bte-20211231

MANAGEMENT'S ANNUAL 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, 2021, 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, 2021 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, 2021.

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.


/s/ Edward D. LaFehr			/s/ Rodney D. Gray

Edward D. LaFehr			Rodney D. Gray
President and Chief Executive Officer			Executive Vice President and Chief Financial Officer
Baytex Energy Corp.			Baytex Energy Corp.

February 24, 2022

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. (and subsidiaries) (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of income (loss) and comprehensive income (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, 2021 and 2020, and 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, 2021, 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 February 24, 2022 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 the recoverable amount of of oil and gas properties

As discussed in note 6 to the consolidated financial statements, the Company recorded an impairment reversal of $1,537 million related to the Company’s Conventional, Peace River, Lloydminster, Viking and Eagle Ford cash generating units (CGUs). The Company identified indicators of impairment reversal as of December 31, 2021 for each of the CGUs and therefore determined the recoverable amount as of December 31, 2021 of each of the CGUs. The determination of recoverable amount of a CGU involves numerous estimates, including cash flows associated with estimated proved and probable oil and gas reserves of the CGU (“CGU reserves”) and the discount rate. The estimation of proved and probable oil and gas reserves involves the expertise of independent reserves evaluators, who take into consideration assumptions related to forecasted production volumes, royalty, operating and capital costs and commodity prices (collectively “reserve assumptions”). The Company engages independent reserves evaluators to estimate CGU reserves.

We identified the assessment of the recoverable amount of each of the Company’s CGUs as a critical audit matter. Minor changes in reserve assumptions and discount rates could have had a significant impact on the estimate of recoverable amounts and the resulting impairment reversal of the CGUs. A high degree of auditor judgment was required to evaluate the Company’s estimates of CGU reserves, and related reserve assumptions, and the discount rates, which were inputs into the calculation of recoverable amounts. Additionally, the evaluation of these estimates required involvement of valuation professionals with specialized skills and knowledge.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:

•the Company’s determination of the recoverable amount of each of the CGUs, including the discount rate

•the Company’s determination of reserve assumptions of the CGU reserves and resulting cash flows.

We evaluated the competence, capabilities and objectivity of the independent reserves evaluators engaged by the Company. We evaluated the methodology used by the independent reserves evaluators to estimate the CGU reserves for compliance with regulatory standards. We compared the current year actual CGU production volumes, royalty, operating and capital costs to those estimates used in the prior year estimate of proved reserves by CGU to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of the CGU reserves by comparing them to those published by other reserve engineering companies. We assessed the forecasted production volumes and forecasted royalty, operating and capital costs assumptions used in the current year estimate of the CGU reserves by comparing them to historical results. We involved valuation professionals with specialized skills and knowledge, who assisted in:

•evaluating the Company’s determination of discount rates by comparing the discount rate against publicly available market data for comparable assets and assessing the resulting discount rate

•evaluating the Company’s estimate of aggregate recoverable amount of all CGUs by comparing the implied enterprise value to publicly available market data.

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”). As discussed in note 6 to the consolidated financial statements, the Company recorded depletion expense related to oil and gas properties of $459 million for the year ended December 31, 2021. The estimation of area reserves requires the expertise of independent reserves evaluators who take into consideration reserve assumptions. The Company engages independent reserves evaluators to estimate 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. Changes in assumptions used to estimate area reserves could have had a significant impact on the calculation of depletion expense of the depletable area. A high degree of auditor judgment was required in evaluating the area reserves, and related reserve assumptions, which were used in the calculation of depletion expense.

•the Company’s calculation of depletion expense

•the Company’s determination of reserve assumptions and resulting area reserves.

We assessed the calculation of depletion expense for compliance with International Financial Reporting Standards as issued by the International Accounting Standards Board. We evaluated the competence, capabilities and objectivity of the independent reserves evaluators engaged by the Company. We evaluated the methodology used by the independent reserves evaluators to estimate area reserves for compliance with regulatory standards. We compared current year actual area production volumes, royalty, operating and capital costs to those estimates used in the prior year estimate of proved reserves by area to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of area reserves by comparing them to those published by other reserves engineering companies. We assessed the forecasted production volumes and forecasted royalty, operating and capital costs assumptions used in the estimate of area reserves by comparing them to historical results.

/s/ KPMG LLP

Chartered Professional Accountants

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

Calgary, Canada

February 24, 2022

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Baytex Energy Corp.

Opinion on Internal Control Over Financial Reporting

We have audited Baytex Energy Corp.’s (and subsidiaries’) (the “Company”) internal control over financial reporting as of December 31, 2021, 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, 2021, 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, 2021 and 2020, the related consolidated statements of income (loss) and comprehensive income (loss), changes in equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements), and our report dated February 24, 2022 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 Annual 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.

/s/ KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 24, 2022

Baytex Energy Corp.

Consolidated Statements of Financial Position

(thousands of Canadian dollars)


As at	Notes	December 31, 2021		December 31, 2020

ASSETS
Current assets

Trade and other receivables		$	173,409	$	107,477
Financial derivatives	17	8,654		5,057
		182,063		112,534
Non-current assets

Exploration and evaluation assets	5	172,824		191,865
Oil and gas properties	6	4,464,371		3,077,548
Other plant and equipment		7,121		7,996
Lease assets		8,264		11,098
Deferred income tax asset	14	—		7,055
		$	4,834,643	$	3,408,096

LIABILITIES
Current liabilities
Trade and other payables		$	190,692	$	155,955
Financial derivatives	17	134,020		26,792
Lease obligations		2,938		4,289
Asset retirement obligations	9	11,080		11,820
		338,730		198,856
Non-current liabilities

Credit facilities	7	505,171		649,221
Long-term notes	8	874,527		1,132,868
Lease obligations		4,827		6,787
Asset retirement obligations	9	732,603		748,563
Deferred income tax liability	14	167,456		93,588
		2,623,314		2,829,883

SHAREHOLDERS’ EQUITY
Shareholders' capital	10	5,736,593		5,729,418
Contributed surplus		13,559		14,345
Accumulated other comprehensive income		632,103		618,976
Deficit		(4,170,926)		(5,784,526)
		2,211,329		578,213
		$	4,834,643	$	3,408,096

Commitments (note 19)

See accompanying notes to the consolidated financial statements.


/s/ Mark R. Bly			/s/ Jennifer A. Maki

Mark R. Bly			Jennifer A. Maki
Director, Baytex Energy Corp.			Director, Baytex Energy Corp.

Baytex Energy Corp.

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)

(thousands of Canadian dollars, except per common share amounts and weighted average common shares)


Years Ended December 31	Notes	2021		2020

Revenue, net of royalties
Petroleum and natural gas sales	13	$	1,868,195	$	975,477
Royalties		(339,156)		(163,735)
		1,529,039		811,742

Expenses
Operating		343,002		331,345
Transportation		32,261		28,437
Blending and other		85,689		48,381
General and administrative		40,804		34,268

Exploration and evaluation	5	15,212		14,011
Depletion and depreciation		464,580		486,380
Impairment (impairment reversal)	5, 6	(1,542,414)		2,360,220
Share-based compensation	11	11,130		9,469
Financing and interest	15	111,159		125,441
Financial derivatives loss (gain)	17	287,872		(29,336)
Foreign exchange (gain) loss	16	(2,868)		8,688
Gain on dispositions		(9,666)		(901)
Other income		(2,562)		(5,304)
		(165,801)		3,411,099
Net income (loss) before income taxes		1,694,840		(2,599,357)
Income tax expense (recovery)	14
Current income tax expense		1,272		574
Deferred income tax expense (recovery)		79,968		(160,967)
		81,240		(160,393)
Net income (loss)		$	1,613,600	$	(2,438,964)
Other comprehensive income (loss)
Foreign currency translation adjustment		13,127		62,752
Comprehensive income (loss)		$	1,626,727	$	(2,376,212)

Net income (loss) per common share	12
Basic		$	2.86	$	(4.35)
Diluted		$	2.82	$	(4.35)

Weighted average common shares	12
Basic		563,674		560,657
Diluted		571,610		560,657

See accompanying notes to the consolidated financial statements.

Baytex Energy Corp.

Consolidated Statements of Changes in Equity

(thousands of Canadian dollars)


	Notes	Shareholders’ capital		Contributed surplus		Accumulated other comprehensive income		Deficit		Total equity
Balance at December 31, 2019		$	5,718,835	$	17,712	$	556,224	$	(3,345,562)	$	2,947,209
Vesting of share awards	10	10,583		(10,583)		—		—		—
Share-based compensation	11	—		7,216		—		—		7,216
Comprehensive income (loss)		—		—		62,752		(2,438,964)		(2,376,212)
Balance at December 31, 2020		$	5,729,418	$	14,345	$	618,976	$	(5,784,526)	$	578,213
Vesting of share awards	10	7,175		(7,175)		—		—		—
Share-based compensation	11	—		6,389		—		—		6,389
Comprehensive income		—		—		13,127		1,613,600		1,626,727
Balance at December 31, 2021		$	5,736,593	$	13,559	$	632,103	$	(4,170,926)	$	2,211,329

See accompanying notes to the consolidated financial statements.

Baytex Energy Corp.

Consolidated Statements of Cash Flows

(thousands of Canadian dollars)


Years Ended December 31	Notes	2021		2020

CASH PROVIDED BY (USED IN):
Operating activities
Net income (loss)		$	1,613,600	$	(2,438,964)
Adjustments for:
Share-based compensation	11	6,389		7,216
Unrealized foreign exchange (gain) loss	16	(1,905)		9,232
Exploration and evaluation	5	15,212		14,011
Depletion and depreciation		464,580		486,380
Impairment (impairment reversal)	5, 6	(1,542,414)		2,360,220
Non-cash financing, accretion and early redemption expense	15	19,090		18,907
Non-cash other income	9	(2,857)		(2,128)
Unrealized financial derivatives loss	17	103,631		18,500
Gain on dispositions		(9,666)		(901)
Deferred income tax expense (recovery)	14	79,968		(160,967)

Asset retirement obligations settled	9	(6,662)		(7,168)
Change in non-cash working capital	18	(26,582)		48,758
Cash flows from operating activities		712,384		353,096

Financing activities
(Decrease) increase in credit facilities	7	(145,321)		143,248

Payments on lease obligations		(4,334)		(5,925)
Net proceeds from issuance of long-term notes	8	—		652,150
Redemption of long-term notes	8	(251,969)		(833,672)
Cash flows used in financing activities		(401,624)		(44,199)

Investing activities
Additions to exploration and evaluation assets	5	(3,298)		(4,490)
Additions to oil and gas properties	6	(310,005)		(275,850)
Additions to other plant and equipment		(907)		(2,280)
Property acquisitions		(1,557)		—
Proceeds from dispositions		7,804		182

Change in non-cash working capital	18	(2,797)		(32,031)
Cash flows used in investing activities		(310,760)		(314,469)

Change in cash		—		(5,572)
Cash, beginning of year		—		5,572
Cash, end of year		$	—	$	—

Supplementary information
Interest paid		$	93,114	$	102,358
Income taxes paid		$	253	$	1,155

See accompanying notes to the consolidated financial statements.

Baytex Energy Corp.

Notes to the Consolidated Financial Statements

For the years ended December 31, 2021 and 2020

(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 energy company engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and in Texas, United States. The Company’s common shares are traded on the Toronto Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

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.

The consolidated financial statements were approved by the Board of Directors of Baytex on February 24, 2022.

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

Current Environment and Estimation Uncertainty

Management makes judgements and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities.

During the year ended December 31, 2021, the global economy continued to show signs of recovery from the impacts of the COVID-19 pandemic. Global spot prices for crude oil have recovered and now exceed pre-pandemic levels as optimism for demand recovery improves with limited production growth from independent producers and ongoing OPEC+ production curtailments. While we have benefited from these improvements in crude oil prices there is a degree of uncertainty related to COVID-19 that has been considered in our estimates for the period ended December 31, 2021.

Environmental Reporting Regulations

Environmental reporting for public enterprises continues to evolve and we may be subject to additional future disclosure requirements. The International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Securities Administrators have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. We continue to monitor developments on these reporting requirements and have not yet quantified the cost to comply with these regulations.

Measurement Uncertainty and Judgments

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

Reserves

The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion, evaluating the recoverability of deferred income tax assets and in the determination of fair value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are

evaluated annually by independent reserves evaluators and represent the estimated recoverable quantities of oil, natural gas and NGL and the related net cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the Canadian Oil and Gas Evaluation Handbook.

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

Cash-generating Units ("CGUs")

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

Identification of Impairment and Impairment Reversal Indicators

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

Measurement of Recoverable Amount

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

Exploration and Evaluation ("E&E") Assets

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

Asset Retirement Obligations

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

Income Taxes

Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes. Estimates of future income taxes are subject to measurement uncertainty.

3. SIGNIFICANT ACCOUNTING POLICIES

Consolidation

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

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

Business Combinations

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

Revenue Recognition

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

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

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

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

E&E Assets

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

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

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

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

Oil and Gas Properties

Oil and gas properties are initially recorded at cost and include the costs to acquire, develop, complete geological and geophysical surveys, drill wells, and construct and install infrastructure including wellhead equipment and processing facilities.

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

Depletion and Depreciation

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

Impairment and Impairment Reversals

Non-financial Assets

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

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

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

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

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

Asset Retirement Obligations

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

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

Foreign Currency Translation

Foreign Transactions

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

Foreign Operations

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

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

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

Financial Instruments

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

The measurement categories for each class of financial asset and financial liability is set forth in the following table.


Financial Instrument			Classification
Cash and cash equivalents			Amortized cost
Trade and other receivables			Amortized cost
Financial derivatives			Fair value through profit or loss
Trade and other payables			Amortized cost
Credit facilities			Amortized cost
Long-term notes			Amortized cost

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

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

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

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

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

Fair Value of Financial Instruments

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

•Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

•Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

•Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

Income Taxes

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

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

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

Share-based Compensation Plans

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

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

The Company has a cash-settled incentive award plan (the "Incentive Award Plan") pursuant to which incentive awards may be granted to officers and employees of the Company and its subsidiaries. Each incentive award entitles the holder to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables.

4. SEGMENTED FINANCIAL INFORMATION

Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations:

•Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada;

•U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the U.S.; and

•Corporate includes corporate activities and items not allocated between operating segments.


	Canada				U.S.				Corporate				Consolidated
Years Ended December 31	2021		2020		2021		2020		2021		2020		2021		2020

Revenue, net of royalties
Petroleum and natural gas sales	$	1,128,137	$	571,741	$	740,058	$	403,736	$	—	$	—	$	1,868,195	$	975,477
Royalties	(121,306)		(46,064)		(217,850)		(117,671)		—		—		(339,156)		(163,735)
	1,006,831		525,677		522,208		286,065		—		—		1,529,039		811,742

Expenses
Operating	257,658		247,050		85,344		84,295		—		—		343,002		331,345
Transportation	32,261		28,437		—		—		—		—		32,261		28,437
Blending and other	85,689		48,381		—		—		—		—		85,689		48,381
General and administrative	—		—		—		—		40,804		34,268		40,804		34,268

Exploration and evaluation	15,212		14,011		—		—		—		—		15,212		14,011
Depletion and depreciation	303,135		309,420		155,806		169,439		5,639		7,521		464,580		486,380
Impairment (reversal) loss	(1,100,000)		1,737,000		(442,414)		623,220		—		—		(1,542,414)		2,360,220
Share-based compensation	—		—		—		—		11,130		9,469		11,130		9,469
Financing and interest	—		—		—		—		111,159		125,441		111,159		125,441
Financial derivatives loss (gain)	—		—		—		—		287,872		(29,336)		287,872		(29,336)
Foreign exchange (gain) loss	—		—		—		—		(2,868)		8,688		(2,868)		8,688
(Gain) loss on dispositions	(9,856)		(901)		190		—		—		—		(9,666)		(901)
Other (income) expense	(2,857)		(2,128)		—		—		295		(3,176)		(2,562)		(5,304)
	(418,758)		2,381,270		(201,074)		876,954		454,031		152,875		(165,801)		3,411,099
Net income (loss) before income taxes	1,425,589		(1,855,593)		723,282		(590,889)		(454,031)		(152,875)		1,694,840		(2,599,357)
Income tax expense (recovery)
Current income tax (recovery) expense	(548)		469		1,820		105		—		—		1,272		574
Deferred income tax expense (recovery)	86,928		(77,201)		72,913		(57,199)		(79,873)		(26,567)		79,968		(160,967)
	86,380		(76,732)		74,733		(57,094)		(79,873)		(26,567)		81,240		(160,393)
Net income (loss)	$	1,339,209	$	(1,778,861)	$	648,549	$	(533,795)	$	(374,158)	$	(126,308)	$	1,613,600	$	(2,438,964)

Additions to exploration and evaluation assets	3,298		4,490		—		—		—		—		3,298		4,490
Additions to oil and gas properties	204,912		170,462		105,093		105,388		—		—		310,005		275,850
Property acquisitions	1,557		—		—		—		—		—		1,557		—
Proceeds from dispositions	(7,211)		(182)		(593)		—		—		—		(7,804)		(182)


As at	December 31, 2021		December 31, 2020
Canadian assets	$	2,658,281	$	1,646,412
U.S. assets	2,152,323		1,737,533
Corporate assets	24,039		24,151
Total consolidated assets	$	4,834,643	$	3,408,096

5. EXPLORATION AND EVALUATION ASSETS


	December 31, 2021		December 31, 2020
Balance, beginning of year	$	191,865	$	320,210
Capital expenditures	3,298		4,490

Property acquisitions	1,100		—
Divestitures	(166)		—
Property swaps	408		468
Impairment	—		(113,058)
Exploration and evaluation expense (1)	(15,212)		(14,011)
Transfers to oil and gas properties (note 6)	(7,727)		(8,585)
Foreign currency translation	(742)		2,351
Balance, end of year	$	172,824	$	191,865

(1)Exploration and evaluation expense balance consists of land expiries as at December 31, 2021.

At December 31, 2021, there were no indicators of impairment or impairment reversal for exploration and evaluation assets in any of the Company's CGUs.

At March 31, 2020, the Company identified indicators of impairment for the exploration and evaluation assets within each of its six CGUs. The estimated recoverable amount was below the carrying value of the exploration and evaluation assets in the Conventional, Peace River, Lloydminster, Viking and Eagle Ford CGUs and an impairment loss of $127.9 million was recorded at March 31, 2020. The recoverable amount of each CGU was based on its "FVLCD" and was estimated with reference to arm's length transactions in comparable locations and the discounted cash flows associated with the Company's future development plans. The following table indicates the impairment loss booked for each CGU at March 31, 2020.


	Impairment at March 31, 2020
Conventional CGU	$	4,000
Peace River CGU	20,000
Lloydminster CGU	42,000
Viking CGU	13,000
Eagle Ford CGU	48,861
	$	127,861

At December 31, 2020, the Company estimated the recoverable amount of the exploration and evaluation assets within each of its six CGUs due to the ongoing volatility in future oil and natural gas prices. The recoverable amount supported the carrying amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and no impairment loss or impairment reversal was recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded their carrying amounts which resulted in an impairment reversal of $14.8 million at December 31, 2020. The recoverable amount of each CGU was based on its FVLCD and was estimated with reference to arm's length transaction in comparable locations and the discounted cash flows associated with the Company's future development plans. The following table indicates the impairment reversal booked for the Viking and Eagle Ford CGUs at December 31, 2020.


	Impairment reversal at December 31, 2020



Viking CGU	$	2,000
Eagle Ford CGU	12,803
	$	14,803

6. OIL AND GAS PROPERTIES


	Cost		Accumulated depletion		Net book value
Balance, December 31, 2019	$	11,128,297	$	(5,740,408)	$	5,387,889
Capital expenditures	275,850		—		275,850

Transfers from exploration and evaluation assets (note 5)	8,585		—		8,585
Change in asset retirement obligations (note 9)	94,994		—		94,994
Property swaps	(1,190)		178		(1,012)
Impairment	—		(2,247,162)		(2,247,162)
Foreign currency translation	(82,860)		120,123		37,263
Depletion	—		(478,859)		(478,859)
Balance, December 31, 2020	$	11,423,676	$	(8,346,128)	$	3,077,548
Capital expenditures	310,005		—		310,005

Property acquisitions	274		—		274
Divestitures	(37,835)		32,844		(4,991)
Property swaps	(26,131)		25,900		(231)
Transfers from exploration and evaluation assets (note 5)	7,727		—		7,727
Change in asset retirement obligations (note 9)	(12,222)		—		(12,222)
Impairment reversal	—		1,542,414		1,542,414
Foreign currency translation	(31,977)		34,765		2,788
Depletion	—		(458,941)		(458,941)
Balance, December 31, 2021	$	11,633,517	$	(7,169,146)	$	4,464,371

Baytex recorded total impairment reversals related to oil and gas properties of $1.5 billion for the year ended December 31, 2021 and impairment losses related to oil and gas properties of $2.2 billion for the year ended December 31, 2020.

2021 Impairment Reversals

At December 31, 2021, we identified indicators of impairment reversal for oil and gas properties in five CGUs due to the increase in forecasted commodity prices in addition to changes in proved plus probable reserves. The recoverable amount for three CGUs exceeded their carrying amounts which resulted in an impairment reversal of $416 million recorded at December 31, 2021. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2021. The after-tax discount rates applied to the cash flows were between 12% and 19%.

At December 31, 2021, the recoverable amount of the five CGUs tested were calculated using the following benchmark reference prices for the years 2022 to 2031 adjusted for commodity differentials specific to the CGU. The prices and costs subsequent to 2031 have been adjusted for inflation at an annual rate of 2.0%.


	2022	2023	2024	2025	2026	2027	2028	2029	2030	2031
WTI crude oil (US$/bbl)	72.83	68.78	66.76	68.09	69.45	70.84	72.26	73.70	75.18	76.68
WCS heavy oil ($/bbl)	74.42	69.17	66.54	67.87	69.23	70.61	72.02	73.46	74.69	76.19
LLS crude oil (US$/bbl)	74.33	70.28	68.27	69.62	71.01	72.41	73.85	75.32	76.82	78.35
Edmonton par oil ($/bbl)	86.82	80.73	78.01	79.57	81.16	82.78	84.44	86.13	87.85	89.61
Henry Hub gas (US$/mmbtu)	3.85	3.44	3.17	3.24	3.30	3.37	3.44	3.50	3.58	3.65
AECO gas ($/mmbtu)	3.56	3.21	3.05	3.11	3.17	3.23	3.30	3.36	3.43	3.50
Exchange rate (CAD/USD)	1.26	1.26	1.26	1.26	1.26	1.26	1.26	1.26	1.26	1.26

The following table summarizes the recoverable amount and impairment reversal at December 31, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the five CGUs with respect to reasonably possible changes in key assumptions inherent in the estimate.


	Recoverable amount		Impairment reversal		Change in discount rate of 1%		Change in oil price of $2.50/bbl		Change in gas price of $0.25/mcf
Conventional CGU	$	77,846	$	19,000	$	—	$	3,000	$	8,000
Peace River CGU	489,274		251,000		8,500		53,000		3,500
Lloydminster CGU	479,411		146,000		12,500		52,000		—
Viking CGU	1,320,094		—		38,000		85,500		4,500
Eagle Ford CGU	2,008,478		—		97,200		138,800		31,300
	$	4,375,103	$	416,000	$	156,200	$	332,300	$	47,300

At June 30, 2021, we identified indicators of impairment reversal for oil and gas properties in each of our six CGUs due to the increase in forecasted commodity prices. The recoverable amount for each of our six CGUs exceeded their carrying amounts which resulted in an impairment reversal of $1.1 billion recorded at June 30, 2021. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020 and was adjusted by management for operations between December 31, 2020 and June 30, 2021. The after-tax discount rates applied to the cash flows were between 10% and 16%.

At June 30, 2021, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2.0%.


	2021	2022	2023	2024	2025	2026	2027	2028	2029	2030
WTI crude oil (US$/bbl)	71.33	67.20	63.95	63.23	64.50	65.79	67.10	68.44	69.81	71.21
WCS heavy oil ($/bbl)	72.22	66.84	61.73	60.70	61.91	63.15	64.42	65.70	67.02	68.36
LLS crude oil (US$/bbl)	72.17	68.53	65.80	65.10	66.39	67.71	69.05	70.42	71.82	73.26
Edmonton par oil ($/bbl)	83.20	78.27	74.06	73.05	74.51	76.00	77.52	79.07	80.66	82.27
Henry Hub gas (US$/mmbtu)	3.42	3.19	2.92	2.96	3.02	3.08	3.14	3.21	3.27	3.34
AECO gas ($/mmbtu)	3.46	3.13	2.72	2.71	2.76	2.82	2.88	2.94	2.99	3.05
Exchange rate (CAD/USD)	1.24	1.25	1.25	1.25	1.25	1.25	1.25	1.25	1.25	1.25

The following table summarizes the recoverable amount and impairment reversal at June 30, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible changes in key assumptions inherent in the estimate.


	Recoverable amount		Impairment reversal		Change in discount rate of 1%		Change in oil price of $2.50/bbl		Change in gas price of $0.25/mcf
Conventional CGU	$	57,891	$	15,000	$	1,000	$	1,000	$	8,000
Peace River CGU	238,714		154,000		4,000		40,000		2,500
Lloydminster CGU	340,730		154,000		12,500		52,000		—
Duvernay CGU(1)	115,157		5,000		45,000		44,500		44,500
Viking CGU	1,338,985		356,000		47,000		89,500		4,500
Eagle Ford CGU	2,015,118		442,415		109,400		103,900		24,400
	$	4,106,595	$	1,126,415	$	218,900	$	330,900	$	83,900

(1) The impairment reversal for the Duvernay CGU was limited to total accumulated impairments less subsequent depletion of $5.0 million.

2020 Impairments

At December 31, 2020, the Company estimated the recoverable amount of each of its six CGUs due to the volatility in commodity prices during the year and a reduction in future development costs per well for the Viking and Eagle Ford CGUs. The recoverable amount supported the carrying amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and no impairment or impairment reversal was recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded their carrying amounts which resulted in an impairment reversal of $341.3 million recorded at December 31, 2020. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020. The after-tax discount rates applied to the cash flows were between 10% and 17%.

At December 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2%.


	2021	2022	2023	2024	2025	2026	2027	2028	2029	2030
WTI crude oil (US$/bbl)	47.17	50.17	53.17	54.97	56.07	57.19	58.34	59.50	60.69	61.91
WCS heavy oil ($/bbl)	44.63	48.18	52.10	54.10	55.19	56.29	57.42	58.57	59.74	60.93
LLS crude oil (US$/bbl)	49.50	52.85	55.87	57.69	58.82	59.97	61.15	62.34	63.56	64.83
Edmonton par oil ($/bbl)	55.76	59.89	63.48	65.76	67.13	68.53	69.95	71.40	72.88	74.34
Henry Hub gas (US$/mmbtu)	2.83	2.87	2.90	2.96	3.02	3.08	3.14	3.20	3.26	3.33
AECO gas ($/mmbtu)	2.78	2.70	2.61	2.65	2.70	2.76	2.81	2.87	2.92	2.98
Exchange rate (CAD/USD)	1.30	1.31	1.31	1.31	1.31	1.31	1.31	1.31	1.31	1.31

The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably possible changes in key assumptions inherent in the estimate.


	Recoverable amount		Impairment reversal		Change in discount rate of 1%		Change in oil price of $2.50/bbl		Change in gas price of $0.25/mcf
Conventional CGU	$	54,265	$	—	$	1,000	$	3,000	$	9,000
Peace River CGU	104,225		—		1,000		49,500		3,000
Lloydminster CGU	212,979		—		7,000		57,500		500
Duvernay CGU	70,491		—		5,500		12,000		1,500
Viking CGU	1,026,026		116,000		34,500		106,500		5,000
Eagle Ford CGU	1,609,562		225,326		91,600		157,500		38,400
	$	3,077,548	$	341,326	$	140,600	$	386,000	$	57,400

At March 31, 2020, the Company identified indicators of impairment for each of its six CGUs due to a significant decline in forecasted commodity prices. The recoverable amount was not sufficient to support the carrying amount which resulted in an impairment of $2.6 billion recorded at March 31, 2020. The recoverable amount of each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2019 and was adjusted for operations between December 31, 2019 and March 31, 2020. The after-tax discount rates applied to the cash flows were between 8% and 14%.

At March 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2%.


	2020	2021	2022	2023	2024	2025	2026	2027	2028	2029
WTI crude oil (US$/bbl)	29.17	40.45	49.17	53.28	55.66	56.87	58.01	59.17	60.35	61.56
WCS heavy oil ($/bbl)	19.21	34.65	46.34	51.25	54.28	55.72	56.96	58.22	59.51	60.82
LLS crude oil (US$/bbl)	32.17	43.80	52.55	56.68	59.10	60.35	61.52	62.72	63.94	65.19
Edmonton par oil ($/bbl)	29.22	46.85	59.27	65.02	68.43	69.81	71.24	72.70	74.19	75.71
Henry Hub gas (US$/mmbtu)	2.10	2.58	2.79	2.86	2.93	3.00	3.07	3.13	3.19	3.25
AECO gas ($/mmbtu)	1.74	2.20	2.38	2.45	2.53	2.60	2.66	2.72	2.79	2.85
Exchange rate (CAD/USD)	1.41	1.37	1.34	1.34	1.34	1.33	1.33	1.33	1.33	1.33

The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably possible changes in key assumptions inherent in the estimate.


	Recoverable amount		Impairment		Change in discount rate of 1%		Change in oil price of $2.50/bbl		Change in gas price of $0.25/mcf
Conventional CGU	$	37,444	$	41,000	$	3,000	$	3,500	$	8,500
Peace River CGU	109,631		345,000		9,500		53,500		3,000
Lloydminster CGU	227,967		470,000		25,000		69,500		—
Duvernay CGU	61,197		5,000		5,500		9,500		1,500
Viking CGU	962,134		915,000		57,000		123,000		4,000
Eagle Ford CGU	1,576,423		812,488		120,750		141,500		32,000
	$	2,974,796	$	2,588,488	$	220,750	$	400,500	$	49,000

7. CREDIT FACILITIES


	December 31, 2021		December 31, 2020
Credit facilities - U.S. dollar denominated(1)	$	156,332	$	140,815
Credit facilities - Canadian dollar denominated	350,182		510,358
Credit facilities - principal(2)	$	506,514	$	651,173
Unamortized debt issuance costs	(1,343)		(1,952)
Credit facilities	$	505,171	$	649,221

(1)U.S. dollar denominated credit facilities balance was US$123.5 million as at December 31, 2021 (December 31, 2020 - US$110.4 million).

(2)The decrease in the principal amount of the credit facilities outstanding from December 31, 2020 to December 31, 2021 is the result of net repayments of $145.3 million and an increase in the reported amount of U.S. denominated debt of $0.7 million due to foreign exchange.

Baytex has US$575 million of revolving credit facilities (the "Revolving Facilities") and a $300 million non-revolving secured term loan (the "Term Loan") (collectively the "Credit Facilities"). The Credit Facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The $300 million Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership.

The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon Baytex's request. Advances (including letters of credit) under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates ("LIBOR"), plus applicable margins.

The LIBOR benchmark transition began on December 31, 2021. Certain tenors of the U.S. dollar LIBOR benchmark are no longer published as of December 31, 2021 while some tenors will continue to be published through mid-2023. We expect the U.S. dollar LIBOR benchmarks to be replaced with an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material impact to Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate.

The weighted average interest rate on the Credit Facilities was 2.1% for the year ended December 31, 2021 (2.4% for the year ended December 31, 2020).

At December 31, 2021, Baytex had $15.0 million of outstanding letters of credit under the Credit Facilities (December 31, 2020 - $15.0 million).

At December 31, 2021, Baytex was in compliance with all of the covenants contained in the Credit Facilities and is forecasting compliance with these covenants based on current forward commodity prices. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2021.


Covenant Description	Position as at December 31, 2021	Covenant
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)	0.6:1.0	3.5:1.0
Interest Coverage(3) (Minimum Ratio)	9.1:1.0	2.0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreements and is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at December 31, 2021, the Company's Senior Secured Debt totaled $521.5 million.

(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the year ended December 31, 2021 was $836.9 million.

(3)"Interest coverage" is calculated in accordance with the credit agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the year ended December 31, 2021 was $91.8 million.

8. LONG-TERM NOTES


	December 31, 2021		December 31, 2020
5.625% notes (US$200,000 – principal) due June 1, 2024	253,120		510,200
8.75% notes (US$500,000 – principal) due April 1, 2027	632,800		637,750
Total long-term notes - principal(1)	$	885,920	$	1,147,950
Unamortized debt issuance costs	(11,393)		(15,082)
Total long-term notes - net of unamortized debt issuance costs	$	874,527	$	1,132,868

(1)The decrease in the principal amount of long-term notes outstanding from December 31, 2020 to December 31, 2021 is the result of principal repayments of $249.4 million and changes in the reported amount of U.S. denominated debt of $12.6 million.

During 2021, Baytex repurchased and cancelled principal notes totaling US$200 million of the 5.625% Notes and recorded early redemption expense of $1.9 million. As at December 31, 2021, there was a total of US$200.0 million of the 5.625% Notes that remained outstanding.

On February 5, 2020, Baytex issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable at Baytex's option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.2 million.

The long-term notes do not contain any significant financial maintenance covenants.

9. ASSET RETIREMENT OBLIGATIONS


	December 31, 2021		December 31, 2020
Balance, beginning of year	$	760,383	$	667,974
Liabilities incurred	14,845		15,189
Liabilities settled	(6,662)		(7,168)

Liabilities acquired from property acquisitions	249		—
Liabilities divested	(3,161)		(721)
Property swaps	(4,113)		(525)
Accretion (note 15)	12,381		8,978
Government grants(1)	(2,857)		(2,128)
Change in estimate	(9,686)		(12,771)
Changes in discount rates and inflation rates(2)	(17,381)		92,576
Foreign currency translation	(315)		(1,021)
Balance, end of year	$	743,683	$	760,383
Less current portion of asset retirement obligations	11,080		11,820
Non-current portion of asset retirement obligations	$	732,603	$	748,563

(1)During 2021, Baytex recognized $2.9 million of non-cash other income and a reduction in asset retirement obligations related to government grants provided by the Government of Alberta and the Government of Saskatchewan ($2.1 million in 2020).

(2)The discount and inflation rates at December 31, 2021 were 1.7% and 1.8% respectively (December 31, 2020 - 1.2% and 1.5%).

At December 31, 2021, the undiscounted amount of estimated cash flows required to settle the asset retirement obligations is $721.7 million (December 31, 2020 - $721.0 million). The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2021, calculated using an estimated inflation rate of 1.8% (December 31, 2020 - 1.5%) and a risk free discount rate of 1.7% (December 31, 2020 - 1.2%), is $743.7 million (December 31, 2020 - $760.4 million). These costs are expected to be incurred over the next 60 years.

10. SHAREHOLDERS' CAPITAL

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at December 31, 2021, no preferred shares have been issued by the Company and all common shares issued were fully paid.

The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meeting of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated.


	Number of Common Shares (000s)	Amount
Balance, December 31, 2019	558,305	$	5,718,835
Vesting of share awards	2,922	10,583


Balance, December 31, 2020	561,227	$	5,729,418
Vesting of share awards	2,986	7,175


Balance, December 31, 2021	564,213	$	5,736,593

11. SHARE-BASED COMPENSATION PLAN

For the year ended December 31, 2021, the Company recorded total compensation expense related to the share awards of $11.1 million ($9.5 million for the year ended December 31, 2020) which includes $4.7 million of compensation expense related to the incentive award plan, deferred share unit plan and the associated equity total return swaps ($2.3 million for the year ended December 31, 2020).

Share Award Incentive Plan

Baytex has a share award plan pursuant to which it issues restricted and performance awards. A restricted award entitles the holder of each award to receive one common share of Baytex at the time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares on vesting; the number of common shares issued is determined by a multiplier. The multiplier, which ranges between zero and two, is calculated based on a number of factors determined and approved by the Board of Directors on an annual basis. The restricted awards and performance awards vest in equal tranches on the first, second and third anniversaries of the grant date. At Baytex's option, these awards may be cash settled at vesting.

The weighted average fair value of share awards granted during the year ended December 31, 2021 was $1.31 per restricted and performance award ($1.48 for the year ended December 31, 2020).

The number of share awards outstanding is detailed below:


(000s)	Number of restricted awards	Number of performance awards	Total number of share awards
Balance, December 31, 2019	3,801	3,135	6,936
Granted	2,239	3,253	5,492

Vested and converted to common shares	(1,730)	(1,192)	(2,922)
Forfeited	(188)	(1,108)	(1,296)
Balance, December 31, 2020	4,122	4,088	8,210
Granted	—	4,067	4,067

Added by performance factor	—	669	669
Vested and converted to common shares	(1,861)	(1,152)	(3,013)
Forfeited	(168)	(291)	(459)
Balance, December 31, 2021	2,093	7,381	9,474

Incentive Award Plan

Baytex has an incentive award plan (the "Incentive Award" plan) whereby the holder of each incentive award is entitled to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables.

During the year ended December 31, 2021, Baytex granted 5.0 million awards under the Incentive Award plan at a fair value of $1.33 per award (2.9 million awards at $1.50 per award for the year ended December 31, 2020). At December 31, 2021 there were 6.4 million awards outstanding under the Incentive Award plan (2.6 million awards outstanding at December 31, 2020).

Deferred Share Unit Plan

Baytex has a deferred share unit plan (the "DSU" plan) whereby each Director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share on the date on which they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period end and are included in trade and other payables.

During the year ended December 31, 2021, Baytex granted 0.9 million awards under the DSU plan at a fair value of $1.29 per award. At December 31, 2021, there were 0.8 million awards outstanding under the DSU plan.

The Company uses equity total return swaps on the equivalent number of Baytex common shares in order to fix a portion of the aggregate cost of the Incentive Award plan and the DSU plan at the fair value determined on the grant date. The carrying value of the financial derivatives includes the fair value of the equity total return swap which was an asset of $6.5 million on December 31, 2021 (December 31, 2020 - liability of $1.1 million). At December 31, 2021, an asset of $10.7 million associated with the equity return swap is included in accounts payable as it relates to the settlement of cash compensation payable (December 31, 2020 - a liability of $1.2 million).

12. NET INCOME (LOSS) PER SHARE

Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards were converted to common shares. The treasury stock method is used to determine the dilutive effect of share awards whereby the potential conversion of share awards and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the year.


	Years Ended December 31
	2021					2020
	Net income		Weighted average common shares (000's)	Net income per share		Net loss		Weighted average common shares (000's)	Net loss per share
Net income (loss) - basic	$	1,613,600	563,674	$	2.86	$	(2,438,964)	560,657	$	(4.35)
Dilutive effect of share awards	—		7,936	—		—		—	—
Net income (loss) - diluted	$	1,613,600	571,610	$	2.82	$	(2,438,964)	560,657	$	(4.35)

For the year ended December 31, 2021, no share awards were excluded from the calculation of diluted income per share as their effect was dilutive. For the year ended December 31, 2020, all share awards were excluded from the calculation of diluted earnings per share as their effect was anti-dilutive given the Company recorded a net loss.

13. PETROLEUM AND NATURAL GAS SALES

Petroleum and natural gas sales from contracts with customers for the Company's Canadian and U.S. operating segments is set forth in the following table.


	Years Ended December 31
	2021						2020
	Canada		U.S.		Total		Canada		U.S.		Total
Light oil and condensate	$	480,199	$	585,635	$	1,065,834	$	296,125	$	327,460	$	623,585
Heavy oil	560,696		—		560,696		236,235		—		236,235
NGL	18,904		75,611		94,515		6,037		34,845		40,882
Natural gas sales	68,338		78,812		147,150		33,344		41,431		74,775
Total petroleum and natural gas sales	$	1,128,137	$	740,058	$	1,868,195	$	571,741	$	403,736	$	975,477

Included in accounts receivable at December 31, 2021 is $154.0 million of accrued receivables related to delivered volumes (December 31, 2020 - $81.3 million).

14. INCOME TAXES

The provision for income taxes has been computed as follows:


	Years Ended December 31
	2021		2020
Net income (loss) before income taxes	$	1,694,840	$	(2,599,357)
Expected income taxes at the statutory rate of 25.12% (2020 – 25.42%)	425,744		(660,757)
(Increase) decrease in income tax recovery resulting from:
Share-based compensation	1,605		1,834
Effect of foreign exchange	(841)		1,017
Effect of change in income tax rates	(65)		10,969
Effect of rate adjustments for foreign jurisdictions	(21,746)		22,375

Effect of change in deferred tax benefit not recognized	(325,295)		444,117
Effect of U.S. tax change	—		19,807
Adjustments and assessments	1,838		245
Income tax expense (recovery)	$	81,240	$	(160,393)

At December 31, 2021, a deferred tax asset of $145.6 million remains unrecognized due to uncertainty surrounding future commodity prices and future capital gains (December 31, 2020 - $469.7 million). These deferred income tax assets relate to capital losses of $237.4 million and non-capital losses of $461.1 million, which expire from 2033 to 2039.

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

A continuity of the net deferred income tax liability is detailed in the following tables:


As at	January 1, 2021		Recognized in Net Income		Foreign Currency Translation Adjustment		December 31, 2021
Taxable temporary differences:
Petroleum and natural gas properties	$	(502,625)	$	(257,800)	$	(154)	$	(760,579)
Financial derivatives	—		—		—		—

Other	(22,377)		624		137		(21,616)
Deductible temporary differences:
Asset retirement obligations	187,840		(2,436)		(68)		185,336
Financial derivatives	5,410		26,082		—		31,492
Non-capital losses	241,514		104,479		(3,109)		342,884
Finance costs	3,705		49,083		2,239		55,027
Net deferred income tax liability(1)	$	(86,533)	$	(79,968)	$	(955)	$	(167,456)

(1)Non-capital loss carry-forwards at December 31, 2021 totaled $2.0 billion and expire from 2033 to 2039.


As at	January 1, 2020		Recognized in Net Loss		Foreign Currency Translation Adjustment		December 31, 2020
Taxable temporary differences:
Petroleum and natural gas properties	$	(881,994)	$	378,321	$	1,048	$	(502,625)
Financial derivatives	—		—		—		—

Other	(2,403)		(18,839)		(1,135)		(22,377)
Deductible temporary differences:
Asset retirement obligations	164,523		23,432		(115)		187,840
Financial derivatives	802		4,608		—		5,410
Non-capital losses	386,717		(141,468)		(3,735)		241,514
Finance costs	97,047		(85,087)		(8,255)		3,705
Net deferred income tax liability(1)	$	(235,308)	$	160,967	$	(12,192)	$	(86,533)

(1)Non-capital loss carry-forwards at December 31, 2020 totaled $2.2 billion and expire from 2034 to 2040.

15. FINANCING AND INTEREST


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

16. FOREIGN EXCHANGE


	Years Ended December 31
	2021		2020
Unrealized foreign exchange loss - intercompany notes(1)	$	12,000	$	31,617
Unrealized foreign exchange gain - long-term notes & credit facilities	(13,905)		(22,385)
Realized foreign exchange gain	(963)		(544)
Foreign exchange (gain) loss	$	(2,868)	$	8,688

(1)During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. During 2021, US$150.0 million of these notes were redeemed and cancelled. At December 31, 2021, US$601.0 million of this series of intercompany notes remained outstanding. These notes are eliminated upon consolidation within the Statement of Financial Position and are revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.

17. 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, credit facilities and long-term notes. The fair value of the credit facilities is equal to the principal amount outstanding as the credit facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices.

The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories:


	December 31, 2021				December 31, 2020
	Carrying value		Fair value		Carrying value		Fair value		Fair Value Measurement Hierarchy
Financial Assets
FVTPL
Financial Derivatives	$	8,654	$	8,654	$	5,057	$	5,057	Level 2
Total	$	8,654	$	8,654	$	5,057	$	5,057

Amortized cost

Trade and other receivables	$	173,409	$	173,409	$	107,477	$	107,477	—
Total	$	173,409	$	173,409	$	107,477	$	107,477

Financial Liabilities
FVTPL
Financial Derivatives	$	(134,020)	$	(134,020)	$	(26,792)	$	(26,792)	Level 2
Total	$	(134,020)	$	(134,020)	$	(26,792)	$	(26,792)

Amortized cost
Trade and other payables	$	(190,692)	$	(190,692)	$	(155,955)	$	(155,955)	—
Credit Facilities	(505,171)		(506,514)		(649,221)		(651,173)		—
Long-term notes	(874,527)		(917,889)		(1,132,868)		(761,129)		Level 1
Total	$	(1,570,390)	$	(1,615,095)	$	(1,938,044)	$	(1,568,257)

There were no transfers between Level 1 and Level 2 during the years ended December 31, 2021 or 2020.

Foreign Currency Risk

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

A $0.01 increase or decrease in the CAD/USD foreign exchange rate on the revaluation of outstanding U.S. dollar denominated assets and liabilities would impact net income or loss before income taxes by approximately $2.3 million.

The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows:

Assets

Liabilities

December 31, 2021

December 31, 2020

December 31, 2021

December 31, 2020

U.S. dollar denominated

US$602,503

US$759,508

US$829,934

US$934,731

Interest Rate Risk

The Company's interest rate risk arises from borrowing at floating rates under the Credit Facilities (note 7). Based on the principal outstanding on the Credit Facilities as at December 31, 2021, a change of 100 basis points in interest rates would impact net income or loss before income taxes by approximately $5.1 million.

Commodity Price Risk

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

When assessing the potential impact of crude oil price changes on the crude oil financial derivative contracts outstanding as at December 31, 2021, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $10.4 million.

When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2021, a US$0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $3.7 million.

Financial Derivative Contracts

Baytex had the following commodity financial derivative contracts outstanding as at February 24, 2022.

Period

Volume

Price/Unit(1)

Index

Oil

Basis swap

Jan 2022 to Dec 2022

12,000 bbl/d

WTI less US$12.40/bbl

WCS

Basis swap

Jan 2022 to Dec 2022

4,000 bbl/d

WTI less US$4.43/bbl

MSW

Basis swap(3)

Feb 2022 to Jun 2022

1,000 bbl/d

WTI less US$3.00/bbl

MSW

Basis swap(3)

Mar 2022 to Dec 2022

2,000 bbl/d

WTI less US$2.88/bbl

MSW

Fixed - Sell

Jan 2022 to Dec 2022

10,000 bbl/d

US$53.50/bbl

WTI

3-way option(2)

Jan 2022 to Dec 2022

1,500 bbl/d

US$40.00/US$50.00/US$58.10

WTI

3-way option(2)

Jan 2022 to Dec 2022

2,000 bbl/d

US$46.00/US$56.00/US$66.72

WTI

3-way option(2)

Jan 2022 to Dec 2022

2,500 bbl/d

US$47.00/US$57.00/US$67.00

WTI

3-way option(2)

Jan 2022 to Dec 2022

2,500 bbl/d

US$50.00/US$60.00/US$70.00

WTI

3-way option(2)

Jan 2022 to Dec 2022

2,000 bbl/d

US$53.00/US$63.50/US$72.90

WTI

3-way option(2)

Jan 2023 to Dec 2023

2,000 bbl/d

US$55.00/US$66.00/US$84.00

WTI

3-way option(2)(3)

Jan 2023 to Dec 2023

2,500 bbl/d

US$60.00/US$75.00/US$91.54

WTI

Natural Gas

Fixed - Sell

Jan 2022 to Dec 2022

5,000 GJ/d

$2.53/GJ

AECO 7A

Fixed - Sell

Jan 2022 to Dec 2022

14,250 GJ/d

$2.84/GJ

AECO 5A

Fixed - Sell

Jan 2022 to Dec 2022

1,000 mmbtu/d

US$2.94/mmbtu

NYMEX

3-way option(2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$2.25/US$2.75/US$3.06

NYMEX

3-way option(2)

Jan 2022 to Dec 2022

1,500 mmbtu/d

US$2.60/US$2.91/US$3.56

NYMEX

3-way option(2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$2.60/US$3.00/US$3.83

NYMEX

3-way option(2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$2.65/US$2.90/US$3.40

NYMEX

3-way option(2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$3.00/US$3.75/US$4.40

NYMEX

(1)Based on the weighted average price per unit for the period.

(2)Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$50.00/US$60.00/US$70.00 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$60.00/bbl when WTI is between US$50.00/bbl and US$60.00/bbl; Baytex receives the market price when WTI is between US$60.00/bbl and US$70.00/bbl; and Baytex receives US$70.00/bbl when WTI is above US$70.00/bbl.

(3)Contracts entered subsequent to December 31, 2021.

The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.


	Years Ended December 31
	2021		2020
Realized financial derivatives loss (gain)	$	184,241	$	(47,836)
Unrealized financial derivatives loss	103,631		18,500
Financial derivatives loss (gain)	$	287,872	$	(29,336)

Liquidity Risk

Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Such strategies include monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements, opportunities to issue additional common shares as well as reducing capital expenditures.

As at December 31, 2021, Baytex had $506.5 million of principal amounts and $15.0 million of letters of credit outstanding on its Credit Facilities (December 31, 2020 - $651.2 million and $15.0 million, respectively) which have total availability of $1.0 billion (December 31, 2020 - $1.0 billion).

The timing of cash outflows relating to financial liabilities as at December 31, 2021 is outlined in the table below:


	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	190,692	$	190,692	—		$	—	$	—
Financial derivatives	134,020		134,020		—		—		—
Credit facilities(1)(2)	506,514		—		506,514		—		—
Long-term notes(1)(3)	885,920		—		253,120		—		632,800
Interest on long-term notes(4)	325,172		69,608		130,868		110,740		13,956
Lease obligations(1)	8,014		3,068		3,989		902		55
	$	2,050,332	$	397,388	$	894,491	$	111,642	$	646,811

(1)Principal amount of instruments.

(2)The credit facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing the Company has either refinanced or has the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

(3)Principal amount of instruments. The US$500 million principal amount of 8.75% senior unsecured notes is due April 1, 2027 and the US$200 million principal amount of the 5.625% senior unsecured notes is due June 1, 2024 (note 8).

(4)Excludes interest on credit facilities as interest payments on credit facilities fluctuate based on amounts outstanding and the prevailing interest rate at the time of borrowing.

Credit Risk

Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31, 2021, the Company is exposed to credit risk with respect to its trade and other receivables and financial derivatives. Baytex manages these risks through the selection and monitoring of credit-worthy counterparties.

Most of the Company's trade and other receivables relate to petroleum and natural gas sales. Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts after reviewing the creditworthiness of the entity. Letters of credit or parental guarantees may be obtained prior to the commencement of business with certain counterparties. Credit risk may also arise from financial derivative instruments. The maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company considers all financial assets that are not impaired or past due to be of good credit quality.

The majority of the Company's credit exposure on trade and other receivables at December 31, 2021 relates to accrued revenues. Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day of the month following production. Joint interest receivables are typically collected within one to three months following production. Included in trade and other receivables at December 31, 2021 is $154.0 million (December 31, 2020 - $81.3 million) of accrued receivables related to delivered volumes.

Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of trade and other receivables is reduced by adjusting the allowance for doubtful accounts and recording a charge to net income or loss. If the Company subsequently determines the accounts receivable is uncollectible, the receivable and allowance for doubtful accounts are adjusted accordingly. As at December 31, 2021, allowance for doubtful accounts was $2.6 million (December 31, 2020 - $2.0 million).

In determining whether amounts past due are collectible, the Company will assess the nature of the past due amounts as well as the credit worthiness and past payment history of the counterparty. As at December 31, 2021, accounts receivable that Baytex has deemed past due (more than 90 days) but not impaired was $1.8 million (December 31, 2020 - $1.6 million). Baytex has estimated the lifetime expected credit loss as at and for the year ended December 31, 2021 to be nominal.

The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2021.


Trade and Other Receivables Aging	December 31, 2021		December 31, 2020
Current (less than 30 days)	$	171,058	$	104,210
31-60 days	441		1,493
61-90 days	107		220
Past due (more than 90 days)	1,803		1,554
	$	173,409	$	107,477

18. SUPPLEMENTAL INFORMATION

Changes in Non-Cash Working Capital Items


	Years Ended December 31
	2021		2020
Trade and other receivables	$	(65,932)	$	66,285
Trade and other payables	34,737		(51,499)

	$	(31,195)	$	14,786
Changes in non-cash working capital related to:
Operating activities	$	(26,582)	$	48,758
Investing activities	(2,797)		(32,031)
Foreign currency translation on non-cash working capital	(1,816)		(1,941)
	$	(31,195)	$	14,786

Income Statement Presentation

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

The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense.


	Years Ended December 31
	2021		2020
Operating	$	11,053	$	9,065
General and administrative	29,538		22,802
Total employee compensation costs	$	40,591	$	31,867

19. COMMITMENTS

Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s cash flow from operations in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of December 31, 2021, and the expected timing of funding of these obligations, are noted in the table below.


	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Processing agreements	$	6,090	753		890		530		3,917
Transportation agreements	81,182		20,500		37,825		14,673		8,184
Total	$	87,272	$	21,253	$	38,715	$	15,203	$	12,101

Baytex also has ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached the end of their economic lives. The present value of the future estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statements of financial position. Programs to abandon and reclaim wellsites and facilities are undertaken regularly in accordance with applicable legislative requirements.

20. RELATED PARTIES

Transactions with key management personnel and directors are noted in the table below.


	Years Ended December 31
	2021		2020
Short-term employee benefits	$	5,995	$	4,295
Share-based compensation	5,917		4,080

Total compensation for key management personnel	$	11,912	$	8,375

21. CAPITAL MANAGEMENT

The Company's capital management objective is to maintain financial flexibility and sufficient sources of liquidity to execute its capital programs, while meeting short and long-term commitments. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At December 31, 2021, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other payables and the Credit Facilities.

In order to manage its capital structure and liquidity, Baytex may from time to time issue equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.

The capital intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Baytex's capital resources consist primarily of Adjusted Funds Flow, available Credit Facilities and proceeds received from the divestiture of oil and gas properties. The following capital management measures and ratios are used to monitor current and projected sources of liquidity.

Net Debt

The Company uses Net Debt to monitor it's current financial position and to evaluate existing sources of liquidity. Baytex also uses Net Debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations.

The following table reconciles Net Debt to amounts disclosed in the primary financial statements.


	December 31, 2021		December 31, 2020
Credit facilities	$	505,171	$	649,221
Unamortized debt issuance costs - Credit Facilities (note 7)	1,343		1,952
Long-term notes	874,527		1,132,868
Unamortized debt issuance costs - Long-term notes (note 8)	11,393		15,082
Trade and other payables	190,692		155,955

Trade and other receivables	(173,409)		(107,477)
Net Debt	$	1,409,717	$	1,847,601

Adjusted Funds Flow

Adjusted Funds Flow is used to monitor operating performance and the Company's ability to generate funds for exploration and development expenditures, debt repayment, settlement of abandonment obligations and potential future dividends. Baytex also uses a Net Debt to Adjusted Funds Flow ratio calculated on a twelve-month trailing basis to monitor the Company's existing capital structure and future liquidity requirements.

Adjusted Funds Flow is reconciled to amounts disclosed in the primary financial statements in the following table.


	Years Ended December 31
	2021		2020
Cash flows from operating activities	$	712,384	$	353,096
Change in non-cash working capital	26,582		(48,758)
Asset retirement obligations settled	6,662		7,168

Adjusted Funds Flow	$	745,628	$	311,506
Net Debt to Adjusted Funds Flow	1.9		5.9