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

Exhibit 99.1

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Baytex Energy Corp. (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision of our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on our assessment, we have concluded that as of December 31, 2018, our internal control over financial reporting was effective. Management excluded from its design and assessment the internal control over financial reporting for Raging River Exploration Inc. (as permitted by applicable securities laws in Canada and the U.S.), which was acquired on August 22, 2018. The consolidated financial statements as at and for the year ended December 31, 2018 include $2.1 billion of total assets and $142.3 million of revenues, net of royalties from the acquired entity.

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, 2018 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, 2018.

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.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

The Company's internal controls over financial reporting commencing August 22, 2018 include Raging River's systems, processes and controls, as well as additional controls designed to result in complete and accurate consolidation of Raging River's results. Other than Raging River, there has been no change in the Baytex's internal control over financial reporting that occurred during 2018 that has materially affected, or are reasonably likely to materially affect, Baytex's internal control over financial reporting.

Edward D. LaFehr	Rodney D. Gray
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer
Baytex Energy Corp.	Baytex Energy Corp.
March 5, 2019

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statements of financial position of Baytex Energy Corp. (the "Company") as of December 31, 2018 and December 31, 2017, the consolidated statements of income (loss), 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, 2018 and December 31, 2017, and the results of its operations 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, 2018, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 5, 2019 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 to 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.

Chartered Professional Accountants

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

March 5, 2019

Calgary, Canada

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on Internal Control Over Financial Reporting

We have audited Baytex Energy Corp.’s (the “Company”) internal control over financial reporting as of December 31, 2018, based on the 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, 2018, based on the 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 financial statements of the Company as of December 31, 2018 and 2017, and the related consolidated statements of income (loss), comprehensive income (loss), changes in equity, and cash flows for the years then ended, and related notes (collectively, the consolidated financial statements), and our report dated March 5, 2019 expressed and unqualified opinion on those consolidated financial statements.

The Company acquired Raging River Exploration Inc. during 2018, and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2018, Raging River Exploration Inc.'s internal control over financial reporting associated with total assets of $2.1 billion and total revenues, net of royalties, of $142.3 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2018. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Raging River Exploration Inc.

Basis for Opinion

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

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

Chartered Professional Accountants

March 5, 2019

Calgary, Canada

Baytex Energy Corp.

Consolidated Statements of Financial Position

(thousands of Canadian dollars)

As at	December 31, 2018			December 31, 2017
ASSETS
Current assets
Trade and other receivables (note 19)	$	111,564		$	112,844
Financial derivatives (note 19)	79,582			18,510
	191,146			131,354
Non-current assets
Exploration and evaluation assets (note 6)	358,935			272,974
Oil and gas properties (note 7)	5,817,889			3,958,309
Other plant and equipment (note 8)	9,228			9,474
	$	6,377,198		$	4,372,111
LIABILITIES
Current liabilities
Trade and other payables (note 19)	$	258,114		$	144,542
Financial derivatives (note 19)	—			50,095
Onerous contracts (note 20)	1,986			2,574
	260,100			197,211
Non-current liabilities
Bank loan (note 9)	520,700			212,138
Long-term notes (note 10)	1,583,240			1,474,184
Asset retirement obligations (note 11)	646,898			368,995
Deferred income tax liability (note 16)	310,836			204,698
	3,321,774			2,457,226
SHAREHOLDERS’ EQUITY
Shareholders' capital (note 12)	5,701,516			4,443,576
Contributed surplus	19,137			15,999
Accumulated other comprehensive income	667,874			463,104
Deficit	(3,333,103		)	(3,007,794		)
	3,055,424			1,914,885
	$	6,377,198		$	4,372,111

Commitments and contingencies (note 21)

See accompanying notes to the consolidated financial statements.

Naveen Dargan	Gregory K. Melchin
Director, Baytex Energy Corp.	Director, Baytex Energy Corp.

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Baytex Energy Corp.

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

(thousands of Canadian dollars, except per common share amounts)

Years Ended December 31	2018			2017
Revenue, net of royalties
Petroleum and natural gas sales (note 13)	$	1,428,870		$	1,099,867
Royalties	(313,754		)	(241,892		)
	1,115,116			857,975
Expenses
Operating	311,592			269,283
Transportation	36,869			33,985
Blending and other	68,832			59,345
General and administrative	45,825			47,389
Transaction costs (note 4)	13,074			—
Exploration and evaluation (note 6)	21,729			8,253
Depletion and depreciation (notes 7 and 8)	558,684			481,929
Impairment (note 7)	285,341			—
Share-based compensation (note 14)	19,534			15,509
Financing and interest (note 17)	119,086			113,638
Financial derivatives gain (note 19)	(43,550		)	(5,177		)
Foreign exchange loss (gain) (note 18)	108,294			(87,060		)
Gain on dispositions	(1,946		)	(12,081		)
Other expense (income)	(1,172		)	2,216
	1,542,192			927,229
Net loss before income taxes	(427,076		)	(69,254		)
Income tax recovery (note 16)
Current income tax recovery	(35		)	(1,085		)
Deferred income tax recovery	(101,732		)	(155,343		)
	(101,767		)	(156,428		)
Net income (loss) attributable to shareholders	$	(325,309	)	$	87,174
Other comprehensive income (loss)
Foreign currency translation adjustment	204,770			(166,759		)
Comprehensive income (loss)	$	(120,539	)	$	(79,585	)
Net income (loss) per common share (note 15)
Basic	$	(0.93	)	$	0.37
Diluted	$	(0.93	)	$	0.37
Weighted average common shares (note 15)
Basic	351,542			234,787
Diluted	351,542			237,249

See accompanying notes to the consolidated financial statements.

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Baytex Energy Corp.

Consolidated Statements of Changes in Equity

(thousands of Canadian dollars)

	Shareholders’ capital			Contributed surplus			Accumulated other comprehensive income			Deficit			Total equity
Balance at December 31, 2016	$	4,422,661		$	21,405		$	629,863		$	(3,094,968	)	$	1,978,961
Vesting of share awards (note 12)	20,915			(20,915		)	—			—			—
Share-based compensation (note 14)	—			15,509			—			—			15,509
Comprehensive income (loss) for the year	—			—			(166,759		)	87,174			(79,585		)
Balance at December 31, 2017	$	4,443,576		$	15,999		$	463,104		$	(3,007,794	)	$	1,914,885
Issued on corporate acquisition (note 4)	1,238,995			3,100			—			—			1,242,095
Issuance costs, net of tax (notes 4 and 12)	(551		)	—			—			—			(551		)
Vesting of share awards (note 12)	19,496			(19,496		)	—			—			—
Share-based compensation (note 14)	—			19,534			—			—			19,534
Comprehensive income (loss) for the year	—			—			204,770			(325,309		)	(120,539		)
Balance at December 31, 2018	$	5,701,516		$	19,137		$	667,874		$	(3,333,103	)	$	3,055,424

See accompanying notes to the consolidated financial statements.

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Baytex Energy Corp.

Consolidated Statements of Cash Flows

(thousands of Canadian dollars)

Years Ended December 31	2018			2017
CASH PROVIDED BY (USED IN):
Operating activities
Net income (loss) for the year	$	(325,309	)	$	87,174
Adjustments for:
Share-based compensation (note 14)	19,534			15,509
Unrealized foreign exchange loss (gain) (note 18)	106,143			(86,649		)
Exploration and evaluation (note 6)	21,729			8,253
Depletion and depreciation (notes 7 and 8)	558,684			481,929
Impairment (note 7)	285,341			—
Non-cash financing and accretion (note 17)	14,768			13,156
Unrealized financial derivatives (gain) loss (note 19)	(116,715		)	2,439
Gain on dispositions	(1,946		)	(12,081		)
Deferred income tax recovery (note 16)	(101,732		)	(155,343		)
Payments on onerous contracts (note 20)	(588		)	(6,746		)
Asset retirement obligations settled (note 11)	(14,035		)	(13,471		)
Change in non-cash working capital (note 20)	39,448			(8,962		)
	485,322			325,208
Financing activities
Increase (decrease) in bank loan	(21,295		)	33,347
Common share issuance costs (notes 4 and 12)	(755		)	—
Redemption of long-term notes	—			(8,582		)
	(22,050		)	24,765
Investing activities
Additions to exploration and evaluation assets (note 6)	(10,567		)	(7,118		)
Additions to oil and gas properties (note 7)	(485,154		)	(319,148		)
Additions to other plant and equipment (note 8)	(1,804		)	(238		)
Property acquisitions	(701		)	(71,643		)
Proceeds from dispositions (notes 6 and 7)	2,519			11,786
Change in non-cash working capital (note 20)	32,435			33,683
	(463,272		)	(352,678		)
Change in cash	—			(2,705		)
Cash, beginning of year	—			2,705
Cash, end of year	$	—		$	—
Supplementary information
Interest paid	$	102,230		$	98,101
Income taxes paid	$	—		$	49

See accompanying notes to the consolidated financial statements.

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Baytex Energy Corp.

Notes to the Consolidated Financial Statements

For the years ended December 31, 2018 and 2017

(all tabular amounts in thousands of Canadian dollars, except per common share amounts)

1. REPORTING ENTITY

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

2. BASIS OF PRESENTATION

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). The significant accounting policies set forth below were consistently applied to all periods presented.

The consolidated financial statements were approved by the Board of Directors of Baytex on March 5, 2019.

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

Measurement Uncertainty and Judgments

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

Reserves

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

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

Cash-generating Units ("CGUs")

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

Identification of Impairment and Impairment Reversal Indicators

Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. When completing this assessment, management considers internal and external sources of information including changes in future commodity prices, changes in industry regulations or royalty rates, asset performance and changes in the Company's estimates of economically recoverable reserves.

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Measurement of Recoverable Amount

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

Exploration and Evaluation ("E&E") Assets

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

Business Combinations

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

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

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

Joint Arrangements

Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint control, management considers whether the decisions regarding the capital and operating activities of the arrangement require unanimous consent.

Classification of a joint arrangement once joint control has been established also requires judgment. The type of joint arrangement is determined by assessing the rights and obligations arising from the arrangement given the structure, legal form, and terms agreed upon by the parties sharing control. Arrangements where the controlling parties have rights to the net assets of the arrangement are classified as joint ventures. Arrangements where the controlling parties have rights to the assets and revenues, and obligations for the liabilities and expenses, are classified as joint operations. Baytex does not have any joint arrangements that are structured through joint venture arrangements.

Financial Derivatives

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

Asset Retirement Obligations

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

Income Taxes

Regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. Interpretation and application of existing regulation and legislation requires management judgment. Income tax filings are subject

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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

Changes in significant accounting policies

Revenue from contracts with customers

Baytex adopted IFRS 15 Revenue from Contracts with Customers with a date of initial application of January 1, 2018, using the retrospective method. Baytex recognizes revenue when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. The standard also requires new disclosure, as to the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. Baytex analyzed its revenue streams and its contracts with customers on adoption.

For the year ended December 31, 2017, $8.3 million of commodity purchases related to heavy oil sales have been reclassified from petroleum and natural gas sales to blending and other expense to conform to the requirements of IFRS 15. There were no adjustments made to the January 1, 2018 opening statement of financial position on adoption. The additional disclosures required by IFRS 15 are provided in note 13 to these consolidated financial statements, in addition to the new significant accounting policy noted below.

Financial instruments

Baytex adopted IFRS 9 Financial Instruments, on January 1, 2018. The new standard includes three classifications for financial assets; measurement at amortized cost, fair value through profit or loss and fair value through comprehensive income. Under IFRS 9, where the fair value option is applied to financial liabilities, any change in fair value resulting from an entity’s own credit risk is recorded through other comprehensive income or loss rather than net income or loss. The new standard also introduces a credit loss model for evaluating impairment of financial assets.

The adoption of this standard did not result in a change in the recognition or measurement of any of the Company's financial instruments on transition. The table summarizes the change in classification categories for Baytex's financial assets and liabilities.

Financial Instrument	IAS 39 Classification	IFRS 9 Classification
Cash and cash equivalents	Fair value through profit or loss	Amortized cost
Trade and other receivables	Amortized cost	Amortized cost
Financial derivatives	Fair value through profit or loss	Fair value through profit or loss
Trade and other payables	Amortized cost	Amortized cost
Bank loan	Amortized cost	Amortized cost
Long-term notes	Amortized cost	Amortized cost

Significant accounting policies

Consolidation

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

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

Business Combinations

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

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Revenue Recognition

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

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

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

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

Exploration and Evaluation Assets

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

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

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

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

Oil and Gas Properties

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

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

Depletion and Depreciation

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

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The depreciation methods and estimated useful lives for other plant and equipment are as follows:

Classification	Method	Rate or period
Motor Vehicles	Diminishing balance	15%
Office Equipment	Diminishing balance	20%
Computer Hardware	Diminishing balance	30%
Furniture and Fixtures	Diminishing balance	10%
Leasehold Improvements	Straight-line over life of the lease	Various
Other Assets	Diminishing balance	Various

The expected lives of other plant and equipment are reviewed on an annual basis and, if necessary, changes in expected useful lives are accounted for prospectively. Field inventory, which is included in other plant and equipment, is valued at the lower of cost, using the weighted average cost method, or net realizable value and is not depreciated.

Impairment

Non-derivative financial assets

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

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

Non-financial assets

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

When reviewing for indicators of impairment and impairment reversal, and testing for impairment when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. FVLCD is determined as the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction between willing parties. In determining FVLCD, recent market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a pre-tax discount rate that reflects current market assessments of the time value of money.

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

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

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

Asset Retirement Obligations

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

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

Foreign Currency Translation

Foreign transactions

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

Foreign operations

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

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

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

Financial Instruments

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

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

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

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

Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition

Page 10

and amortized through net income or loss over the term of the financial instrument. Debt issuance costs related to the restructuring of credit facilities are capitalized and amortized as financing costs over the term of the credit facilities.

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

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

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

Fair Value of Financial Instruments

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

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

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

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

Income Taxes

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

Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period.

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

Share-based Compensation Plans

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

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

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

Future Accounting Pronouncements

Leases

In January 2016, the IASB issued IFRS 16 Leases which replaces IAS 17 Leases. IFRS 16 introduces a single recognition and measurement model for lessees, which will require recognition of lease assets and lease obligations on the balance sheet. Short-term leases and leases for low value assets are exempt from recognition and may be treated as operating leases and recognized through net income or loss. The standard is effective for annual periods beginning on or after January 1, 2019. IFRS 16 is required to be adopted either retrospectively or using the modified retrospective approach. The Company will adopt IFRS 16 on January 1, 2019 using the modified retrospective method. The modified retrospective approach does not require restatement of prior period comparative financial information as the Company will record the cumulative effect of applying the standard as an increase to right of use assets with a corresponding increase to lease obligations. The Company is currently in the process of quantifying the impact of the contracts that fall within the scope of IFRS 16. The Company expects adjustments for its office lease and the related subleases, field office leases, certain vehicles and field equipment, however, the full extent of the impact has not yet been finalized.

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4. BUSINESS COMBINATION

On August 22, 2018, Baytex completed a plan of arrangement whereby Baytex acquired, directly and indirectly, all of the issued and outstanding common shares of Raging River Exploration Inc. (“Raging River”), a publicly traded oil and gas producer with light oil producing properties in southwest Saskatchewan and Alberta. In identifying Baytex as the acquirer, Baytex considered, amongst other things, voting rights of all equity instruments, the intended corporate governance structure and composition of senior management of the combined company, in addition to various metrics used to evaluate the relative size of each company. All factors were considered in arriving at the conclusion that Baytex is the acquirer for accounting purposes.

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

The total consideration paid and estimates of the fair value of the assets acquired and liabilities assumed as at the date of the acquisition are set forth in the table below. All amounts are final.

Consideration
Common shares issued	$	1,238,995
Share based compensation (1)	3,100
Total consideration	$	1,242,095
Fair value of net assets acquired
Exploration and evaluation assets	$	97,858
Oil and gas properties	1,748,368
Working capital deficiency excluding bank debt and financial derivatives	(46,773		)
Financial derivatives	(5,548		)
Bank debt (2)	(316,800		)
Asset retirement obligations	(39,960		)
Deferred income tax liability	(195,050		)
Net assets acquired	$	1,242,095

(1) Following closing of the transaction, holders of units outstanding under Raging River's share based compensation plans are entitled to Baytex common shares rather than Raging River common shares with adjustment to the exercise price or quantity outstanding based on the exchange ratio for the Raging River shares. As a result, the fair value of the vested units was recognized by Baytex as additional consideration (see note 14).

(2) On August 22, 2018, Baytex amended its credit facilities to include the credit facility assumed in conjunction with the acquisition of Raging River and converted outstanding principal amounts to a non-revolving term loan which matures on June 4, 2020 (see note 9).

These consolidated financial statements include the results of operations of Raging River for the period following closing of the transaction on August 22, 2018. For the period from August 22, 2018 to December 31, 2018, the acquisition contributed revenues of $158.8 million and operating income of $98.6 million. Had the acquisition occurred on January 1, 2018, revenues would have increased by $379.5 million and operating income would have increased by $273.2 million for the year. Operating income is defined as revenue, net of royalties, less operating, transportation and blending expense.

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

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5. SEGMENTED FINANCIAL INFORMATION

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

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

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

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

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

(1) Includes acquisitions, net of proceeds from divestitures.

As at	December 31, 2018		December 31, 2017
Canadian assets	$	3,739,029	$	1,677,821
U.S. assets	2,628,941		2,684,816
Corporate assets	9,228		9,474
Total consolidated assets	$	6,377,198	$	4,372,111

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6. EXPLORATION AND EVALUATION ASSETS

	December 31, 2018			December 31, 2017
Balance, beginning of year	$	272,974		$	308,462
Capital expenditures	10,567			7,118
Corporate acquisition (note 4)	97,858			—
Property acquisitions	514			—
Divestitures	(1,021		)	(1,276		)
Exploration and evaluation expense	(21,729		)	(8,253		)
Transfers to oil and gas properties (Note 7)	(13,866		)	(20,198		)
Foreign currency translation	13,638			(12,879		)
Balance, end of year	$	358,935		$	272,974

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

At December 31, 2017, there were no indicators of impairment for the Company's exploration and evaluation assets.

7. OIL AND GAS PROPERTIES

	Cost			Accumulated depletion			Net book value
Balance, December 31, 2016	$	7,764,037		$	(3,611,868	)	$	4,152,169
Capital expenditures	319,148			—			319,148
Property acquisitions	136,007			—			136,007
Transfers from exploration and evaluation assets (note 6)	20,198			—			20,198
Transfers from other assets (note 8)	5,124			—			5,124
Change in asset retirement obligations (Note 11)	42,808			—			42,808
Divestitures	(105,272		)	49,291			(55,981		)
Foreign currency translation	(249,723		)	68,641			(181,082		)
Depletion	—			(480,082		)	(480,082		)
Balance, December 31, 2017	$	7,932,327		$	(3,974,018	)	$	3,958,309
Capital expenditures	485,154			—			485,154
Corporate acquisition (note 4)	1,748,368			—			1,748,368
Property acquisitions	202			—			202
Transfers from exploration and evaluation assets (note 6)	13,866			—			13,866
Change in asset retirement obligations (note 11)	238,662			—			238,662
Divestitures	(15		)	—			(15		)
Impairment	—			(285,341		)	(285,341		)
Foreign currency translation	325,969			(110,651		)	215,318
Depletion	—			(556,634		)	(556,634		)
Balance, December 31, 2018	$	10,744,533		$	(4,926,644	)	$	5,817,889

For the year ended December 31, 2018, the Company identified indicators of impairment for its Conventional and Eagle Ford CGUs and recorded total impairment expense to oil and gas properties of $285.3 million (2017 - nil). There were no indicators of impairment identified for the remaining CGUs as at December 31, 2018.

At December 31, 2018, indicators of impairment existed for the Conventional CGU due to a sustained decline in Canadian natural gas prices and a reduction in planned capital exploration and development expenditures. The recoverable amount was not sufficient to support the carrying amount of the CGU which resulted in an impairment of $65.0 million recorded as at December 31, 2018. The recoverable amount of the Conventional CGU was based on its VIU which was estimated using a discounted cash flow model

Page 15

based on an independent reserve report approved by the Board of Directors and a range of pre-tax discount rates between 8% and 20%.

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

The recoverable amount of each CGU was calculated at December 31, 2018 using the following benchmark reference prices for the years 2019 to 2023 adjusted for commodity differentials specific to the Company.

	2019	2020	2021	2022	2023
WTI crude oil (US$/bbl)	63.00	67.00	70.00	71.40	72.83
LLS crude oil (US$/bbl)	68.40	70.37	71.34	72.76	74.22
Edmonton par (CA$/bbl)	75.27	77.89	82.25	84.79	87.39
NYMEX gas (US$/mmbtu)	3.00	3.25	3.50	3.57	3.64
AECO (CA$/GJ)	1.95	2.44	3.00	3.21	3.30
Exchange rate (CAD/USD)	1.30	1.25	1.25	1.25	1.25

This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2023 have been adjusted for inflation at an annual rate of 2.0%.

The following table demonstrates the sensitivity of the estimated recoverable amount of reasonably possible changes in key assumptions inherent in the estimate.

	Increase in discount rate of 1 percent		Decrease in discount rate of 1 percent			Increase in oil price of $2.50/bbl			Decrease in oil price of $2.50/bbl		Increase in gas price of $0.25/mcf			Decrease in gas price of $0.25/mcf
Conventional CGU	$	4,501	$	(4,673	)	$	(6,000	)	$	6,000	$	(12,000	)	$	12,000
Eagle Ford CGU	137,820		(155,562		)	(155,559		)	155,559		(31,385		)	31,385
Impairment increase (decrease)	$	142,321	$	(160,235	)	$	(161,559	)	$	161,559	$	(43,385	)	$	43,385

8. OTHER PLANT AND EQUIPMENT

	Cost			Accumulated depreciation			Net book value
Balance, December 31, 2016	$	67,698		$	(51,339	)	$	16,359
Capital expenditures	329			—			329
Dispositions, net of acquisitions	(255		)	—			(255		)
Transfers to oil and gas properties (note 7)	(5,124		)	—			(5,124		)
Foreign currency translation	—			12			12
Depreciation	—			(1,847		)	(1,847		)
Balance, December 31, 2017	62,648			(53,174		)	9,474
Capital expenditures	1,804			—			1,804
Depreciation	—			(2,050		)	(2,050		)
Balance, December 31, 2018	$	64,452		$	(55,224	)	$	9,228

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9. BANK LOAN

	December 31, 2018			December 31, 2017
Bank loan - U.S. dollar denominated(1)	$	122,388		$	167,159
Bank loan - Canadian dollar denominated	399,906			46,217
Bank loan - principal	522,294			213,376
Unamortized debt issuance costs	(1,594		)	(1,238		)
Bank loan	$	520,700		$	212,138

(1) U.S. dollar denominated bank loan balance was US$89.7 million as at December 31, 2018 (US$133.5 million as at December 31, 2017).

Baytex has credit facilities that include US$575 million of revolving credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving term loan (the "Term Loan"). On August 22, 2018, Baytex amended its credit facilities to include the Term Loan assumed in conjunction with the acquisition of Raging River (note 4) which matures on June 4, 2020.

The extendible secured Revolving Facilities are comprised of a US$35 million operating loan and a US$340 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. and matures on June 4, 2020. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership and matures on June 4, 2020.

The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The credit facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity on June 4, 2020 which could be extended upon Baytex's request. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates, plus applicable margins. In the event that Baytex breaches any of the covenants under the credit facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders.

At December 31, 2018 and 2017, Baytex had $14.6 million of outstanding letters of credit under the credit facilities.

At December 31, 2018, Baytex was in compliance with all of the covenants contained in the credit facilities including the financial covenants as summarized below.

Covenant Description	Position as at December 31, 2018	Covenant
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)	0.64:1.00	3.50:1.00
Interest Coverage(3) (Minimum Ratio)	8.00:1.00	2.00:1.00

(1) "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at December 31, 2018, the Company's Senior Secured Debt totaled $536.9 million which includes $522.3 million of principal amounts outstanding and $14.6 million of letters of credit.

(2) Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, unrealized gains and losses on financial derivatives, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2018 was $833.7 million.

(3) Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended December 31, 2018 were $104.3 million.

10. LONG-TERM NOTES

	December 31, 2018			December 31, 2017
6.75% notes (US$150,000 – principal) due February 17, 2021	204,683			187,770
5.125% notes (US$400,000 – principal) due June 1, 2021	545,820			500,720
6.625% notes (Cdn$300,000 – principal) due July 19, 2022	300,000			300,000
5.625% notes (US$400,000 – principal) due June 1, 2024	545,820			500,720
Total long-term notes - principal	1,596,323			1,489,210
Unamortized debt issuance costs	(13,083		)	(15,026		)
Total long-term notes - net of unamortized debt issuance costs	$	1,583,240		$	1,474,184

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The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts the Company's ability to raise additional debt beyond the existing credit facilities and long-term notes unless the Company maintains a minimum fixed charge coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 9) to financing and interest expenses on a trailing twelve month basis) of 2.50:1.00. As at December 31, 2018, the fixed charge coverage ratio was 8.00:1.00.

11. ASSET RETIREMENT OBLIGATIONS

	December 31, 2018			December 31, 2017
Balance, beginning of year	$	368,995		$	331,517
Liabilities incurred	12,537			5,825
Liabilities settled	(14,035		)	(13,471		)
Liabilities assumed from corporate acquisition (note 4)	39,960			—
Liabilities acquired from property acquisitions	132			22,264
Liabilities divested	(580		)	(19,940		)
Accretion (note 17)	10,914			8,682
Change in estimate(1)	33,453			(24,028		)
Changes in discount rates and inflation rates(2)	192,672			61,011
Foreign currency translation	2,850			(2,865		)
Balance, end of year	$	646,898		$	368,995

(1) Changes in the estimated costs, the timing of abandonment and reclamation and the status of wells are factors resulting in a change in estimate.

(2) Change in discount rates and inflation rates includes $136.8 million to revalue the liabilities acquired in the Raging River acquisition (note 4) using the risk-free discount rate. At the date of acquisition, acquired asset retirement obligation liabilities are fair valued using a market discount rate.

The undiscounted amount of estimated cash flows required to settle the asset retirement obligations is $673.1 million (December 31, 2017 - $420.3 million). Based on an inflation rate of 2.00% (December 31, 2017 - 2.00%), the undiscounted amount of estimated future cash flows required to settle the obligation is $1,238.6 million (December 31, 2017 - $756.7 million). These costs are expected to be incurred over the next 50 years.

The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2018 using an estimated annual inflation rate of 2.00% (December 31, 2017 - 2.00%) and discounted at a risk free rate of 2.15% (December 31, 2017 - 2.50%) is $646.9 million (December 31, 2017 - $369.0 million).

12. SHAREHOLDERS' CAPITAL

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at December 31, 2018, no preferred shares have been issued by the Company and all common shares issued were fully paid.

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

	Number of Common Shares (000s)	Amount
Balance, December 31, 2016	233,449	$	4,422,661
Transfer from contributed surplus on vesting and conversion of share awards	2,002	20,915
Balance, December 31, 2017	235,451	$	4,443,576
Transfer from contributed surplus on vesting and conversion of share awards	3,343	19,496
Issued on corporate acquisition (note 4)	315,266	1,238,995
Issuance costs, net of tax (note 4)	—	(551		)
Balance, December 31, 2018	554,060	$	5,701,516

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13. PETROLEUM AND NATURAL GAS SALES

Petroleum and natural gas sales primarily consists of revenues earned from the sale of produced oil and natural gas volumes pursuant to fixed or variable price contracts, including the physical delivery contracts for fixed volumes outlined in note 19. The activities that generate petroleum and natural gas sales for the Canadian and U.S. operating segments are described below.

Canada Segment

Petroleum and natural gas sales for Baytex's Canadian operating segment primarily consists of revenues generated from the Company's interest in operated oil and natural gas properties and production taken in-kind from its interest in non-operated oil and natural gas properties.

Under its contracts with customers, Baytex is required to deliver volumes of heavy oil, light oil and condensate, natural gas liquids and natural gas to agreed upon locations where control over the delivered volumes is transferred to the customer. Revenue is recognized when control of each unit of product is transferred to the customer with revenues due on the 25th day of the month following delivery.

Baytex's customers are primarily oil and natural gas marketers and partners in joint operations in the oil and natural gas industry. Concentration of credit risk is mitigated by marketing production to several oil and natural gas marketers under customary industry and payment terms. Baytex reviews the credit worthiness and, when prudent, obtains certain financial assurances from customers prior to entering sales contracts. The financial strength of the Company's customers is reviewed on a routine basis.

U.S. Segment

Petroleum and natural gas sales for Baytex's U.S. operating segment primarily consist of revenues generated from the Company's interest in non-operated oil and natural gas properties where the Company has not elected its right to take its production in-kind. The operator of the oil and natural gas properties that comprise the U.S. operating segment enters contracts with customers, conducts the activities required to transfer control of light oil and condensate, natural gas liquids and natural gas volumes to the customer, and collects and remits payments from the customer to Baytex.

The Company's petroleum and natural gas sales from contracts with customers for each reportable segment is set forth in the following table.

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

Included in accounts receivable at December 31, 2018 is $77.4 million (December 31, 2017 - $91.6 million) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.

14. SHARE-BASED COMPENSATION PLAN

The Company recorded compensation expense related to the share awards and share options of $19.5 million for the year ended December 31, 2018 ($15.5 million for the year ended December 31, 2017).

Share Awards

The weighted average fair value of share awards granted during the year ended December 31, 2018 was $4.04per restricted and performance award (December 31, 2017 - $5.75).

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The number of share awards outstanding is detailed below:

(000s)	Number of restricted awards		Number of performance awards(1)		Total number of share awards
Balance, December 31, 2016	1,508		1,737		3,245
Granted	1,636		1,584		3,220
Vested and converted to common shares	(959	)	(1,043	)	(2,002	)
Forfeited	(157	)	(25	)	(182	)
Balance, December 31, 2017	2,028		2,253		4,281
Granted	2,793		2,591		5,384
Assumed on corporate acquisition(2)	302		257		559
Vested and converted to common shares	(1,682	)	(1,661	)	(3,343	)
Forfeited	(198	)	(167	)	(365	)
Balance, December 31, 2018	3,243		3,273		6,516

(1) Based on underlying awards before applying the payout multiplier which can range from 0x to 2x.

(2) Following closing of the business combination (note 4), holders of 0.3 million Raging River restricted awards and 0.3 million performance awards are entitled to receive Baytex common shares rather than Raging River common shares, after adjusting the quantity of awards outstanding based on the exchange ratio. The fair value of the vested awards was included in consideration (note 4) performance awards associated with the business combination have a fixed payout multiplier of 1.0.

Share Options

On August 22, 2018, Baytex became the successor to Raging River's 2012 Option Plan and Raging River's 2016 Option Plan (collectively, the "Option Plans"). Although no new grants will be made under the Option Plans following completion of the Arrangement, share options held under the Option Plans in existence at August 22, 2018 were converted to share options to purchase shares in Baytex, with an exercise price based on the pre-existing exercise price adjusted based on the exchange ratio.

Share options granted under the Option Plans have a maximum term of 3.5 years to expiry. One third of the options granted will vest on each of the first, second, and third anniversaries of the date of grant. At December 31, 2018, 4.9 million share options with a weighted average exercise price of $6.70 were outstanding. The following tables summarize the information about the share options.

(000s, except per common share amounts)	Number of options		Weighted average exercise price
Balance, December 31, 2017	—		$	—
Granted	—		—
Assumed on corporate acquisition (note 4)	9,187		6.63
Forfeited/Expired	(4,322	)	6.57
Balance, December 31, 2018	4,865		$	6.70

	Options Outstanding				Options Exercisable
Exercise price	Number outstanding at December 31, 2018 (000s)	Weighted average remaining life (years)	Weighted average exercise price		Number exercisable at December 31, 2018 (000s)	Weighted average exercise price
$5.00 - $7.00	3,425	1.28	$	6.28	2,007	$	6.28
$7.01 - $9.00	1,440	1.04	7.68		960	7.68
Total	4,865	1.21	$	6.70	2,967	$	6.73

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The fair value of each option granted was estimated on closing of the business combination (note 4) using the Black-Scholes option-pricing model with the following assumptions.

Risk-free interest rate (%)	2.0	%
Expected life (years)	0.8 - 2.8
Expected volatility (%) (1)	50	%
Dividend per share	—
Expected forfeiture rate (%)	—
Weighted average fair value at grant date ($/option)	0.25

(1) Expected volatility has been based on historical share volatility of the Company.

15. NET INCOME (LOSS) PER SHARE

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

	Year Ended December 31
	2018							2017
	Net loss			Common shares (000's)	Net loss per share			Net income		Common shares (000's)	Net income per share
Net income (loss) - basic	$	(325,309	)	351,542	$	(0.93	)	$	87,174	234,787	$	0.37
Dilutive effect of share awards	—			—	—			—		2,462	—
Dilutive effect of share options	—			—	—			—		—	—
Net income (loss) - diluted	$	(325,309	)	351,542	$	(0.93	)	$	87,174	237,249	$	0.37

For the year ended December 31, 2018, 6.5 million share awards and 4.9 million share options were excluded from the calculation of diluted earnings per share as the Company recorded a net loss. For the year ended December 31, 2017, no share awards were excluded from the calculation of diluted earnings per share and there were no share options outstanding at the time.

16. INCOME TAXES

The provision for income taxes has been computed as follows:

	Year Ended December 31
	2018			2017
Net loss before income taxes	$	(427,076	)	$	(69,254	)
Expected income taxes at the statutory rate of 27.00% (2017 – 26.93%)(1)	(115,311		)	(18,650		)
(Increase) decrease in income tax recovery resulting from:
Share-based compensation	5,185			4,177
Non-taxable portion of foreign exchange (gain) loss	14,467			(11,615		)
Effect of change in income tax rates(1)	—			(104		)
Effect of rate adjustments for foreign jurisdictions	(22,119		)	(42,214		)
Effect of U.S. tax reform(2)	—			(91,830		)
Effect of change in deferred tax benefit not recognized(3)	14,467			(11,615		)
Adjustments and assessments(4)	1,544			15,423
Income tax recovery	$	(101,767	)	$	(156,428	)

(1) Expected income tax rate increased due to an increase in the corporate income tax rate in Saskatchewan (from 11.75% to 12%).

(2) On December 22, 2017, the United States of America (the "U.S.") enacted the Tax Cuts and Jobs Act which altered the federal income tax law that applies to Baytex's U.S. subsidiary. The changes include a reduction of the statutory income tax rate to 21% from 35%, resulting in a $91.8 million deferred tax recovery in 2017.

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(3) A deferred income tax asset has not been recognized for allowable capital losses of $139 million related to the unrealized foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes ($86 million as at December 31, 2017).

(4) The Company is regularly subject to audit by the revenue authorities in the jurisdictions in which it operates. During the year ended December 31, 2017, the Company accepted an audit proposal from the Canada Revenue Agency which reduced certain non-capital loss tax pools by $39.3 million and resulted in a $10.6 million increase in deferred tax expense.

In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the “CRA”) that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. These reassessments follow the previously disclosed letter from the CRA received by Baytex in November 2014 proposing to issue such reassessments.

Baytex remains confident that the tax filings of the affected entities are correct and in September 2016, filed a notice of objection for each notice of reassessment received. These notices of objection will be reviewed by the Appeals Division of CRA; a process that Baytex estimates could take up to two years. If the Appeals Division upholds the notices of reassessment Baytex has the right to appeal to the Tax Court of Canada; a process that Baytex estimates could take a further two years. Should Baytex be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that Baytex estimates could take another two years and potentially longer. The reassessments do not require Baytex to pay any amounts in order to participate in the appeals process. In July 2018, an Appeals Officer was assigned to its file.

By way of background, Baytex acquired all of the interests in several privately held commercial trusts in 2010 with accumulated non-capital losses of $591 million (the “Losses”). The Losses were subsequently used to reduce the taxable income of those trusts. The reassessments disallow the deduction of the Losses under the general anti-avoidance rule of the Income Tax Act (Canada). If, after exhausting available appeals, the deduction of Losses continues to be disallowed, Baytex would owe cash taxes for the years 2012 through 2015 and an additional amount for late payment interest. The amount of cash taxes owing and the late payment interest are dependent upon the amount of unused tax shelter available to offset the reassessed income, including tax shelter from future years that may be applied to the years 2012 through 2015.

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

As at	January 1, 2018			Recognized in Net Loss			Share Issuance Costs		Business Combination			Foreign Currency Translation Adjustment			December 31, 2018
Taxable temporary differences:
Petroleum and natural gas properties	$	(696,427	)	$	(11,639	)	$	—	$	(207,337	)	$	(39,103	)	$	(954,506	)
Financial derivatives	8,528			(31,512		)	—		1,498						(21,486		)
Deferred income	(17,827		)	17,827			—		—						—
Other	(5,956		)	(2,538		)	209		—			5,240			(3,045		)
Deductible temporary differences:
Asset retirement obligations	97,977			62,984			—		10,789			609			172,359
Non-capital losses	330,749			48,725			—		—			20,225			399,699
Finance costs	78,258			17,885			—		—						96,143
Net deferred income tax liability(1)	$	(204,698	)	$	101,732		$	209	$	(195,050	)	$	(13,029	)	$	(310,836	)

(1) Non-capital loss carry-forwards at December 31, 2018 totaled $1,733.8 million and expire from 2029 to 2038.

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As at	January 1, 2017			Recognized in Net Loss			Share Issuance Costs		Business Combination		Foreign Currency Translation Adjustment			December 31, 2017
Taxable temporary differences:
Petroleum and natural gas properties	$	(967,579	)	$	221,697		$	—	$	—	$	49,455		$	(696,427	)
Financial derivatives	7,869			659			—		—		—			8,528
Deferred income	(419		)	(17,408		)	—		—		—			(17,827		)
Other	(5,018		)	6,076			—		—		(7,014		)	(5,956		)
Deductible temporary differences:
Asset retirement obligations	93,016			5,925			—		—		(964		)	97,977
Non-capital losses	404,952			(48,380		)	—		—		(25,823		)	330,749
Finance costs	91,484			(13,226		)	—		—		—			78,258
Net deferred income tax liability(1)	$	(375,695	)	$	155,343		$	—	$	—	$	15,654		$	(204,698	)

(1) Non-capital loss carry-forwards at December 31, 2017 totaled $1,478.5 million and expire from 2023 to 2037.

The following is a summary of Baytex's tax pools.

	December 31, 2018		December 31, 2017
Canadian Tax Pools
Canadian oil and natural gas property expenditures	$	529,044	$	308,366
Canadian development expenditures	765,289		176,188
Canadian exploration expenditures	8,875		1,343
Undepreciated capital costs	502,320		228,739
Non-capital losses	593,251		337,808
Financing costs and other	33,866		46,986
Total Canadian tax pools	$	2,432,645	$	1,099,430
U.S. Tax Pools
Depletion	$	180,367	$	183,406
Intangible drilling costs	133,345		204,857
Tangibles	69,138		108,631
Non-capital losses	1,140,579		1,140,673
Other	407,654		303,357
Total U.S. tax pools	$	1,931,083	$	1,940,924

17. FINANCING AND INTEREST

	Year Ended December 31
	2018		2017
Interest on bank loan	$	15,637	$	11,439
Interest on long-term notes	88,681		89,043
Non-cash financing	3,854		4,474
Accretion on asset retirement obligations (note 11)	10,914		8,682
Financing and interest	$	119,086	$	113,638

18. FOREIGN EXCHANGE

	Year Ended December 31
	2018		2017
Unrealized foreign exchange loss (gain)	$	106,143	$	(86,649	)
Realized foreign exchange loss (gain)	2,151		(411		)
Foreign exchange loss (gain)	$	108,294	$	(87,060	)

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19. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, bank loan and long-term notes.

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

	December 31, 2018						December 31, 2017
	Carrying value			Fair value			Carrying value			Fair value			Fair Value Measurement Hierarchy
Financial Assets
FVTPL
Financial Derivatives	$	79,582		$	79,582		$	18,510		$	18,510		Level 2
Total	$	79,582		$	79,582		$	18,510		$	18,510
Financial assets at amortized cost
Trade and other receivables	$	111,564		$	111,564		$	112,844		$	112,844		—
Total	$	111,564		$	111,564		$	112,844		$	112,844
Financial Liabilities
FVTPL
Financial Derivatives	$	—		$	—		$	(50,095	)	$	(50,095	)	Level 2
Total	$	—		$	—		$	(50,095	)	$	(50,095	)
Financial liabilities at amortized cost
Trade and other payables	$	(258,114	)	$	(258,114	)	$	(144,542	)	$	(144,542	)	—
Bank loan	(520,700		)	(522,294		)	(212,138		)	(213,376		)	—
Long-term notes	(1,583,240		)	(1,492,363		)	(1,474,184		)	(1,430,902		)	Level 1
Total	$	(2,362,054	)	$	(2,272,771	)	$	(1,830,864	)	$	(1,788,820	)

There were no transfers of financial instruments between Level 1 and Level 2 in during the years ended December 31, 2018 or 2017.

Financial Risk

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

Market Risk

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

Foreign Currency Risk

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

To manage the impact of foreign exchange rate fluctuations, the Company may enter into agreements to fix the Canadian to U.S. dollar exchange rate. At December 31, 2018 and 2017, the Company did not have any currency derivative contracts outstanding.

A $0.01 increase or decrease in the CAD/USD foreign exchange rate on the revaluation of outstanding U.S. dollar denominated assets and liabilities, would impact net income or loss before income taxes by approximately $8.8 million.

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

	Assets				Liabilities
	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
U.S. dollar denominated		US$80,857		US$479		US$963,351		US$1,008,001

Interest Rate Risk

The Company's interest rate risk arises from the floating rate Revolving Facilities and Term Loan (note 9). Based on the Company's principle bank loan outstanding net of the interest rate swap, as at December 31, 2018, a change of 100 basis points in interest rates would have an impact on net income or loss before income taxes of approximately $3.2 million.

Interest Rate Swaps

Baytex had the following interest rate swaps outstanding as of March 5, 2019:

Contract Type	Notional Amount			Maturity Date	Fixed Contract Price		Reference(1)	Fair Value ($ millions)
Interest rate swap	$	100	million	October 2020	2.02	%	CDOR	$	0.3
Total								$	0.3
Current asset								0.3

(1) Canadian Dollar Offered Rate.

The Company partially mitigates its exposure to interest rate risk by entering into interest rate swap transactions. A change of 100 basis points in the interest rates would impact net income or loss before income taxes for the year ended December 31, 2018 by approximately$0.4 million.

Commodity Price Risk

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

When assessing the potential impact of crude oil price changes on the crude oil financial derivative contracts outstanding as at December 31, 2018, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $2.9 million.

When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2018, a $0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $1.5 million.

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Financial Derivative Contracts

Baytex had the following financial derivative contracts outstanding as of March 5, 2019:

	Remaining Period	Volume	Price/Unit(1)		Index	Fair Value(2) ($ millions)
Oil
Fixed - Sell	Jan 2019 to Jun 2019	2,000 bbl/d	US$62.85/bbl		WTI	$	8.0
3-way option (3)	Jan 2019 to Dec 2019	2,000 bbl/d	US$70.00/US$60.00/US$50.00		WTI	$	7.0
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$72.60/US$65.00/US$55.00		WTI	$	4.0
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$72.50/US$66.00/US$56.00		WTI	$	4.1
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$73.00/US$66.00/US$56.00		WTI	$	4.1
3-way option (3)	Jan 2019 to Dec 2019	2,000 bbl/d	US$73.00/US$67.00/US$57.00		WTI	$	8.3
3-way option (3)	Jan 2019 to Dec 2019	2,000 bbl/d	US$74.00/US$68.00/US$58.00		WTI	$	8.4
3-way option (3)	Jan 2019 to Dec 2019	2,000 bbl/d	US$75.00/US$61.70/US$49.00		WTI	$	9.1
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$75.00/US$69.90/US$60.00		WTI	$	4.3
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$76.00/US$71.00/US$61.00		WTI	$	4.4
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$78.00/US$73.00/US$63.00		WTI	$	4.5
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$75.50/US$65.50/US$55.50		Brent	$	3.1
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$77.55/US$70.00/US$60.00		Brent	$	3.7
3-way option (3)	Jan 2019 to Dec 2019	1,000 bbl/d	US$83.00/US$73.00/US$63.00		Brent	$	4.0
Basis Swap (4)	Mar 2019 to Jun 2019	2,000 bbl/d	WTI less US$14.75/bbl		WCS	$	—
Basis Swap (4)	Apr 2019 to Jun 2019	2,000 bbl/d	WTI less US$13.65/bbl		WCS	$	—
Basis Swap (4)	Jul 2019 to Sep 2019	4,000 bbl/d	WTI less US$17.38/bbl		WCS	$	—
Basis Swap (4)	Oct 2019 to Dec 2019	4,000 bbl/d	WTI less US$20.88/bbl		WCS	$	—
Natural Gas
Fixed - Sell	Jan 2019 to Mar 2019	5,000 GJ/d	CAD$2.25		AECO	$	0.4
Fixed - Sell	Jan 2019 to Dec 2019	5,000 mmbtu/d		US$3.15	NYMEX	$	0.8
Fixed - Sell	Jan 2019 to Mar 2019	10,000 mmbtu/d		US$3.82	NYMEX	$	0.8
Fixed - Sell	Apr 2019 to Jun 2019	10,000 mmbtu/d		US$2.79	NYMEX	$	0.1
Fixed - Sell	Jul 2019 to Sep 2019	10,000 mmbtu/d		US$2.79	NYMEX	$	0.1
Fixed - Sell	Oct 2019 to Dec 2019	10,000 mmbtu/d		US$2.88	NYMEX	$	0.1
Total						$	79.3
Current asset						$	79.3

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

(2) Fair values as at December 31, 2018. For the purposes of the table, contracts entered subsequent to December 31, 2018 will have no fair value assigned.

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

(4) Contracts entered subsequent to December 31, 2018.

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

	Year Ended December 31
	2018			2017
Realized financial derivatives loss (gain)	$	73,165		$	(7,616	)
Unrealized financial derivatives loss (gain)	(116,715		)	2,439
Financial derivatives gain	$	(43,550	)	$	(5,177	)

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Physical Delivery Contracts

The following physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with the Company's expected sale requirements. Physical delivery contracts are not considered financial instruments and, as a result, no asset or liability has been recognized in the consolidated statements of financial position.

As at March 5, 2019, Baytex had committed to deliver the following volumes of raw bitumen to market on rail:

Period	Volume
Jan 2019 to Oct 2019	1,000 bbl/d
Jan 2019 to Dec 2019	5,000 bbl/d
Jan 2019 to Dec 2020	5,000 bbl/d

Liquidity Risk

Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Such strategies include monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements, opportunities to issue additional common shares as well as reducing capital expenditures. As at December 31, 2018, Baytex had available unused bank credit facilities in the amount of $547.7 million (as at December 31, 2017 - $494.6 million). In the event the Company is not able to comply with the financial covenants contained in agreements with its lenders, the Company's ability to access additional debt may be restricted.

The timing of cash outflows relating to financial liabilities as at December 31, 2018 is outlined in the table below:

	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	258,114	$	258,114	$	—	$	—	$	—
Bank loan(1) (2)	522,294		—		522,294		—		—
Long-term notes(2)	1,596,323		—		750,503		300,000		545,820
Interest on long-term notes(3)	334,028		92,367		156,525		72,350		12,786
	$	2,710,759	$	350,481	$	1,429,322	$	372,350	$	558,606

(1) The bank loan matures on June 4, 2020 unless maturity is extended at Baytex’s request.

(2) Principal amount of instruments.

(3) Excludes interest on bank loan as interest payments on bank loans fluctuate based on amounts outstanding and interest rates.

Credit Risk

Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31, 2018, the Company is exposed to credit risk with respect to its trade and other receivables and financial derivatives.

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

The majority of the Company's credit exposure on accounts receivable at December 31, 2018 relates to accrued revenues for November and December 2018. Accounts receivables from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day of the month following production, with natural gas sales from the Eagle Ford typically collected on the 25th day of the second month following production. Joint interest receivables are typically collected within one to three months following production. Included in accounts receivable at December 31, 2018 is $77.4 million (December 31, 2017 - $91.6 million) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.

Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of accounts receivable is reduced by the use of an allowance for doubtful accounts and a charge to net income or loss. If the Company subsequently determines the accounts receivable is uncollectible, the receivable and allowance for doubtful accounts are adjusted accordingly. As at December 31, 2018, allowance for doubtful accounts was $1.9 million (as at December 31, 2017 - $1.6 million).

In determining whether amounts past due are collectible, the Company will assess the nature of the past due amounts as well as the credit worthiness and past payment history of the counterparty. As at December 31, 2018, accounts receivable that Baytex has

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deemed past due (more than 90 days) but not impaired was $2.6 million (as at December 31, 2017 - $0.7 million). Baytex has estimated the lifetime expected credit loss as at and for the years ended December 31, 2018 to be nominal.

The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2018.

Trade and Other Receivables Aging	December 31, 2018		December 31, 2017
Current (less than 30 days)	$	104,099	$	107,796
31-60 days	3,037		2,939
61-90 days	1,842		1,427
Past due (more than 90 days)	2,586		682
	$	111,564	$	112,844

20. SUPPLEMENTAL INFORMATION

Change in Non-Cash Working Capital Items

	Year Ended December 31
	2018			2017
Trade and other receivables	$	1,280		$	(673	)
Trade and other payables	113,572			31,569
Non-cash working capital acquired (note 4)	(46,773		)	(4,357		)
	$	68,079		$	26,539
Changes in non-cash working capital related to:
Operating activities	$	39,448		$	(8,962	)
Investing activities	32,435			33,683
Foreign currency translation on non-cash working capital	(3,804		)	1,818
	$	68,079		$	26,539

Onerous Contracts

Onerous contracts result from unfavorable leases in which the unavoidable costs of meeting the obligations under the contracts exceed the economic benefits expected to be received.

	Year Ended December 31
	2018			2017
Balance, beginning of year	$	2,574		$	9,504
Liabilities settled	(588		)	(6,746		)
Foreign currency translation	—			(184		)
Balance, end of year	$	1,986		$	2,574

As at December 31, 2018, the Company has a provision totaling $2.0 million for an onerous contract related to office space that has been subleased (as at December 31, 2017 - $2.6 million). The provision represents the difference between the minimum future payments that the Company is required to make and the estimated recoveries from the sublease agreements.

Income Statement Presentation

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

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

	Year Ended December 31
	2018		2017
Operating	$	12,140	$	13,424
General and administrative	34,963		36,086
Total employee compensation costs	$	47,103	$	49,510

21. COMMITMENTS AND CONTINGENCIES

Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s cash flow from operations in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of December 31, 2018, and the expected timing of funding of these obligations, are noted in the table below.

	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Operating leases	$	22,745	7,484		12,492		2,753		16
Processing agreements	47,717		10,926		15,526		9,039		12,226
Transportation agreements	112,002		14,398		42,054		19,821		35,729
Total	$	182,464	$	32,808	$	70,072	$	31,613	$	47,971

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

Operating lease and sublease payments recognized as an expense during the year ended December 31, 2018 were $6.3 million (December 31, 2017 - $6.5 million). Baytex has entered into operating leases on office buildings in the ordinary course of business. The Company's operating lease agreements do not contain any contingent rent clauses. The Company has the option to renew or extend the leases on its office building with the new lease terms to be based on current market prices. None of the operating lease agreements contain purchase options or escalation clauses or any restrictions regarding dividends, further leases or additional debt.

The litigation and claims that Baytex is engaged with, which arose in the normal course of operations, are not expected to materially affect the Company's financial position or reported results of operations.

22. RELATED PARTIES

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

Transactions with key management personnel (including directors) are noted in the table below.

	Year Ended December 31
	2018		2017
Short-term employee benefits	$	8,703	$	7,840
Share-based compensation	10,985		3,569
Termination payments	3,025		275
Total compensation for key management personnel	$	22,713	$	11,684

23. CAPITAL MANAGEMENT

The Company's capital management objective is to maintain financial flexibility and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions and the risk characteristics of our oil and gas properties. At December 31, 2018, our capital structure was comprised of shareholders' capital, long-term debt, working capital and the bank loan.

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

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

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

Adjusted funds flow does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures for other entities. It is reconciled to the nearest measure determined in accordance with IFRS, cash flow from operating activities, as set forth below.

	Year Ended December 31
	2018			2017
Cash flow from operating activities	$	485,322		$	325,208
Change in non-cash working capital	(39,448		)	8,962
Asset retirement obligations settled	14,035			13,471
Transaction costs	$	13,074		$	—
Adjusted funds flow	$	472,983		$	347,641

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

Net debt does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measure for other entities. The computation of net debt is set forth below.

	December 31, 2018			December 31, 2017
Bank loan - principal	$	522,294		$	213,376
Long-term notes - principal	1,596,323			1,489,210
Trade and other payables	258,114			144,542
Trade and other receivables	(111,564		)	(112,844		)
Net debt	$	2,265,167		$	1,734,284

At December 31, 2018, Baytex had $547.7 million of undrawn availability under its credit facilities (December 31, 2017 - $494.6 million).

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