Outstanding (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Total number of share awards
Beginning balance (in shares)	8,210	6,936
Granted (in shares)	4,067	5,492
Added by performance factor (in shares)	669
Vested and converted to common shares (in shares)	(3,013)	(2,922)
Forfeited (in shares)	(459)	(1,296)
Ending balance (in shares)	9,474	8,210
Minimum
Total number of share awards
Payout multiplier	0.00%
Maximum
Total number of share awards
Payout multiplier	200.00%
Restricted awards
Total number of share awards
Beginning balance (in shares)	4,122	3,801
Granted (in shares)	0	2,239
Added by performance factor (in shares)	0
Vested and converted to common shares (in shares)	(1,861)	(1,730)
Forfeited (in shares)	(168)	(188)
Ending balance (in shares)	2,093	4,122
Performance awards
Total number of share awards
Beginning balance (in shares)	4,088	3,135
Granted (in shares)	4,067	3,253
Added by performance factor (in shares)	669
Vested and converted to common shares (in shares)	(1,152)	(1,192)
Forfeited (in shares)	(291)	(1,108)
Ending balance (in shares)	7,381	4,088

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - CAD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Net income
Net income (loss) - basic	$ 1,613,600	$ (2,438,964)
Net income (loss) - diluted	$ 1,613,600	$ (2,438,964)
Weighted average ordinary shares and adjusted weighted average ordinary shares [abstract]
Weighted average common shares - basic (in shares)	563,674,000	560,657,000
Dilutive effect of share awards (in shares)	7,936,000	0
Weighted average common shares - diluted (in shares)	571,610,000	560,657,000
Net income per share
Basic (in cad per share)	$ 2.86	$ (4.35)
Diluted (in cad per share)	$ 2.82	$ (4.35)
Instruments with potential future dilutive effect not included in calculation of diluted earnings per share	0

Petroleum and Natural Gas Sal_3

Petroleum and Natural Gas Sales (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [line items]
Petroleum and natural gas sales	$ 1,868,195	$ 975,477
Trade receivable, accrued petroleum and natural gas sales
Disclosure of operating segments [line items]
Included in accounts receivable	154,000	81,300
Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	1,128,137	571,741
U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	740,058	403,736
Light oil and condensate
Disclosure of operating segments [line items]
Petroleum and natural gas sales	1,065,834	623,585
Light oil and condensate | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	480,199	296,125
Light oil and condensate | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	585,635	327,460
Heavy oil
Disclosure of operating segments [line items]
Petroleum and natural gas sales	560,696	236,235
Heavy oil | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	560,696	236,235
Heavy oil | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	0	0
NGL
Disclosure of operating segments [line items]
Petroleum and natural gas sales	94,515	40,882
NGL | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	18,904	6,037
NGL | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	75,611	34,845
Natural gas sales
Disclosure of operating segments [line items]
Petroleum and natural gas sales	147,150	74,775
Natural gas sales | Canada
Disclosure of operating segments [line items]
Petroleum and natural gas sales	68,338	33,344
Natural gas sales | U.S.
Disclosure of operating segments [line items]
Petroleum and natural gas sales	$ 78,812	$ 41,431

Income Taxes - Provision For In

Income Taxes - Provision For Income Taxes (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Abstract]
Net income (loss) before income taxes	$ 1,694,840	$ (2,599,357)
Expected income taxes at the statutory rate	$ 425,744	$ (660,757)
Tax rate	25.12%	25.42%
Increase (Decrease) From Tax Effects [Abstract]
Share-based compensation	$ 1,605	$ 1,834
Effect of foreign exchange	(841)	1,017
Effect of change in income tax rates	(65)	10,969
Effect of rate adjustments for foreign jurisdictions	(21,746)	22,375
Effect of change in deferred tax benefit not recognized	(325,295)	444,117
Effect of U.S. tax change	0	19,807
Adjustments and assessments	1,838	245
Income tax expense (recovery)	$ 81,240	$ (160,393)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Jun. 30, 2016
Income Taxes [Abstract]
Deferred tax assets, unrecognized	$ 145,600	$ 469,700
Unrecognized deferred tax assets, capital losses	237,400
Unrecognized deferred tax assets. non-capital losses	461,100
Accumulated non-capital losses			$ 591,000
Effect of U.S. tax change	$ 0	$ 19,807

Income Taxes - Continuity of Ne

Income Taxes - Continuity of Net Deferred Income Tax Liability (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Changes in deferred tax liability (asset) [abstract]
Beginning balance	$ (86,533)	$ (235,308)
Recognized in Net Income	(79,968)	160,967
Foreign Currency Translation Adjustment	(955)	(12,192)
Ending balance	(167,456)	(86,533)
Non-capital loss carry-forwards	2,000,000	2,200,000
Petroleum and natural gas properties
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(502,625)	(881,994)
Recognized in Net Income	(257,800)	378,321
Foreign Currency Translation Adjustment	(154)	1,048
Ending balance	(760,579)	(502,625)
Financial derivatives
Changes in deferred tax liability (asset) [abstract]
Beginning balance	0	0
Recognized in Net Income	0	0
Ending balance	0	0
Other
Changes in deferred tax liability (asset) [abstract]
Beginning balance	(22,377)	(2,403)
Recognized in Net Income	624	(18,839)
Foreign Currency Translation Adjustment	137	(1,135)
Ending balance	(21,616)	(22,377)
Asset retirement obligations
Changes in deferred tax liability (asset) [abstract]
Beginning balance	187,840	164,523
Recognized in Net Income	(2,436)	23,432
Foreign Currency Translation Adjustment	(68)	(115)
Ending balance	185,336	187,840
Financial derivatives
Changes in deferred tax liability (asset) [abstract]
Beginning balance	5,410	802
Recognized in Net Income	26,082	4,608
Ending balance	31,492	5,410
Non-capital losses
Changes in deferred tax liability (asset) [abstract]
Beginning balance	241,514	386,717
Recognized in Net Income	104,479	(141,468)
Foreign Currency Translation Adjustment	(3,109)	(3,735)
Ending balance	342,884	241,514
Finance costs
Changes in deferred tax liability (asset) [abstract]
Beginning balance	3,705	97,047
Recognized in Net Income	49,083	(85,087)
Foreign Currency Translation Adjustment	2,239	(8,255)
Ending balance	$ 55,027	$ 3,705

Financing and Interest (Details

Financing and Interest (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Analysis of income and expense [abstract]
Interest on credit facilities	$ 13,300	$ 15,256
Interest on long-term notes	78,546	90,830
Interest on lease obligations	223	448
Cash interest	92,069	106,534
Early redemption expense	4,858	6,617
Accretion on asset retirement obligations	12,381	8,978
Early redemption expense	1,851	3,312
Financing and interest	$ 111,159	$ 125,441

Foreign Exchange (Details)

Foreign Exchange (Details) $ in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)
Effects Of Changes In Foreign Exchange Rates [Line Items]
Adjustments for unrealised foreign exchange losses (gains)	$ 1,905		$ (9,232)
Realized foreign exchange gain	(963)		(544)
Foreign exchange (gain) loss	(2,868)		8,688
Intercompany notes		$ 601		$ 751
Intercompany notes redeemed and cancelled				$ 150
Unrealized foreign exchange loss - intercompany notes
Effects Of Changes In Foreign Exchange Rates [Line Items]
Adjustments for unrealised foreign exchange losses (gains)	12,000		31,617
Unrealized foreign exchange gain - long-term notes & credit facilities
Effects Of Changes In Foreign Exchange Rates [Line Items]
Adjustments for unrealised foreign exchange losses (gains)	$ (13,905)		$ (22,385)

Financial Instruments and Ris_3

Financial Instruments and Risk Management - Carrying Value and Fair Value of Financial Instruments (Details) - CAD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	$ (134,020)	$ (26,792)
Liabilities, at fair value	(134,020)	(26,792)
FVTPL | Financial Derivatives | Level 2
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(134,020)	(26,792)
Liabilities, at fair value	(134,020)	(26,792)
Amortized cost
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(1,570,390)	(1,938,044)
Liabilities, at fair value	(1,615,095)	(1,568,257)
Amortized cost | Trade and other payables | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(190,692)	(155,955)
Liabilities, at fair value	(190,692)	(155,955)
Amortized cost | Credit Facilities | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(505,171)	(649,221)
Liabilities, at fair value	(506,514)	(651,173)
Amortized cost | Long-term notes | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	(874,527)	(1,132,868)
Liabilities, at fair value	(917,889)	(761,129)
FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	8,654	5,057
Financial assets, at fair value	8,654	5,057
FVTPL | Level 2
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	8,654	5,057
Financial assets, at fair value	8,654	5,057
Amortized cost
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	173,409	107,477
Financial assets, at fair value	173,409	107,477
Amortized cost | Trade and Other Receivables | Level 1
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets	173,409	107,477
Financial assets, at fair value	$ 173,409	$ 107,477

Financial Instruments and Ris_4

Financial Instruments and Risk Management - Foreign Currency Risk, Interest Rate Risk, Interest Rate Swaps and Commodity Price Risk (Details) $ in Thousands	Dec. 31, 2021CAD ($)usdPerBbl	Dec. 31, 2021USD ($)usdPerBbl	Dec. 31, 2020USD ($)
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	2,300,000
Currency risk | U.S. dollar denominated, liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
U.S. dollar denominated		$ 829,934	$ 934,731
Currency risk | U.S. dollar denominated, assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
U.S. dollar denominated		$ 602,503	$ 759,508
Interest rate risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Effect on net income	$ 5,100,000
Impact of base point change on interest rates	100.00%	100.00%
Commodity price risk | Oil Price
Disclosure of nature and extent of risks arising from financial instruments [line items]
Potential impact of crude oil price changes | usdPerBbl	1	1
Potential impact of natural gas price changes	$ 10,400,000
Commodity price risk | Natural Gas Price
Disclosure of nature and extent of risks arising from financial instruments [line items]
Potential impact of crude oil price changes | usdPerBbl	0.25	0.25
Potential impact of natural gas price changes	$ 3,700,000

Financial Instruments and Ris_5

Financial Instruments and Risk Management - Financial Derivative Contracts (Details)	Dec. 31, 2021cadPerGigajoulesmmbtuPerDaybblPerDayusdPerBblgigajoulesPerDay$ / MMBTU
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	10
Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	70
Oil Basis Swap Jan 2022 to December 2022
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	12,000
Oil Basis Swap Jan 2022 to December 2022 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	12.40
Oil Basis Swap Jan 2022 to December 2022 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	4,000
Oil Basis Swap Jan 2022 to December 2022 - 1 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	4.43
Oil Basis Swap February 2022 to June 2022
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,000
Oil Basis Swap February 2022 to June 2022 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3
Oil Basis Swap March 2022 To December 2022
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,000
Oil Basis Swap March 2022 To December 2022 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.88
Oil Fixed Sell Jan 2022 to December 2022
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	10,000
Oil Fixed Sell Jan 2022 to December 2022 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	53.50
Oil Three-Way Option Jan 2022 To Dec 2022
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	1,500
Oil Three-Way Option Jan 2022 To Dec 2022 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	40
Oil Three-Way Option Jan 2022 To Dec 2022 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Oil Three-Way Option Jan 2022 To Dec 2022 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	58.10
Oil Three-Way Option Jan 2022 To Dec 2022 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,000
Oil Three-Way Option Jan 2022 To Dec 2022 - 1 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	46
Oil Three-Way Option Jan 2022 To Dec 2022 - 1 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	56
Oil Three-Way Option Jan 2022 To Dec 2022 - 1 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66.72
Oil Three-Way Option Jan 2022 To Dec 2022 - 2
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,500
Oil Three-Way Option Jan 2022 To Dec 2022 - 2 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	47
Oil Three-Way Option Jan 2022 To Dec 2022 - 2 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	57
Oil Three-Way Option Jan 2022 To Dec 2022 - 2 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	67
Oil Three-Way Option Jan 2022 To Dec 2022 - 3
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,500
Oil Three-Way Option Jan 2022 To Dec 2022 - 3 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	50
Oil Three-Way Option Jan 2022 To Dec 2022 - 3 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Oil Three-Way Option Jan 2022 To Dec 2022 - 3 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	70
Oil Three-Way Option Jan 2022 To Dec 2022 - 4
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,000
Oil Three-Way Option Jan 2022 To Dec 2022 - 4 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	53
Oil Three-Way Option Jan 2022 To Dec 2022 - 4 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	63.50
Oil Three-Way Option Jan 2022 To Dec 2022 - 4 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	72.90
Oil Three-Way Option Jan 2023 To Dec 2023 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,000
Oil Three-Way Option Jan 2023 To Dec 2023 - 1 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	55
Oil Three-Way Option Jan 2023 To Dec 2023 - 1 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	66
Oil Three-Way Option Jan 2023 To Dec 2023 - 1 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	84
Oil Three-Way Option Jan 2023 To Dec 2023 - 2
Disclosure of detailed information about financial instruments [line items]
Volume | bblPerDay	2,500
Oil Three-Way Option Jan 2023 To Dec 2023 - 2 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	60
Oil Three-Way Option Jan 2023 To Dec 2023 - 2 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	75
Oil Three-Way Option Jan 2023 To Dec 2023 - 2 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	91.54
Natural Gas Fixed-Sell Jan 2022 to Dec 2022
Disclosure of detailed information about financial instruments [line items]
Volume | gigajoulesPerDay	5,000
Natural Gas Fixed-Sell Jan 2022 to Dec 2022 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit | cadPerGigajoules	2.53
Natural Gas Fixed-Sell Jan 2022 to Dec 2022 - 1
Disclosure of detailed information about financial instruments [line items]
Volume | gigajoulesPerDay	14,250
Natural Gas Fixed-Sell Jan 2022 to Dec 2022 - 1 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit | cadPerGigajoules	2.84
Natural Gas Fixed-Sell Jan 2022 to Dec 2022 - 2
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	1,000
Natural Gas Fixed-Sell Jan 2022 to Dec 2022 - 2 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit | $ / MMBTU	2.94
Natural Gas Three Way Option Jan 2022 to Dec 2022
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	2,500
Natural Gas Three Way Option Jan 2022 to Dec 2022 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.25
Natural Gas Three Way Option Jan 2022 to Dec 2022 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.75
Natural Gas Three Way Option Jan 2022 to Dec 2022 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3.06
Natural Gas Three Way Option Jan 2022 to Dec 2022-1
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	1,500
Natural Gas Three Way Option Jan 2022 to Dec 2022-1 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.60
Natural Gas Three Way Option Jan 2022 to Dec 2022-1 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.91
Natural Gas Three Way Option Jan 2022 to Dec 2022-1 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3.56
Natural Gas Three Way Option Jan 2022 to Dec 2022-2
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	2,500
Natural Gas Three Way Option Jan 2022 to Dec 2022-2 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.60
Natural Gas Three Way Option Jan 2022 to Dec 2022-2 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3
Natural Gas Three Way Option Jan 2022 to Dec 2022-2 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3.83
Natural Gas Three Way Option Jan 2022 to Dec 2022 -3
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	2,500
Natural Gas Three Way Option Jan 2022 to Dec 2022 -3 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.65
Natural Gas Three Way Option Jan 2022 to Dec 2022 -3 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	2.90
Natural Gas Three Way Option Jan 2022 to Dec 2022 -3 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit	3.40
Natural Gas Three Way Option Jan 2022 to Dec 2022 -4
Disclosure of detailed information about financial instruments [line items]
Volume | mmbtuPerDay	2,500
Natural Gas Three Way Option Jan 2022 to Dec 2022 -4 | Price One
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit | $ / MMBTU	3
Natural Gas Three Way Option Jan 2022 to Dec 2022 -4 | Price Two
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit | $ / MMBTU	3.75
Natural Gas Three Way Option Jan 2022 to Dec 2022 -4 | Price Three
Disclosure of detailed information about financial instruments [line items]
Derivative price/unit | $ / MMBTU	4.40

Financial Instruments and Ris_6

Financial Instruments and Risk Management - Financial Derivatives Marked-To-Market (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Financial Instruments [Abstract]
Realized financial derivatives loss (gain)	$ 184,241	$ (47,836)
Unrealized financial derivatives loss	103,631	18,500
Financial derivatives loss (gain)	$ 287,872	$ (29,336)

Financial Instruments and Ris_7

Financial Instruments and Risk Management - Liquidity Risk (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2021USD ($)	Feb. 05, 2020USD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Outstanding letters of credit	$ 15,000	$ 15,000
Credit facilities	505,171	649,221
Trade and other payables	190,692	155,955
Current derivative financial liabilities	134,020	26,792
Credit facilities	505,171	649,221
Long-term notes	874,527	1,132,868
Cost
Disclosure of nature and extent of risks arising from financial instruments [line items]
Credit facilities	506,514	651,173
Letters of credit, available amount	$ 1,000,000	$ 1,000,000
8.75% Notes Due April 1, 2027
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount			$ 500,000,000	$ 500,000,000
8.75% Notes Due April 1, 2027 | Fixed interest rate
Disclosure of nature and extent of risks arising from financial instruments [line items]
Borrowings, interest rate	8.75%		8.75%	8.75%
5.625% notes due June 1, 2024
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount			$ 200,000,000	$ 200,000,000
5.625% notes due June 1, 2024 | Fixed interest rate
Disclosure of nature and extent of risks arising from financial instruments [line items]
Borrowings, interest rate	5.625%		5.625%	5.625%
Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables	$ 190,692
Current derivative financial liabilities	134,020
Credit facilities	506,514
Long-term notes	885,920
Interest on long-term notes	325,172
Lease obligations	8,014
Financial liabilities	2,050,332
Less than 1 year | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables	190,692
Current derivative financial liabilities	134,020
Credit facilities	0
Long-term notes	0
Interest on long-term notes	69,608
Lease obligations	3,068
Financial liabilities	397,388
1-3 years | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables	0
Current derivative financial liabilities	0
Credit facilities	506,514
Long-term notes	253,120
Interest on long-term notes	130,868
Lease obligations	3,989
Financial liabilities	894,491
3-5 years | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables	0
Current derivative financial liabilities	0
Credit facilities	0
Long-term notes	0
Interest on long-term notes	110,740
Lease obligations	902
Financial liabilities	111,642
Beyond 5 years | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other payables	0
Current derivative financial liabilities	0
Credit facilities	0
Long-term notes	632,800
Interest on long-term notes	13,956
Lease obligations	55
Financial liabilities	$ 646,811

Financial Instruments and Ris_8

Financial Instruments and Risk Management - Credit Risk (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of financial assets [line items]
Current trade receivables	$ 173,409	$ 107,477
Financial assets neither past due nor impaired | Current (less than 30 days)
Disclosure of financial assets [line items]
Current trade receivables	171,058	104,210
Financial assets neither past due nor impaired | 31-60 days
Disclosure of financial assets [line items]
Current trade receivables	441	1,493
Financial assets neither past due nor impaired | 61-90 days
Disclosure of financial assets [line items]
Current trade receivables	107	220
Financial assets past due but not impaired | Past due (more than 90 days)
Disclosure of financial assets [line items]
Current trade receivables	$ 1,803	1,554
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	$ 154,000	81,300
Trade receivables
Disclosure of financial assets [line items]
Allowance for doubtful accounts	$ 2,600	$ 2,000
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, 2021	Dec. 31, 2020
Additional information [abstract]
Trade and other receivables	$ (65,932)	$ 66,285
Trade and other payables	34,737	(51,499)
Trade and other receivables/payables	(31,195)	14,786
Changes in non-cash working capital related to:
Change in non-cash working capital	(26,582)	48,758
Investing activities	(2,797)	(32,031)
Foreign currency translation on non-cash working capital	(1,816)	(1,941)
Changes in non-cash working capital	$ (31,195)	$ 14,786

Supplemental Information - Empl

Supplemental Information - Employee Compensation Costs (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	$ 40,591	$ 31,867
Operating
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	11,053	9,065
General and administrative
Disclosure Of Employee Compensation [Line Items]
Employee compensation costs	$ 29,538	$ 22,802

Commitments (Details)

Commitments (Details) $ in Thousands	Dec. 31, 2021CAD ($)
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	$ 6,090
Transportation agreements	81,182
Total	87,272
Less than 1 year
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	753
Transportation agreements	20,500
Total	21,253
1-3 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	890
Transportation agreements	37,825
Total	38,715
3-5 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	530
Transportation agreements	14,673
Total	15,203
After 5 years
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items]
Processing agreements	3,917
Transportation agreements	8,184
Total	$ 12,101

Related Parties (Details)

Related Parties (Details) - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Related Party [Abstract]
Short-term employee benefits	$ 5,995	$ 4,295
Share-based compensation	5,917	4,080
Total compensation for key management personnel	$ 11,912	$ 8,375

Capital Management - Net Debt (

Capital Management - Net Debt (Details) - CAD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about borrowings [line items]
Trade and other payables	$ 190,692	$ 155,955
Trade and other receivables	(173,409)	(107,477)
Net Debt	1,409,717	1,847,601
Unamortized debt issuance costs | Credit facilities
Disclosure of detailed information about borrowings [line items]
Borrowings	1,343	1,952
Unamortized debt issuance costs | Long-term notes
Disclosure of detailed information about borrowings [line items]
Borrowings	11,393	15,082
Cost | Credit facilities
Disclosure of detailed information about borrowings [line items]
Borrowings	(505,171)	(649,221)
Cost | Long-term notes
Disclosure of detailed information about borrowings [line items]
Borrowings	$ (874,527)	$ (1,132,868)

Capital Management - Bank EBITD

Capital Management - Bank EBITDA (Details) - CAD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020
Corporate Information And Statement Of IFRS Compliance [Abstract]
Net income (loss) - basic		$ 1,613,600	$ (2,438,964)
Financing and interest		111,159	125,441
Unrealized foreign exchange (gain) loss		(1,905)	9,232
Unrealized financial derivatives loss		103,631	18,500
Current income tax expense		1,272	574
Deferred income tax expense (recovery)		79,968	(160,967)
Depletion and depreciation		464,580	486,380
Depletion and depreciation			486,380
Gain on dispositions		(9,666)	(901)
Impairment (impairment reversal)	$ 2,588,488	(1,542,414)	2,360,220
Share-based compensation		6,389	7,216
Exploration and evaluation		15,212	14,011
Interest on lease obligations		(223)	(448)
Early redemption expense		(1,851)	(3,312)
Non-cash other income		$ (2,857)	$ (2,128)

Capital Management - Adjusted F

Capital Management - Adjusted Funds Flow (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)
Corporate Information And Statement Of IFRS Compliance [Abstract]
Cash flows from operating activities	$ 712,384	$ 353,096
Change in non-cash working capital	26,582	(48,758)
Asset retirement obligations settled	6,662	7,168
Adjusted Funds Flow	$ 745,628	$ 311,506
Net Debt to Adjusted Funds Flow	1.9	5.9