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Exhibit 99.1
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Baytex Energy Corp. (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision of our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on our assessment, we have concluded that as of December 31, 2019, our internal control over financial reporting was effective.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2019 has been audited by KPMG LLP, the Company's Independent Registered Public Accounting Firm, who also audited the Company's consolidated financial statements for the year ended December 31, 2019.

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

Management, in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board, has prepared the accompanying consolidated financial statements of the Company. Financial and operating information presented throughout this Annual Report is consistent with that shown in the consolidated financial statements.

Management is responsible for the integrity of the financial information. Internal control systems are designed and maintained to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.

KPMG LLP were appointed by the Company's Board of Directors to express an audit opinion on the consolidated financial statements. Their examination included such tests and procedures, as they considered necessary, to provide a reasonable assurance that the consolidated financial statements are presented fairly in accordance with IFRS.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility through the Audit Committee, with assistance from the Reserves Committee regarding the annual review of our petroleum and natural gas reserves. The Audit Committee meets regularly with management and the Independent Registered Public Accounting Firm to ensure that management's responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board of Directors for approval. The Audit Committee also considers the independence of KPMG LLP and reviews their fees. The Independent Registered Public Accounting Firm has access to the Audit Committee without the presence of management.


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Edward D. LaFehrRodney D. Gray
President and Chief Executive OfficerExecutive Vice President and Chief Financial Officer
Baytex Energy Corp.Baytex Energy Corp.
March 3, 2020
                       



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Baytex Energy Corp.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statements of financial position of Baytex Energy Corp. (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of loss and comprehensive loss, changes in equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its financial performance and its cash flows for the years then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 3, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Assessment of indicators of impairment or impairment reversal related to oil and gas properties

As discussed in note 3 to the consolidated financial statements, when circumstances indicate that a cash-generating unit (“CGU”) may be impaired or a previous impairment reversed, the Company compares the carrying amount of the CGU to its recoverable amount. At each reporting date, the Company analyzes indicators of impairment or impairment reversal (“impairment indicators”) for each CGU, such as significant increases or decreases in reservoir performance (which includes forecasted production volumes), forecasted royalty, operating and capital costs and forecasted oil and gas prices (collectively “reserve assumptions”) or resulting cash flows from proved and probable oil and gas reserves (“CGU reserves”). The estimation of CGU reserves involves the expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The Company engages independent reservoir engineering specialists to estimate CGU reserves, which are an input in the assessment of CGU impairment indicators. The carrying amount of the Company’s oil and gas properties as at December 31, 2019 was $5,388 million.

We identified the assessment of indicators of impairment or impairment reversal related to oil and gas properties as a critical audit matter. Changes in circumstances that could indicate a CGU may be impaired or a previous impairment reversed, required the application of complex auditor judgment. Complex auditor judgment was also required to evaluate the reserve assumptions used by the Company in their assessment.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s impairment indicators assessment process, including controls related to the assessment of reserve assumptions and resulting cash flows of CGU reserves. We evaluated changes in circumstances to the Company or CGUs identified by the Company against evidence obtained through other procedures. We evaluated the competence, capabilities and



objectivity of the independent reservoir engineering specialists, who estimated CGU reserves. We evaluated the methodology used by the independent reservoir engineering specialists to estimate CGU reserves for compliance with regulatory standards. We compared current year actual CGU production volumes, royalty, operating and capital costs to the respective reserve assumptions used in the prior year estimate of proved reserves by CGU to assess the Company’s ability to accurately forecast. We compared the forecasted commodity prices used in the current year estimate of CGU reserves to those published by independent reservoir engineering companies. We compared the forecasted production volumes and forecasted royalty, operating and capital costs assumptions used in the current year estimate of CGU reserves to historical results.

Assessment of the recoverable amount of the Peace River cash generating unit

As discussed in note 7 to the consolidated financial statements, the Company recorded an impairment charge of $180 million related to the Peace River CGU. The Company identified an indicator of impairment at December 31, 2019 for the Peace River CGU and performed an impairment test to determine the recoverable amount of the CGU. The determination of recoverable amount of the CGU involves a number of estimates, including cash flows associated with proved and probable oil and gas reserves of the Peace River CGU (“Peace River CGU reserves”) and discount rate. The estimation of Peace River CGU reserves involves the expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The Company engages independent reservoir engineering specialists to estimate the Peace River CGU reserves.

We identified the assessment of the recoverable amount of the Peace River CGU as a critical audit matter. Complex auditor judgment was required to assess the Company’s estimate of Peace River CGU reserves and discount rate, which were inputs to the calculation of recoverable amount of the Peace River CGU. Auditor judgment was also required to evaluate the reserve assumptions used to estimate Peace River CGU reserves.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s determination of the recoverable amount of the Peace River CGU, including controls related to the development of the discount rate and the assessment of reserve assumptions and resulting cash flows of the Peace River CGU reserves. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists, who estimated the Peace River CGU reserves. We evaluated the methodology used by the independent reservoir engineering specialists to estimate the Peace River CGU reserves for compliance with regulatory standards. We compared current year actual CGU production volumes, royalty, operating and capital costs to the respective reserve assumptions used in the prior year estimate of the proved reserves for the Peace River CGU to assess the Company’s ability to accurately forecast. We compared the forecasted commodity prices used in the current year estimate of the Peace River CGU reserves to those published by independent reservoir engineering companies. We compared the forecasted production volumes and forecasted royalty, operating and capital costs assumptions used in the current year estimate of the Peace River CGU reserves to historical results. We involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the Company’s discount rate, by comparing it against publicly available market and other external data. The valuation specialist estimated the recoverable amount of the Peace River CGU using the estimated of the cash flow associated with the Peace River CGU reserves and the Company’s discount rate evaluated by the specialist and compared the results to market and other external pricing data.

Assessment of the impact of estimated oil and gas reserves on depletion expense related to oil and gas properties

As discussed in note 3 to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-of-production method by depletable area. Under such method, capitalized costs are depleted over estimated proved and probable oil and gas reserves by depletable area (“area reserves”). For the year ended December 31, 2019, the Company recorded depletion expense related to oil and gas properties of $725 million. The estimation of area reserves requires the expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The Company engages independent reservoir engineering specialists to estimate the area reserves.

We identified the assessment of the impact of estimated area reserves on depletion expense related to oil and gas properties as a critical audit matter. Complex auditor judgment was required to assess the Company’s estimate of area reserves and the underlying reserve assumptions.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s calculation of depletion expense, including controls over the assessment of reserve assumptions and the resulting area reserves. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists, who estimate area reserves. We evaluated the methodology used by the independent reservoir engineering specialists to estimate area reserves for compliance with regulatory standards. We compared current year actual area production volumes, royalty, operating and capital costs to respective reserve assumptions used in the prior year estimate of proved reserves by area to assess the Company’s ability to accurately forecast. We compared the forecasted commodity prices used in the current year estimate of area reserves to those published by independent reservoir engineering firms. We compared the forecasted production volumes and forecasted royalty, operating and capital costs assumptions used in the current year estimate of area reserves to historical results.





We have served as the Company’s auditor since 2016.

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Chartered Professional Accountants
Calgary, Canada
March 3, 2020




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors
Baytex Energy Corp.:

Opinion on Internal Control Over Financial Reporting

We have audited Baytex Energy Corp.’s (the Company) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as of December 31, 2019 and 2018, and the related consolidated statements of loss, comprehensive loss, changes in equity, and cash flows for the years then ended, and related notes (collectively, the consolidated financial statements), and our report dated March 3, 2020 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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Chartered Professional Accountants
Calgary, Canada
March 3, 2020





Baytex Energy Corp.
Consolidated Statements of Financial Position
(thousands of Canadian dollars)
As atNotesDecember 31, 2019December 31, 2018
ASSETS
Current assets
Cash$5,572  $  
Trade and other receivables173,762  111,564  
Financial derivatives5,433  79,582  
184,767  191,146  
Non-current assets
Exploration and evaluation assets6320,210  358,935  
Oil and gas properties75,387,889  5,817,889  
Other plant and equipment87,598  9,228  
Lease assets913,619  —  
$5,914,083  $6,377,198  
LIABILITIES
Current liabilities
Trade and other payables$207,454  $258,114  
Lease obligations95,798  —  
Financial derivatives8,668    
Onerous contracts  1,986  
Asset retirement obligations1211,579    
233,499  260,100  
Non-current liabilities
Bank loan 10505,412  520,700  
Long-term notes 111,328,175  1,583,240  
Lease obligations98,085  —  
Asset retirement obligations12656,395  646,898  
Deferred income tax liability 17235,308  310,836  
2,966,874  3,321,774  
SHAREHOLDERS’ EQUITY
Shareholders' capital 135,718,835  5,701,516  
Contributed surplus 17,712  19,137  
Accumulated other comprehensive income556,224  667,874  
Deficit (3,345,562) (3,333,103) 
2,947,209  3,055,424  
$5,914,083  $6,377,198  

Commitments and contingencies (note 22)
Subsequent events (notes 10 and 11)


See accompanying notes to the consolidated financial statements.

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Naveen DarganGregory K. Melchin
Director, Baytex Energy Corp.Director, Baytex Energy Corp.

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Baytex Energy Corp.
Consolidated Statements of Loss and Comprehensive Loss
(thousands of Canadian dollars, except per common share amounts)
Years Ended December 31Notes2019  2018  
Revenue, net of royalties
Petroleum and natural gas sales 16$1,805,919  $1,428,870  
Royalties(320,241) (313,754) 
1,485,678  1,115,116  
Expenses
Operating397,716  311,592  
Transportation43,942  36,869  
Blending and other68,795  68,832  
General and administrative45,469  45,825  
Transaction costs4  13,074  
Exploration and evaluation 611,764  21,729  
Depletion and depreciation 7, 8, 9731,686  558,684  
Impairment6, 7187,822  285,341  
Share-based compensation 1415,894  19,534  
Financing and interest 18125,865  119,086  
Financial derivatives loss (gain)207,197  (43,550) 
Foreign exchange (gain) loss19(61,787) 108,294  
Gain on dispositions(2,238) (1,946) 
Other income(7,526) (1,172) 
1,564,599  1,542,192  
Net loss before income taxes(78,921) (427,076) 
Income tax expense (recovery)17
Current income tax expense (recovery)2,093  (35) 
Deferred income tax recovery(68,555) (101,732) 
(66,462) (101,767) 
Net loss attributable to shareholders$(12,459) $(325,309) 
Other comprehensive income (loss)
Foreign currency translation adjustment(111,650) 204,770  
Comprehensive loss$(124,109) $(120,539) 
Net loss per common share15
Basic$(0.02) $(0.93) 
Diluted$(0.02) $(0.93) 
Weighted average common shares 15
Basic557,048  351,542  
Diluted557,048  351,542  

See accompanying notes to the consolidated financial statements.

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Baytex Energy Corp.
Consolidated Statements of Changes in Equity
(thousands of Canadian dollars)
NotesShareholders’
capital
Contributed
surplus
Accumulated
other
comprehensive
income
DeficitTotal equity  
Balance at December 31, 2017$4,443,576  $15,999  $463,104  $(3,007,794) $1,914,885  
Issued on corporate acquisition41,238,995  3,100  —  —  1,242,095  
Issuance costs, net of tax4, 13(551) —  —  —  (551) 
Vesting of share awards1319,496  (19,496) —  —    
Share-based compensation14—  19,534  —  —  19,534  
Comprehensive income (loss)—  —  204,770  (325,309) (120,539) 
Balance at December 31, 2018$5,701,516  $19,137  $667,874  $(3,333,103) $3,055,424  
Vesting of share awards1317,319  (17,319) —  —    
Share-based compensation14—  15,894  —  —  15,894  
Comprehensive loss—  —  (111,650) (12,459) (124,109) 
Balance at December 31, 2019$5,718,835  $17,712  $556,224  $(3,345,562) $2,947,209  

See accompanying notes to the consolidated financial statements.
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Baytex Energy Corp.
Consolidated Statements of Cash Flows
(thousands of Canadian dollars)
Years Ended December 31Notes2019  2018  
CASH PROVIDED BY (USED IN):
Operating activities
Net loss$(12,459) $(325,309) 
Adjustments for:
Share-based compensation 1415,894  19,534  
Unrealized foreign exchange (gain) loss19(62,753) 106,143  
Exploration and evaluation 611,764  21,729  
Depletion and depreciation 7, 8, 9731,686  558,684  
Impairment 6, 7187,822  285,341  
Non-cash financing and accretion1818,448  14,768  
Unrealized financial derivatives loss (gain)2082,817  (116,715) 
Gain on dispositions(2,238) (1,946) 
Deferred income tax recovery17(68,555) (101,732) 
Payments on onerous contracts   (588) 
Asset retirement obligations settled 12(15,417) (14,035) 
Change in non-cash working capital21(52,070) 39,448  
834,939  485,322  
Financing activities
Decrease in bank loan10(7,775) (21,295) 
Common share issuance costs13  (755) 
Payments on lease obligations9(5,956) —  
Redemption of long-term notes 11(198,128)   
(211,859) (22,050) 
Investing activities
Additions to exploration and evaluation assets6(2,948) (10,567) 
Additions to oil and gas properties7(549,343) (485,154) 
Additions to other plant and equipment8(552) (1,804) 
Property acquisitions (3,667) (701) 
Proceeds from dispositions1,487  2,519  
Change in non-cash working capital21(62,485) 32,435  
(617,508) (463,272) 
Change in cash5,572    
Cash, beginning of year    
Cash, end of year$5,572  $  
Supplementary information
Interest paid$112,241  $104,821  
Income taxes paid$1,160  $  

See accompanying notes to the consolidated financial statements.
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Baytex Energy Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2019 and 2018
(all tabular amounts in thousands of Canadian dollars, except per common share amounts)

1.REPORTING ENTITY
Baytex Energy Corp. (the “Company” or “Baytex”) is an oil and gas corporation engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and the United States. The Company’s common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

2.BASIS OF PRESENTATION
The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). The significant accounting policies set forth below were consistently applied to all periods presented except for the adoption of IFRS 16 Leases as discussed in note 3.

The consolidated financial statements were approved by the Board of Directors of Baytex on March 3, 2020.

The consolidated financial statements have been prepared on a historical cost basis, with the exception of certain fair value measurements noted in the accounting policies set forth below. The consolidated financial statements are presented in Canadian dollars which is the presentation currency of the Company. References to “US$” are to United States ("U.S.") dollars. All financial information is rounded to the nearest thousand, except per share amounts or where otherwise indicated.

Measurement Uncertainty and Judgments

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available to the Company at the time of financial statement preparation. Actual results can differ from those estimates as the effect of future events cannot be determined with certainty. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below.

Reserves

The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion and in the determination of fair value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by independent reserves evaluators and represent the estimated recoverable quantities of oil, natural gas and NGL and the related net cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the Canadian Oil and Gas Evaluation Handbook.

Estimates of economically recoverable oil, natural gas and NGL and their future net cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forward price forecasts, production rates, ultimate reserve recovery, timing and amount of capital expenditures, production costs, marketability of oil and natural gas, royalty rates and other geological, economic and technical factors could have a significant impact on reported reserves. Changes in the Company's reserves estimates can have a significant impact on the carrying values of the Company's oil and gas properties, the calculation of depletion, the timing of cash flows for asset retirement obligations, asset impairments and estimates of fair value determined in accounting for business combinations.

Cash-generating Units ("CGUs")

The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash flows that are largely independent of the cash flows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk.

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Identification of Impairment and Impairment Reversal Indicators

Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. The assessment for each CGU considers significant changes in reservoir performance including forecasted production volumes, forecasted royalty, operating, capital and abandonment and reclamation costs, forecasted oil and gas prices and the resulting cash flows from proved plus probable oil and gas reserves.

Measurement of Recoverable Amount

If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves, the discount rate used to present value future cash flows and assumptions regarding the timing and amount of capital expenditures and future abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets.

Exploration and Evaluation ("E&E") Assets

Costs associated with acquiring oil and natural gas licenses and exploratory drilling are accumulated as E&E assets pending determination of technical feasibility and commercial viability. The determination of technical feasibility and commercial viability of E&E assets for the purposes of reclassifying such assets to oil and gas properties is subject to management judgment. Management uses the establishment of commercial reserves as the basis for determining technical feasibility and commercial viability. Upon determination of commercial reserves, E&E assets are tested for impairment and reclassified to oil and natural gas properties.

Business Combinations

Business combinations are accounted for using the acquisition method of accounting when the assets acquired meet the definition of a business in accordance with IFRS.

Determination of the acquirer in a business combination requires management judgment. In determining the acquirer in a business combination, factors such as voting rights of all equity instruments, the intended corporate governance structure, composition of senior management of the combined company, and various metrics used to evaluate the relative size of each company are considered.

The determination of fair value assigned to assets acquired and liabilities assumed requires management to make assumptions and estimates including forecast benchmark commodity prices, estimates of reserves acquired and discount rates used to present value future cash flows. Changes in any of the assumptions or estimates used in determining the fair value of assets acquired and liabilities assumed could impact the amounts assigned to assets, liabilities and goodwill.

Financial Derivatives

Financial derivatives are measured at fair value on each reporting date. The Company uses quoted commodity prices, estimates of future volatility prices and interest rates available at period end to determine the fair value of outstanding financial derivatives. Changes in market pricing between period end and settlement of the derivative contracts could have a significant impact on financial results related to the financial derivatives.

Asset Retirement Obligations

The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim the wells and the facilities, the estimated time period during which these costs will be incurred in the future, and discount and inflation rates. The provision for asset retirement obligations represents management's best estimate of the present value of the future abandonment and reclamation costs required under current regulatory requirements. Actual abandonment and reclamation costs could be materially different from estimated amounts.

Income Taxes

Regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. Interpretation and application of existing regulation and legislation requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes. Estimates of future income taxes are subject to measurement uncertainty.

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3.SIGNIFICANT ACCOUNTING POLICIES
Changes in significant accounting policies

Leases

Baytex adopted IFRS 16 Leases on January 1, 2019, using the modified retrospective approach. The modified retrospective approach does not require restatement of comparative financial information as it recognizes the cumulative effect on transition as an adjustment to opening retained earnings and applies the standard prospectively. Comparative information in the Company's consolidated statements of financial position, consolidated statements of loss and comprehensive loss, consolidated statements of changes in equity, and consolidated statements of cash flows has not been restated and continues to be accounted for in accordance with the Company's previous accounting policy found in the 2018 annual financial statements.

The cumulative effect of initial application of the standard was to recognize an $18.0 million increase to right-of-use assets ("lease assets"), a $2.0 million reduction of onerous contracts and a $18.0 million increase to lease obligations. Initial measurement of the lease obligation was determined based on the remaining lease payments at January 1, 2019 using a weighted averaged incremental borrowing rate of approximately 3.9%. The lease assets were initially recognized at an amount equal to the lease obligations. The lease assets and lease obligations recognized largely relate to the Company's head office lease in Calgary.

The adoption of IFRS 16 using the modified retrospective approach allowed the Company to use the following practical expedients in determining the opening transition adjustment:

The weighted average incremental borrowing rate in effect at January 1, 2019 was used as opposed to the rate in effect at inception of the lease;
Leases with a remaining term of less than 12 months as at January 1, 2019 were accounted for as short-term leases;
Leases with an underlying asset of low value are recorded as an expense and not recognized as a lease asset;
Leases with similar characteristics were accounted for as a portfolio using a single discount rate; and
Used the Company's previous assessment under IAS 37, "Provisions, Contingent Liabilities and Contingent Assets' for onerous contracts instead of reassessing the lease assets for impairment at January 1, 2019.

Significant accounting policies

Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany balances and transactions are eliminated in preparation of the consolidated financial statements.

Many of the Company's exploration, development and production activities are conducted through joint arrangements. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by joint arrangements.

Business Combinations

Business combinations are accounted for using the acquisition method of accounting when the acquired assets meet the definition of a business under IFRS. The cost of an acquisition is measured as cash paid and the fair value of assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair value of the net identifiable assets acquired is recognized as goodwill. If the cost of acquisition is below the fair values of the identifiable net assets acquired, the difference is recognized as a bargain purchase gain in net income or loss. Associated transaction costs are expensed when incurred.

Revenue Recognition

Revenue from the sale of light oil and condensate, heavy oil, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon.

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The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis when Baytex acts in the capacity of an agent rather than as a principal.

The transaction price for variable price contracts in the Canadian and U.S. operating segments is based on a representative commodity price index, and may include adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period.

Tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.

Exploration and Evaluation Assets

Pre-license costs, including certain geological, geophysical and seismic expenditures, are incurred before the legal rights to explore a specific area have been obtained. These costs are charged to exploration expense in the period in which they are incurred.

Once the legal right to explore has been acquired, costs directly associated with an exploration program are capitalized as an intangible asset until results of the exploration program have been evaluated. Costs capitalized as E&E assets include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing of initial production results.

E&E costs are subject to technical, commercial and management review to confirm the continued intent to develop or otherwise extract the underlying reserves. The technical feasibility and commercial viability of extracting petroleum and natural gas resources is dependent on the existence of economically recoverable reserves for the project. If the asset is determined not to be technically feasible or commercially viable the accumulated E&E costs associated with the exploration project are charged to E&E expense in the period the determination is made.

Upon determination of technical feasibility and commercial viability, as evidenced by the classification of proved or probable reserves and management's intention to develop the E&E asset, the accumulated costs associated with the exploration project are tested for impairment and transferred to oil and gas properties.

Oil and Gas Properties
Items of oil and gas properties are initially recorded at cost. The initial cost of oil and gas properties includes the costs to acquire developed or producing oil and gas properties, and to develop oil and gas properties, such as costs of completing geological and geophysical surveys, drilling development wells, and the costs to construct and install development infrastructure such as wellhead equipment and processing facilities.

Oil and gas properties includes costs related to planned major inspection, overhaul and turnaround activities to maintain items of oil and gas properties and benefit future years of operations. Replacements outside of a major inspection, overhaul or turnaround are recognized as oil and gas properties when it is probable the future economic benefits of the replacement will be realized by the Company. The carrying amount of any replaced or disposed item of oil and gas properties is derecognized. Repair and maintenance costs incurred for servicing an item of oil and gas properties is recorded as operating expense as incurred.

Depletion and Depreciation

The costs associated with an item of oil and gas properties are depleted on a unit-of-production basis by depletable area over proved plus probable reserves once commercial production has commenced. Future development costs required to bring those reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil equivalent.

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The depreciation methods and estimated useful lives for other plant and equipment are as follows:
ClassificationMethodRate or period
Motor VehiclesDiminishing balance15 
Office EquipmentDiminishing balance20 
Computer HardwareDiminishing balance30 
Furniture and FixturesDiminishing balance10 
Leasehold ImprovementsStraight-line over life of the leaseVarious
Other AssetsDiminishing balanceVarious

The expected lives of other plant and equipment are reviewed on an annual basis and, if necessary, changes in expected useful lives are accounted for prospectively.

Impairment

Non-derivative financial assets

The Company assesses non-derivative financial assets at each reporting date to determine whether there is any objective evidence indicating that it is impaired. Objective evidence exists if one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows.

An impairment loss is reversed when there is objective evidence that the value of the financial assets has been partially or fully restored. For financial assets measured at amortized cost the reversal is recognized in net income or loss.

Non-financial assets

The Company reviews its non-financial assets, other than E&E assets, for indicators of impairment and impairment reversal at the end of each reporting period. The recoverable amount of the asset is estimated if indicators of impairment or impairment reversal exist. E&E assets are assessed for impairment when they are reclassified to oil and gas properties and if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

When reviewing for indicators of impairment and impairment reversal, and testing for impairment when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows includes CGU production volumes, royalty obligations, operating costs, capital costs, forecast commodity prices, along with inflation and discount rates used to estimate present value. FVLCD is determined as the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction between willing parties. In determining FVLCD, recent market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a discount rate that reflects current market assessments of the time value of money.

Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment reduces the carrying amount of any goodwill allocated to the CGU first, with any remaining impairment being allocated to the individual assets in the CGU on a pro-rata basis.

Impairments may be reversed for all CGUs and individual assets, other than goodwill, when there is indication that a previously recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. An impairment may be reversed only to the extent that the asset’s revised carrying amount does not exceed the carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized. Impairment recognized in relation to goodwill is not reversed for subsequent increases in its recoverable amount.

Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal occurs.

Leases

A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. A lease obligation and corresponding right-of-use asset ("lease asset") are recognized at the commencement of the lease. The present value of the lease obligation is based on the future lease payments and is discounted using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with similar characteristics. The lease asset is recognized at the amount of the lease
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obligation, adjusted for lease incentives received and initial direct costs, on commencement of the lease. Depreciation is recognized on the lease asset over the shorter of the estimated useful life of the asset or the lease term.

Lease payments are allocated between the liability and interest expense. Interest expense is recognized on the lease obligations using the effective interest rate method and payments are applied against the lease obligation.

Management judgement is required to determine the discount rate used to calculate the present value of the lease obligation. The carrying amounts of the lease assets, lease obligations, and the resulting interest and depletion and depreciation expense are based on the implicit interest rate within the lease arrangement or, if this information is unavailable, the incremental borrowing rate. Incremental borrowing rates are based on judgments including economic environment, term, and the underlying risk inherent to the asset.

Asset Retirement Obligations

The Company recognizes asset retirement obligations when it has a legal or constructive obligation as a result of past events, it is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The Company’s asset retirement obligations are based on its net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and the facilities using existing technology and the estimated time period during which these costs will be incurred in the future.

Asset retirement obligations are recognized for future asset retirement costs associated with the abandonment and reclamation of the Company's E&E assets and oil and gas properties. Asset retirement obligations are measured at the present value of management's best estimate of the future cash flows required to settle the present obligation, using the risk-free interest rate. The present value of the liability is capitalized as part of the cost of the related asset and depleted over its useful life. The asset retirement obligation is accreted until the date of expected settlement of the retirement obligation and is recognized within finance expense in the statements of income or loss. Changes in the future cash flow estimates resulting from revisions to the estimated timing or amount of undiscounted cash flows or the discount rates are recognized as changes in the asset retirement obligation provision and related asset at each reporting date.

Foreign Currency Translation

Foreign transactions

Transactions completed in currencies other than the functional currency are translated into the functional currency at the exchange rates prevailing at the time of the transactions. Foreign currency assets and liabilities are translated to functional currency at the period-end exchange rate. Revenue and expenses are translated to functional currency using the average exchange rate for the period. Realized and unrealized gains and losses resulting from the settlement or translation of foreign currency transactions are included in net income or loss.

Foreign operations

The functional currency of the Company's subsidiaries is the currency of the primary economic environment in which the entity operates. Certain subsidiaries of the Company operate and transact primarily in currencies other than the Canadian dollar. The designation of a subsidiary's functional currency is a management judgment based on the currency of the primary economic environment in which the subsidiary operates.

The financial statements of each entity are translated into Canadian dollars in preparation of the Company's consolidated financial statements. The assets and liabilities of a foreign operation are translated to Canadian dollars at the period-end exchange rate. Revenues and expenses of foreign operations are translated to Canadian dollars using the average exchange rate for the period. Foreign exchange differences are recognized in other comprehensive income or loss.

If the Company or any of its entities disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign operation are recognized in net income or loss.

Financial Instruments

IFRS 9 contains three principal classification categories for initial classification of financial assets: measured at amortized cost; fair value through other comprehensive income (“FVOCI”); or fair value through profit or loss (“FVTPL”). Financial assets are categorized based on the Company’s objective for the asset and the contractual cash flows. A financial asset is classified as amortized cost if the asset is held with the objective to collect contractual cash flows that are solely payments of principal and interest on principal amounts outstanding. A financial asset is classified as FVOCI if the asset is held with the objective to both collect contractual cash flows and sell the financial asset. All other financial assets are measured at FVTPL. Financial assets are
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assessed for impairment using an expected credit loss model. Trade and other receivables are classified and measured at amortized cost.

The measurement categories for each class of financial asset and financial liability is set forth in the following table.
Financial InstrumentClassification
Cash and cash equivalentsAmortized cost
Trade and other receivablesAmortized cost
Financial derivativesFair value through profit or loss
Trade and other payablesAmortized cost
Bank loanAmortized cost
Long-term notesAmortized cost
Lease obligationsAmortized cost

An embedded derivative is a component of a contract that modifies the cash flows of the contract. These hybrid contracts consist of a host contract and an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative unless the economic characteristics and risks of the embedded derivative are closely related to the host contract. The embedded derivatives are measured at FVTPL.

Debt issuance costs related to the amendment our bank loan or the issuance of long term notes are capitalized and amortized as financing costs over the term of the credit facilities or long term notes. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract.

The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The risk management policy permits the use of certain derivative financial instruments, including swaps and collars, to manage these fluctuations. All transactions of this nature entered into by the Company are related to underlying financial instruments or future petroleum and natural gas production. These instruments are classified as FVTPL. The Company does not use financial derivatives for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments by recording an asset or liability on the statements of financial position and recognizing changes in the fair value of the instrument in the statements of income or loss for the current period. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or loss when incurred.

The Company has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are recognized in revenue in the period the product is delivered to the sales point.

Impairment of financial assets is determined by calculating the expected credit loss ("ECL"). The Company measures an ECL allowance for trade and other receivables. The Company determines the ECL which is the probability of default events related to the financial asset by using historical realized bad debts and forward looking information. The carrying amounts of financial assets are reduced by the amount of the ECL through an allowance account and losses are recognized in the statement of income or loss.

Fair Value of Financial Instruments

Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments:

Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.
Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.
Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

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Income Taxes

Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized directly in equity, in which case the current and deferred taxes are also recognized directly in equity.

Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes the financial statement impact of a tax filing position when it is probable that the position will be sustained upon audit. The liability is measured based on an assessment of possible outcomes and their associated probabilities.

The Company follows the balance sheet asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all temporary differences deductible to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs.

Share-based Compensation Plans

The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards (collectively, "share awards") may be granted to the directors, officers and employees of the Company and its subsidiaries. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plans of the Company) shall not at any time exceed 3.8% of the then-issued and outstanding common shares.

Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus dividend equivalents). Each performance award entitles the holder to be issued the number of common shares designated in the performance award (plus dividend equivalents) multiplied by a payout multiplier. Expenses related to the Share Award Incentive Plan are determined based on the fair value of the share awards on the grant date which is based on quoted market prices for the Company's common shares. Both restricted and performance awards are expensed over the vesting period using the graded vesting method. The payout multiplier is dependent on the performance of the Company relative to pre-defined corporate performance measures for a particular period. In the case of both restricted and performance awards, the number of common shares to be issued on the applicable issue date is adjusted to account for the payments of dividends from the grant date to the applicable issue date.

The Company assumed share awards and share options pursuant to a business combination in 2018 (note 4). The share options were valued at the closing date of the transaction utilizing a Black-Scholes pricing model to value the share options. The share awards were valued at fair value using the quoted market price of the Company's common shares on the closing date of the transaction. The share awards assumed consist of restricted share awards and performance share awards with a fixed multiplier of 1.0. Share-based compensation is expensed over the remaining vesting period and recognized as share-based compensation expense, with a corresponding increase to contributed surplus.

.

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4.BUSINESS COMBINATION
On August 22, 2018, Baytex completed a plan of arrangement whereby Baytex acquired, directly and indirectly, all of the issued and outstanding common shares of Raging River Exploration Inc. (“Raging River”), a publicly traded oil and gas producer with light oil producing properties in southwest Saskatchewan and Alberta.

The acquisition was accounted for as a business combination whereby the net assets acquired and liabilities assumed were recorded at fair value at the acquisition date. Consideration consisted of the issuance of 315.3 million Baytex common shares valued at approximately $1.2 billion (based on the closing price of Baytex’s common shares of $3.93 on the Toronto Stock Exchange on August 22, 2018). The fair value of oil and gas properties acquired was determined using estimates of proved plus probable reserves evaluated at December 31, 2018 by an independent reserves evaluator and adjusted for operations between August 22, 2018 and the effective date of the reserve evaluation. Asset retirement obligations were determined using internal estimates of the timing and estimated costs associated with the abandonment and reclamation of the wells and facilities acquired using a market discount rate of 7.5%.The fair value of exploration and evaluation properties was estimated with reference to recent land sales in similar areas.

The total consideration paid and estimates of the fair value of the assets acquired and liabilities assumed as at the date of the acquisition are set forth in the table below.
Consideration
Common shares issued$1,238,995  
Share-based compensation(1)
3,100  
Total consideration$1,242,095  
Fair value of net assets acquired
Exploration and evaluation assets$97,858  
Oil and gas properties1,748,368  
Working capital deficiency excluding bank debt and financial derivatives(46,773) 
Financial derivatives(5,548) 
Bank debt(2)
(316,800) 
Asset retirement obligations(39,960) 
Deferred income tax liability(195,050) 
Net assets acquired$1,242,095  
(1)Following closing of the transaction, holders of units outstanding under Raging River's share-based compensation plans were entitled to Baytex common shares rather than Raging River common shares with adjustment to the exercise price or quantity outstanding based on the exchange ratio for the Raging River shares. As a result, the fair value assigned to the service period that had occurred prior to closing was recognized by Baytex as additional consideration (see note 14).
(2)On August 22, 2018, Baytex amended its credit facilities to include the credit facility assumed in conjunction with the acquisition of Raging River and converted outstanding principal amounts to a non-revolving term loan.

The acquisition contributed revenue of $158.8 million and operating income of $98.6 million for the period from the acquisition date of August 22, 2018 to December 31, 2018. Had the acquisition occurred on January 1, 2018, revenue would have increased by $379.5 million and operating income would have increased by $273.2 million for the year. Operating income is defined as revenue, net of royalties, less operating, transportation and blending expense.

In 2018, transaction costs of $13.1 million were expensed as incurred and share issuance costs of $0.6 million (net of taxes of $0.2 million) were recorded in shareholders' capital in the year.

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5.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.
CanadaU.S.CorporateConsolidated
Years Ended December 312019  20182019  20182019  20182019  2018
Revenue, net of royalties
Petroleum and natural gas sales $1,077,724  $619,215  $728,195  $809,655  $  $  $1,805,919  $1,428,870  
Royalties(107,467) (72,700) (212,774) (241,054)     (320,241) (313,754) 
970,257  546,515  515,421  568,601      1,485,678  1,115,116  
Expenses
Operating298,303  221,717  99,413  89,875      397,716  311,592  
Transportation43,942  36,869          43,942  36,869  
Blending and other68,795  68,832          68,795  68,832  
General and administrative        45,469  45,825  45,469  45,825  
Transaction costs           13,074    13,074  
Exploration and evaluation 11,764  10,580    11,149      11,764  21,729  
Depletion and depreciation 463,501  294,925  261,766  261,709  6,419  2,050  731,686  558,684  
Impairment 187,822  65,000    220,341      187,822  285,341  
Share-based compensation         15,894  19,534  15,894  19,534  
Financing and interest         125,865  119,086  125,865  119,086  
Financial derivatives loss (gain)        7,197  (43,550) 7,197  (43,550) 
Foreign exchange (gain) loss        (61,787) 108,294  (61,787) 108,294  
Gain on dispositions(2,238) (1,946)         (2,238) (1,946) 
Other income        (7,526) (1,172) (7,526) (1,172) 
1,071,889  695,977  361,179  583,074  131,531  263,141  1,564,599  1,542,192  
Net income (loss) before income taxes(101,632) (149,462) 154,242  (14,473) (131,531) (263,141) (78,921) (427,076) 
Income tax expense (recovery)
Current income tax expense (recovery)101    1,992  (35)     2,093  (35) 
Deferred income tax expense (recovery)(32,942) (40,723) 10,055  (26,049) (45,668) (34,960) (68,555) (101,732) 
(32,841) (40,723) 12,047  (26,084) (45,668) (34,960) (66,462) (101,767) 
Net income (loss)$(68,791) $(108,739) $142,195  $11,611  $(85,863) $(228,181) $(12,459) $(325,309) 
Total oil and natural gas capital expenditures(1)
$376,543  $300,299  $177,928  $193,604  $  $  $554,471  $493,903  
(1)Includes acquisitions, net of proceeds from divestitures.

As atDecember 31, 2019December 31, 2018
Canadian assets$3,484,123  $3,739,029  
U.S. assets2,403,310  2,628,941  
Corporate assets26,650  9,228  
Total consolidated assets$5,914,083  $6,377,198  

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6.EXPLORATION AND EVALUATION ASSETS
December 31, 2019December 31, 2018
Balance, beginning of year$358,935  $272,974  
Capital expenditures2,948  10,567  
Corporate acquisition (note 4)  97,858  
Property acquisitions1,523  514  
Divestitures(443) (1,021) 
Impairment(7,822)   
Property swaps417    
Exploration and evaluation expense(11,764) (21,729) 
Transfers to oil and gas properties (note 7)(16,204) (13,866) 
Foreign currency translation(7,380) 13,638  
Balance, end of year$320,210  $358,935  

At December 31, 2019, the Company identified indicators of impairment for the exploration and evaluation assets within the Peace River CGU. The estimated recoverable amount was below the carrying value of the exploration and evaluation assets in the Peace River CGU and an impairment of $7.8 million was recorded as at December 31, 2019. There were no indicators of impairment for exploration and evaluation assets in the remaining CGUs at December 31, 2019.

At December 31, 2018 the Company identified indicators of impairment for the exploration and evaluation assets within the Conventional CGU. The estimated recoverable amount exceeded the carrying value of the of the exploration and evaluation assets in the Conventional CGU and no impairment was recorded. There were no indicators of impairment for exploration and evaluation assets in the remaining CGUs at December 31, 2018.

7.OIL AND GAS PROPERTIES
CostAccumulated
depletion
Net book value
Balance, December 31, 2017$7,932,327  $(3,974,018) $3,958,309  
Capital expenditures485,154    485,154  
Corporate acquisition (note 4)1,748,368    1,748,368  
Property acquisitions202    202  
Transfers from exploration and evaluation assets (note 6)13,866    13,866  
Change in asset retirement obligations (note 12)238,662    238,662  
Divestitures(15)   (15) 
Impairment  (285,341) (285,341) 
Foreign currency translation325,969  (110,651) 215,318  
Depletion  (556,634) (556,634) 
Balance, December 31, 2018$10,744,533  $(4,926,644) $5,817,889  
Capital expenditures549,343    549,343  
Property acquisitions2,636    2,636  
Transfers from exploration and evaluation assets (note 6)16,204    16,204  
Change in asset retirement obligations (note 12)23,894    23,894  
Divestitures(2,069) 1,690  (379) 
Property swaps1,773    1,773  
Impairment  (180,000) (180,000) 
Foreign currency translation(208,017) 89,813  (118,204) 
Depletion  (725,267) (725,267) 
Balance, December 31, 2019$11,128,297  $(5,740,408) $5,387,889  

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Baytex recorded impairment expense related to oil and gas properties of $180.0 million for the year ended December 31, 2019 and $285.3 million for the year ended December 31, 2018.

At December 31, 2019, the Company identified indicators of impairment for its Peace River CGU due to a sustained decline in Canadian heavy oil prices and a reduction in planned exploration and development expenditures related to thermal properties in the Peace River CGU. The recoverable amount of the Peace River CGU was based on its VIU which was estimated using a discounted cash flow model using proved plus probable cash flows from an independent reserve report approved by the Board of Directors and an after-tax discount rate of 11%. The recoverable amount was not sufficient to support the carrying amount of the the CGU which resulted in an impairment of $180.0 million recorded as at December 31, 2019. There were no indicators of impairment or impairment reversal identified for the remaining CGUs as at December 31, 2019.

The recoverable amount of the Peace River CGU was calculated at December 31, 2019 using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company.
2020202120222023202420252026202720282029
WTI crude oil (US$/bbl)61.00  63.75  66.18  67.91  69.48  71.07  72.68  74.24  75.73  77.24  
WCS heavy oil (CA$/bbl)57.57  62.35  64.33  66.23  67.97  69.72  71.49  73.20  74.80  76.43  
AECO (CA$/GJ)2.04  2.32  2.62  2.71  2.81  2.89  2.96  3.03  3.09  3.16  
Exchange rate (CAD/USD)1.32  1.30  1.27  1.27  1.27  1.27  1.27  1.27  1.27  1.27  

This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2.0%.

The following table demonstrates the sensitivity of the estimated recoverable amount of the Peace River CGU to reasonably possible changes in key assumptions inherent in the estimate.
Change in discount rate of 1%
Change in oil price of $2.50/bbl
Change in impairment expense$24,000  $88,000  

At December 31, 2018, indicators of impairment existed for the Conventional CGU due to a sustained decline in Canadian natural gas prices and a reduction in planned capital exploration and development expenditures. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $65.0 million recorded as at December 31, 2018. The recoverable amount of the Conventional CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20%.

At December 31, 2018, indicators of impairment existed for the Eagle Ford CGU due to the expected development plan outlined by the operator which resulted in a decline in the net present value of the cash flows of the proved plus probable reserves. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $220.3 million recorded as at December 31, 2018. The recoverable amount of the Eagle Ford CGU was based on its VIU which was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20%.

8.OTHER PLANT AND EQUIPMENT
CostAccumulated depreciationNet book value
Balance, December 31, 2017$62,648  $(53,174) $9,474  
Capital expenditures1,804    1,804  
Depreciation  (2,050) (2,050) 
Balance, December 31, 2018$64,452  $(55,224) $9,228  
Capital expenditures552    552  
Depreciation  (2,182) (2,182) 
Balance, December 31, 2019$65,004  $(57,406) $7,598  

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9.LEASES
Lease Assets
Baytex had the following right-of-use assets at December 31, 2019.
Office LeasesField EquipmentVehicles and OtherTotal
Balance, January 1, 2019 (1)
$14,775  $2,254  $969  $17,998  
Additions  1,668  159  1,827  
Modifications(6) 4  19  17  
Depreciation(4,904) (837) (482) (6,223) 
Balance, December 31, 2019$9,865  $3,089  $665  $13,619  
(1)The Company adopted IFRS 16 Leases on January 1, 2019 using the modified retrospective approach. At December 31, 2018, the Company did not report any finance leases in accordance with its previous accounting policy for leases.

Lease Obligations
Baytex had the following future commitments associated with its lease obligations at December 31, 2019.

December 31, 2019
Less than 1 year$6,216  
1 - 3 years7,748  
3 - 5 years604  
After 5 years  
Total lease payments$14,568  
Amounts representing interest over the term of the lease(685) 
Present value of net lease payments$13,883  
Less current portion of lease obligations5,798  
Non-current portion of lease obligations$8,085  

The Company recorded interest expense related to its lease obligations of $0.6 million and recorded lease payments of $6.0 million for the year ended December 31, 2019.

10.BANK LOAN
December 31, 2019December 31, 2018
Bank loan - U.S. dollar denominated(1)
$206,144  $122,388  
Bank loan - Canadian dollar denominated300,327  399,906  
Bank loan - principal(2)
$506,471  $522,294  
Unamortized debt issuance costs(1,059) (1,594) 
Bank loan$505,412  $520,700  
(1)U.S. dollar denominated bank loan balance was US$159.0 million as at December 31, 2019 (US$89.7 million as at December 31, 2018).
(2)The decrease in the principal amount of the bank loan outstanding from December 31, 2018 to December 31, 2019 is the result of loan repayments of $7.1 million and changes in the reported amount of U.S. denominated debt of $8.7 million.

Baytex has US$575 million of revolving secured credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving secured term loan (the "Term Loan"). On May 2, 2019, Baytex amended its credit facilities to extend maturity from June 4, 2020 to April 2, 2021. On March 3, 2020, Baytex amended its credit facilities to extend maturity to April 2, 2024. These facilities will automatically be extended to June 4, 2024 providing Baytex has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership.

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The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The credit facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon Baytex's request. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates, plus applicable margins. In the event that Baytex breaches any of the covenants under the credit facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders.

At December 31, 2019, Baytex had $15.2 million of outstanding letters of credit under the credit facilities (December 31, 2018 - $14.6 million).

At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2019.
Covenant DescriptionPosition as at December 31, 2019  Covenant
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)
0.52:1.00
3.50:1.00
Interest Coverage(3) (Minimum Ratio)
9.42:1.00
2.00:1.00
(1)"Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at December 31, 2019, the Company's Senior Secured Debt totaled $521.7 million which includes $506.5 million of principal amounts outstanding and $15.2 million of letters of credit.
(2)Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2019 was $1,011.9 million.
(3)Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended December 31, 2019 were $107.4 million.

11.LONG-TERM NOTES
December 31, 2019December 31, 2018
6.75% notes (US$150,000 – principal) due February 17, 2021
$  $204,683  
5.125% notes (US$400,000 – principal) due June 1, 2021
518,600  545,820  
6.625% notes (Cdn$300,000 – principal) due July 19, 2022
300,000  300,000  
5.625% notes (US$400,000 – principal) due June 1, 2024
518,600  545,820  
Total long-term notes - principal(1)
$1,337,200  $1,596,323  
Unamortized debt issuance costs(9,025) (13,083) 
Total long-term notes - net of unamortized debt issuance costs$1,328,175  $1,583,240  
(1)The decrease in the principal amount of long-term notes outstanding from December 31, 2018 to December 31, 2019 is the result of principal repayments of $198.1 million and changes in the reported amount of U.S. denominated debt of $61.0 million.

On September 13, 2019, Baytex completed the early redemption of the US$150,000 principal amount of 6.75% senior unsecured notes, due February 17, 2021. The total principal payment was $198.1 million.

The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts the Company's ability to raise additional debt beyond the existing credit facilities and long-term notes unless the Company maintains a minimum coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 10) to financing and interest expense on a trailing twelve month basis) of 2.50:1.00. As at December 31, 2019, the fixed charge coverage ratio was 8.04:1.00.

On February 5, 2020, Baytex issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually in arrears (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.4 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.3 million.

On February 20, 2020, Baytex used a portion of the net proceeds from the issuance of the 8.75% Senior Notes of $652.3 million to complete the early redemption of the US$400 million principal amount of the 5.125% senior unsecured notes due June 1, 2021 at par plus accrued interest. On February 5, 2020, the Company also issued a notice of redemption for the $300 million
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principal amount of our 6.625% senior unsecured notes due July 19, 2022. Baytex expects to complete the early redemption of these notes on March 6, 2020 at 101.104% of the principal amount plus accrued interest.

12.ASSET RETIREMENT OBLIGATIONS
December 31, 2019December 31, 2018
Balance, beginning of year$646,898  $368,995  
Liabilities incurred21,748  12,537  
Liabilities settled(15,417) (14,035) 
Liabilities assumed from corporate acquisition (note 4)  39,960  
Liabilities acquired from property acquisitions1,648  132  
Liabilities divested(1,331) (580) 
Property swaps792    
Accretion (note 18)13,713  10,914  
Change in estimate(1)
19,632  33,453  
Changes in discount rates and inflation rates(17,486) 192,672  
Foreign currency translation(2,223) 2,850  
Balance, end of year$667,974  $646,898  
Less current portion of asset retirement obligations11,579    
Non-current portion of asset retirement obligations$656,395  $646,898  
(1)Changes in the estimated costs, the timing of abandonment and reclamation and the status of wells are factors resulting in a change in estimate.

At December 31, 2019, the undiscounted amount of estimated cash flows required to settle the asset retirement obligations is $714.8 million (December 31, 2018 - $673.1 million). The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2019 calculated using an estimated inflation rate of 1.4% (December 31, 2018 - 2.0%) and a risk free rate discount rate of 1.8% (December 31, 2018 - 2.2%) is $668.0 million (December 31, 2018 - $646.9 million). These costs are expected to be incurred over the next 60 years.

13.SHAREHOLDERS' CAPITAL
The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at December 31, 2019, no preferred shares have been issued by the Company and all common shares issued were fully paid.

The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meetings of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated.
Number of Common Shares
(000s)
Amount
Balance, December 31, 2017235,451  $4,443,576  
Vesting of share awards 3,343  19,496  
Issued on corporate acquisition (note 4)315,266  1,238,995  
Issuance costs, net of tax (note 4)—  (551) 
Balance, December 31, 2018554,060  $5,701,516  
Vesting of share awards4,245  17,319  
Balance, December 31, 2019558,305  $5,718,835  

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14.SHARE-BASED COMPENSATION PLAN
The Company recorded compensation expense related to the share awards and share options of $15.9 million for the year ended December 31, 2019 ($19.5 million for the year ended December 31, 2018).
Share Awards

The weighted average fair value of share awards granted during the year ended December 31, 2019 was $2.63 per restricted and performance award (December 31, 2018 - $4.04).

The number of share awards outstanding is detailed below:
(000s)Number of
restricted awards
Number of
 performance awards(1)
Total number of
share awards
Balance, December 31, 20172,028  2,253  4,281  
Granted2,793  2,591  5,384  
Assumed on corporate acquisition (2)
302  257  559  
Vested and converted to common shares(1,682) (1,661) (3,343) 
Forfeited(198) (167) (365) 
Balance, December 31, 20183,243  3,273  6,516  
Granted3,184  3,245  6,429  
Vested and converted to common shares(2,081) (2,164) (4,245) 
Forfeited(545) (1,219) (1,764) 
Balance, December 31, 20193,801  3,135  6,936  
(1)Based on underlying awards before applying the payout multiplier which can range from 0x to 2x.
(2)Following closing of the business combination (note 4), holders of 0.3 million Raging River restricted awards and 0.3 million performance awards are entitled to receive Baytex common shares rather than Raging River common shares, after adjusting the quantity of awards outstanding based on the exchange ratio. The payout multiplier for the performance awards is fixed at 1.0. The fair value assigned to the service period that had occurred prior to closing was included in consideration for the business combination.

Share Options

Baytex assumed share option plans pursuant to a business combination in 2018 (note 4). No new grants will be made under the option plans.

The Company accounts for share options using the fair value method. Under this method, compensation is expensed over the vesting period for the share options, with a corresponding increase in contributed surplus.

One third of the options granted will vest on each of the first, second, and third anniversaries of the date of grant. At December 31, 2019, 2.5 million share options with a weighted average exercise price of $6.83 were outstanding. The following tables summarize the information about the share options.
(000s, except per common share amounts)Number of optionsWeighted average
exercise price
Balance, December 31, 2017  $  
Assumed on corporate acquisition9,187  6.63  
Forfeited/Expired(4,322) 6.57  
Balance, December 31, 20184,865  $6.70  
Forfeited/Expired(2,390) 6.56  
Balance, December 31, 20192,475  $6.83  

20


Options OutstandingOptions Exercisable
Exercise priceNumber outstanding at December 31, 2019 (000s)Weighted average remaining life (years)Weighted
average
exercise price
Number exercisable at December 31, 2019 (000s)Weighted
average
exercise price
$5.00 - $7.00
1,654  0.79$6.39  1,248  $6.42  
$7.01 - $9.00
821  0.157.73  821  7.73  
Total2,475  0.58$6.83  2,069  $6.94  

15.NET INCOME (LOSS) PER SHARE
Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards and share options were exercised. The treasury stock method is used to determine the dilutive effect of share awards and share options whereby the proceeds from the potential exercise of share options and the amount of unrecognized share-based compensation expense on all share awards and share options, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the year.
Years Ended December 31
20192018
Net lossWeighted average common shares (000's)Net loss per shareNet lossWeighted average common shares (000's)Net loss per share
Net loss - basic$(12,459) 557,048  $(0.02) $(325,309) 351,542  $(0.93) 
Dilutive effect of share awards—    —  —    —  
Dilutive effect of share options—    —  —    —  
Net loss - diluted$(12,459) 557,048  $(0.02) $(325,309) 351,542  $(0.93) 

For the year ended December 31, 2019, 6.9 million share awards (2018 - 6.5 million) and 2.5 million share options (2018 - 4.9 million) were excluded from the calculation of diluted earnings per share as the Company recorded a net loss.

16.PETROLEUM AND NATURAL GAS SALES
The Company's petroleum and natural gas sales from contracts with customers for each reportable segment is set forth in the following table.
Years Ended December 31
20192018
CanadaU.S.TotalCanadaU.S.Total
Light oil and condensate$538,487  $600,163  $1,138,650  $169,335  $637,055  $806,390  
Heavy oil500,187    500,187  411,794    411,794  
NGL8,430  60,647  69,077  14,531  97,008  111,539  
Natural gas sales30,620  67,385  98,005  23,555  75,592  99,147  
Total petroleum and natural gas sales$1,077,724  $728,195  $1,805,919  $619,215  $809,655  $1,428,870  

Included in accounts receivable at December 31, 2019 is $138.0 million (December 31, 2018 - $77.4 million) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.

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17.INCOME TAXES
The provision for income taxes has been computed as follows:
Years Ended December 31
2019  2018  
Net loss before income taxes $(78,921) $(427,076) 
Expected income taxes at the statutory rate of 26.72% (2018 – 27.00%)
(21,088) (115,311) 
(Increase) decrease in income tax recovery resulting from:
Share-based compensation4,247  5,185  
Non-taxable portion of foreign exchange (gain) loss(8,155) 14,467  
Effect of change in income tax rates(6,098)   
Effect of rate adjustments for foreign jurisdictions(27,785) (22,119) 
Effect of change in deferred tax benefit not recognized(1)
(7,563) 14,467  
Adjustments and assessments(20) 1,544  
Income tax recovery$(66,462) $(101,767) 
(1)A deferred income tax asset has not been recognized for accumulated allowable capital losses of $109 million ($139 million as at December 31, 2018) related to the foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes.

For the year ended December 31, 2019, the deferred tax recovery includes $6.1 million attributable to decreases in the Alberta provincial income tax rate for the period from July 1, 2019 to January 1, 2022, which reduced the provincial tax rate to 11% effective July 1, 2019, and further reduces it by 1% on January 1st for each of the years 2020, 2021, and 2022, resulting in a provincial rate of 8%.

In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the "CRA”) that deny $591 million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Office was assigned to the Company's file in July 2018. Baytex remains confident that the original tax filings are correct and intends to defend these tax filings through the appeals process.

A continuity of the net deferred income tax liability is detailed in the following tables:
As atJanuary 1, 2019Recognized in Net IncomeForeign Currency Translation AdjustmentDecember 31, 2019
Taxable temporary differences:
Petroleum and natural gas properties$(954,506) $48,995  $23,517  $(881,994) 
Financial derivatives(21,486) 21,486  —    
Other(3,045) 5,192  (4,550) (2,403) 
Deductible temporary differences:
Asset retirement obligations172,359  (7,364) (472) 164,523  
Financial derivatives—  802  —  802  
Non-capital losses399,699  (1,460) (11,522) 386,717  
Finance costs96,143  904  —  97,047  
Net deferred income tax liability(1)
$(310,836) $68,555  $6,973  $(235,308) 
(1)Non-capital loss carry-forwards at December 31, 2019 totaled $1,714.6 million and expire from 2029 to 2039.

22


As atJanuary 1, 2018Recognized in Net LossShare Issuance CostsBusiness CombinationForeign Currency Translation AdjustmentDecember 31, 2018
Taxable temporary differences:
Petroleum and natural gas properties$(696,427) $(11,639) $—  $(207,337) $(39,103) $(954,506) 
Financial derivatives  (22,984) —  1,498  —  (21,486) 
Deferred income(17,827) 17,827  —  —  —    
Other(5,956) (2,538) 209  —  5,240  (3,045) 
Deductible temporary differences:
Asset retirement obligations97,977  62,984  —  10,789  609  172,359  
Financial derivatives8,528  (8,528) —  —  —  —  
Non-capital losses330,749  48,725  —  —  20,225  399,699  
Finance costs78,258  17,885  —  —  —  96,143  
Net deferred income tax liability(1)
$(204,698) $101,732  $209  $(195,050) $(13,029) $(310,836) 
(1)Non-capital loss carry-forwards at December 31, 2018 totaled $1,733.8 million and expire from 2029 to 2038.

18.FINANCING AND INTEREST
Years Ended December 31
2019  2018  
Interest on bank loan$20,376  $15,637  
Interest on long-term notes86,431  88,681  
Interest on lease obligations610  —  
Non-cash financing4,735  3,854  
Accretion of asset retirement obligations (note 12)13,713  10,914  
Financing and interest$125,865  $119,086  

19.FOREIGN EXCHANGE
Years Ended December 31
2019  2018  
Unrealized foreign exchange (gain) loss$(62,753) $106,143  
Realized foreign exchange loss966  2,151  
Foreign exchange (gain) loss$(61,787) $108,294  

20.FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, bank loan, long-term notes, and lease obligations. The fair value of the bank loan is equal to the principal amount outstanding as the credit facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices.

23


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, 2019December 31, 2018
Carrying valueFair valueCarrying valueFair valueFair Value Measurement Hierarchy
Financial Assets
FVTPL
Financial Derivatives$5,433  $5,433  $79,582  $79,582  Level 2
Total$5,433  $5,433  $79,582  $79,582  
Financial assets at amortized cost
Cash$5,572  $5,572  $  $  —  
Trade and other receivables173,762  173,762  111,564  111,564  —  
Total$179,334  $179,334  $111,564  $111,564  
Financial Liabilities
FVTPL
Financial Derivatives$(8,668) $(8,668) $  $  Level 2
Total$(8,668) $(8,668) $  $  
Financial liabilities at amortized cost
Trade and other payables$(207,454) $(207,454) $(258,114) $(258,114) —  
Bank loan(505,412) (506,471) (520,700) (522,294) —  
Long-term notes(1,328,175) (1,290,817) (1,583,240) (1,492,363) Level 1  
Lease obligations(13,883) (13,883) —  —  —  
Total$(2,054,924) $(2,018,625) $(2,362,054) $(2,272,771) 

There were no transfers of financial instruments between Level 1 and Level 2 in during the years ended December 31, 2019 or 2018.

Financial Risk

Baytex is exposed to a variety of financial risks, including market risk, liquidity risk and credit risk. The Company's process to mitigate these risks is described below.

Market Risk

Market risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in market prices. Market risk is comprised of foreign currency risk, interest rate risk and commodity price risk.

Foreign Currency Risk

Baytex is exposed to fluctuations in foreign exchange rates as a result of the U.S. dollar portion of its bank loan and long-term notes, crude oil sales based on U.S. dollar benchmark prices and commodity financial derivative contracts that are settled in U.S. dollars. The Company's net income or loss, comprehensive income or loss and cash flow will therefore be impacted by fluctuations in foreign exchange rates.

To manage the impact of foreign exchange rate fluctuations, the Company may enter into agreements to fix the Canadian to U.S. dollar exchange rate. At December 31, 2019 and 2018, the Company did not have any currency derivative contracts outstanding.

A $0.01 increase or decrease in the CAD/USD foreign exchange rate on the revaluation of outstanding U.S. dollar denominated assets and liabilities, would impact net income or loss before income taxes by approximately $8.3 million.
24


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:
AssetsLiabilities
December 31, 2019December 31, 2018December 31, 2019December 31, 2018
U.S. dollar denominatedUS$8,733  US$80,857  US$841,961  US$963,351  

Interest Rate Risk

The Company's interest rate risk arises from borrowing at floating rates under the Revolving Facilities and Term Loan (note 10). Based on the Company's principal bank loan outstanding net of the interest rate swap, as at December 31, 2019, a change of 100 basis points in interest rates would have an impact on net income or loss before income taxes of approximately $4.1 million.

Interest Rate Swaps

The Company mitigates its exposure to interest rate risk by entering into interest rate swap transactions. As of March 3, 2020, Baytex had an interest rate swap outstanding with a notional value of $100 million maturing in October 2020, with a fixed contract price of 2.02% referencing the Canadian Dollar Offered Rate. At December 31, 2019, the interest rate swap had a fair value of zero (December 31, 2018 - $0.3 million).

Commodity Price Risk

Baytex utilizes financial derivative contracts or physical delivery contracts to manage the risk associated with changes in commodity prices. The use of derivatives is governed by a Risk Management Policy approved by the Board of Directors of Baytex which sets out limits on the use of derivatives. Baytex does not use financial derivatives for speculative purposes. Baytex's financial derivative contracts are subject to master netting agreements that create a legally enforceable right to offset by the counterparty the related financial assets and financial liabilities.

When assessing the potential impact of crude oil price changes on the crude oil financial derivative contracts outstanding as at December 31, 2019, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $17.5 million.

When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2019, a $0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $1.2 million.

25


Financial Derivative Contracts

Baytex had the following financial derivative contracts outstanding as of March 3, 2020:
Remaining PeriodVolume
Price/Unit (1)
Index
Oil
Basis swapJan 2020 to Dec 2020
2,500 bbl/d
WTI less US$16.10/bbl
WCS
Basis swap (6)
Apr 2020 to Dec 2020
4,000 bbl/d
WTI less US$16.38/bbl
WCS
Basis swapJan 2020 to Dec 2020
2,000 bbl/d
WTI less US$6.50/bbl
MSW
Basis swap (6)
Apr 2020 to Dec 2020
3,000 bbl/d
WTI less US$5.92/bbl
MSW
Fixed - SellJan 2020 to Mar 2020
6,000 bbl/d
US$56.60/bbl
WTI
Fixed - SellJan 2020 to Dec 2020
2,000 bbl/d
US$58.00/bbl
WTI
3-way option (2)
Jan 2020 to Dec 2020
3,000 bbl/d
US$50.00/US$56.00/US$61.35
WTI
3-way option (2)
Jan 2020 to Dec 2020
3,000 bbl/d
US$50.00/US$57.00/US$60.00
WTI
3-way option (2)
Jan 2020 to Dec 2020
4,500 bbl/d
US$50.00/US$57.00/US$62.00
WTI
3-way option (2)
Jan 2020 to Dec 2020
3,000 bbl/d
US$50.00/US$58.00/US$62.00
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,000 bbl/d
US$51.00/US$58.00/US$60.50
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,000 bbl/d
US$51.00/US$58.00/US$60.83
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,500 bbl/d
US$51.00/US$59.00/US$65.60
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,500 bbl/d
US$51.00/US$59.00/US$66.00
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,000 bbl/d
US$51.00/US$59.50/US$66.15
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,000 bbl/d
US$51.00/US$60.00/US$65.60
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,000 bbl/d
US$51.00/US$60.00/US$66.00
WTI
3-way option (2)
Jan 2020 to Dec 2020
1,000 bbl/d
US$51.00/US$60.00/US$66.05
WTI
3-way option (2)
Jan 2020 to Dec 2020
2,000 bbl/d
US$51.00/US$60.00/US$66.70
WTI
Swaption (3)
Jan 2021 to Dec 2021
3,000 bbl/d
US$64.50/bbl
Brent
Swaption (4)
Jan 2021 to Dec 2021
3,000 bbl/d
US$70.00/bbl
Brent
Swaption (4)
Jan 2021 to Dec 2021
3,000 bbl/d
US$60.75/bbl
WTI
Natural Gas
3-way option (2)
Jan 2020 to Dec 2020
5,000 mmbtu/d
US$2.25/US$2.60/US$2.85
NYMEX
Swaption (5)
Jan 2021 to Dec 2021
5,000 mmbtu/d
US$2.90/mmbtu
NYMEX
(1)Based on the weighted average price per unit for the period.
(2)Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US50/US$58.00/US$62.00 contract, Baytex receives WTI plus US$8.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$58.00/bbl when WTI is between US$50.00/bbl and US$58.00/bbl; Baytex receives the market price when WTI is between US$58.00/bbl and US$62.00/bbl; and Baytex receives US$62.00/bbl when WTI is above US$62.00/bbl.
(3)For these contracts, the counterparty has the right, if exercised on September 30, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.
(4)For these contracts, the counterparty has the right, if exercised on December 31, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.
(5)For these contracts, the counterparty has the right, if exercised on December 23, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.
(6)Contracts entered subsequent to December 31, 2019.

The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.
Years Ended December 31  
2019  2018  
Realized financial derivatives (gain) loss$(75,620) $73,165  
Unrealized financial derivatives loss (gain)82,817  (116,715) 
Financial derivatives loss (gain)$7,197  $(43,550) 


26


Liquidity Risk

Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Such strategies include monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements, opportunities to issue additional common shares as well as reducing capital expenditures. As at December 31, 2019, Baytex had available unused bank credit facilities in the amount of $523.8 million (December 31, 2018 - $547.7 million). In the event the Company is not able to comply with the financial covenants contained in agreements with its lenders, the Company's ability to access additional debt may be restricted.

The timing of cash outflows relating to financial liabilities as at December 31, 2019 is outlined in the table below:
TotalLess than 1 year1-3 years3-5 yearsBeyond 5 years
Trade and other payables$207,454  $207,454  $  $  $  
Bank loan (1)(2)
506,471    506,471      
Long-term notes (2)
1,337,200    818,600  518,600    
Interest on long-term notes (3)
217,247  75,625  100,303  41,319    
Lease obligations14,568  6,216  7,748  604    
$2,282,940  $289,295  $1,433,122  $560,523  $  
(1)At December 31, 2019, the bank loan was set to mature on April 2, 2021. On March 3, 2020, Baytex amended the bank loan to extend maturity to April 2, 2024 which will automatically be extended to June 4, 2024 providing the Company has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.
(2)Principal amount of instruments. On February 5, 2020, Baytex issued US$500 million principal amount of 8.75% senior unsecured notes due 2027 and issued a redemption notice for the $300 million principal amount of 6.625% senior unsecured notes due 2022 (note 11). The Company expects to complete the redemption of these notes on March 6, 2020. On February 20, 2020 Baytex completed the redemption of the US$400 million principal amount of senior unsecured notes due 2021 (note 11).
(3)Excludes interest on bank loan as interest payments on bank loans fluctuate based on amounts outstanding and interest rates.

Credit Risk

Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31, 2019, the Company is exposed to credit risk with respect to its trade and other receivables and financial derivatives.

Credit risk is considered very low for the Company's trade and other receivables and financial derivatives due to the external credit ratings of its counterparties and Baytex's process for selecting and monitoring credit-worthy counterparties. Most of the Company's trade and other receivables relate to petroleum and natural gas sales and are exposed to typical industry credit risks. Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts with only creditworthy entities. Letters of credit or parental guarantees may be obtained prior to the commencement of business with certain counterparties. Credit risk may also arise from financial derivative instruments. The maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company considers all financial assets that are not impaired or past due to be of good credit quality.

The majority of the Company's credit exposure on accounts receivable at December 31, 2019 relates to accrued revenues for November and December 2019. Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day of the month following production. Joint interest receivables are typically collected within one to three months following production. Included in accounts receivable at December 31, 2019 is $138.0 million (December 31, 2018 - $77.4 million) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.

Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of accounts receivable is reduced by the use of an allowance for doubtful accounts and a charge to net income or loss. If the Company subsequently determines the accounts receivable is uncollectible, the receivable and allowance for doubtful accounts are adjusted accordingly. As at December 31, 2019, allowance for doubtful accounts was $1.6 million (December 31, 2018 - $1.9 million).

In determining whether amounts past due are collectible, the Company will assess the nature of the past due amounts as well as the credit worthiness and past payment history of the counterparty. As at December 31, 2019, accounts receivable that Baytex has deemed past due (more than 90 days) but not impaired was $2.7 million (December 31, 2018 - $2.6 million). Baytex has estimated the lifetime expected credit loss as at and for the years ended December 31, 2019 to be nominal.

27


The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2019.
Trade and Other Receivables AgingDecember 31, 2019December 31, 2018
Current (less than 30 days)$169,500  $104,099  
31-60 days1,199  3,037  
61-90 days342  1,842  
Past due (more than 90 days)2,721  2,586  
$173,762  $111,564  

21.SUPPLEMENTAL INFORMATION
Change in Non-Cash Working Capital Items
Years Ended December 31
2019  2018  
Trade and other receivables$(62,198) $1,280  
Trade and other payables(50,660) 113,572  
Non-cash working capital acquired (note 4)  (46,773) 
$(112,858) $68,079  
Changes in non-cash working capital related to:
Operating activities$(52,070) $39,448  
Investing activities(62,485) 32,435  
Foreign currency translation on non-cash working capital1,697  (3,804) 
$(112,858) $68,079  

Income Statement Presentation

Baytex's consolidated statements of income or loss and comprehensive income or loss are prepared primarily according to the nature of expense, with the exception of employee compensation costs which are included in both operating expense and general and administrative expense line items.

The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense.
Years Ended December 31
2019  2018  
Operating$12,918  $12,140  
General and administrative33,728  34,963  
Total employee compensation costs$46,646  $47,103  

22.COMMITMENTS AND CONTINGENCIES
Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s cash flow from operations in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of December 31, 2019, and the expected timing of funding of these obligations, are noted in the table below.
TotalLess than
1 year
1-3 years
3-5 yearsBeyond 5 years
Processing agreements39,352  10,234  10,591  8,848  9,679  
Transportation agreements115,999  11,636  41,263  37,099  26,001  
Total$155,351  $21,870  $51,854  $45,947  $35,680  

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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.

23.RELATED PARTIES

Balances and transactions between the Company and its subsidiaries, which are related parties of the Company, have been eliminated on consolidation and are not disclosed separately in this note.

Transactions with key management personnel and directors are noted in the table below.
Years Ended December 31
20192018
Short-term employee benefits$6,202  $8,703  
Share-based compensation9,188  10,985  
Termination payments2,208  3,025  
Total compensation for key management personnel$17,598  $22,713  

24.CAPITAL MANAGEMENT

The Company's capital management objective is to maintain financial flexibility and sufficient sources of liquidity to execute its capital programs, while meeting short and long-term commitments. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At December 31, 2019, the Company's capital structure was comprised of shareholders' capital, long-term debt, working capital and the bank loan.

Baytex monitors its estimated adjusted funds flow and the level of undrawn credit facilities. The Company's adjusted funds flow depends on a number of factors, including commodity prices, production and sales volumes, royalties, operating expenses, taxes and foreign exchange rates. In order to manage its capital structure and liquidity, Baytex may from time to time issue equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.

At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities and had unused capacity of $523.8 million (December 31, 2018 - $547.7 million).

Baytex considers adjusted funds flow a key measure that provides a more complete understanding of operating performance and the Company's ability to generate funds for capital investments, debt repayment, settlement of abandonment obligations and potential future dividends. Baytex eliminates changes in non-cash working capital, transaction costs, and settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on the Company's capital programs and the maturity of its operating areas. The settlement of abandonment obligations are managed through the capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them from the calculation Baytex is able to provide a more meaningful measure of cash flow on a continuing basis. Transaction costs associated with business combinations (note 4) are excluded from adjusted funds flow as the costs are considered non-recurring and not reflective of the Company's ability to generate adjusted funds flow on an ongoing basis. Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with IFRS, such as cash flow from operating activities and net income or loss.

Adjusted funds flow does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures for other entities. It is reconciled to the nearest measure determined in accordance with IFRS, cash flow from operating activities, as set forth below.
Years Ended December 31
20192018
Cash flow from operating activities$834,939  $485,322  
Change in non-cash working capital52,070  (39,448) 
Asset retirement obligations settled15,417  14,035  
Transaction costs  13,074  
Adjusted funds flow$902,426  $472,983  

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The Company believes that net debt assists in providing a more complete understanding of its financial position and provides a key measure to assess liquidity. Net debt is calculated based on the principal amounts of the bank loan and long-term notes outstanding, net of working capital. The current portion of financial derivatives is excluded as the valuation of the underlying contracts is subject to a high degree of volatility prior to the ultimate settlement. Onerous contracts are excluded from net debt as the underlying contracts do not represent an available source of liquidity. The principal amounts of the bank loan and long-term notes outstanding are used in the calculation of net debt as these amounts represent the Company's ultimate repayment obligation at maturity. The carrying amount of debt issue costs associated with the bank loan and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source of liquidity or repayment obligation.

Net debt does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measure for other entities. The computation of net debt is set forth below.
December 31, 2019December 31, 2018
Bank loan - principal$506,471  $522,294  
Long-term notes - principal1,337,200  1,596,323  
Trade and other payables207,454  258,114  
Cash(5,572)   
Trade and other receivables(173,762) (111,564) 
Net debt$1,871,791  $2,265,167  


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