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 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, 2017, our internal control over financial reporting was effective.

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

The effectiveness of the Company's internal control over financial reporting as of December 31, 2017 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, 2017.

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.

Edward D. LaFehr	Rodney D. Gray
President and Chief Executive Officer	Chief Financial Officer
Baytex Energy Corp.	Baytex Energy Corp.
March 5, 2018

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 financial statements of Baytex Energy Corp. (the “Company”), which comprise the consolidated statements of financial position as at December 31, 2017 and December 31, 2016, the consolidated statements of income (loss) and comprehensive income (loss), changes in equity and cash flows for the years then ended, and the related notes, comprising a summary of significant accounting policies and other explanatory information (collectively referred to as the “consolidated financial statements”).

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as at December 31, 2017 and December 31, 2016, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Report on Internal Control Over Financial Reporting

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, 2017, 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, 2018 expressed an unqualified (unmodified) opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

A - Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

B - Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and 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 from material misstatement, whether due to error or fraud. Those standards also require that we comply with ethical requirements, including independence. We are required to be independent with respect to the Company in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We are a public accounting firm registered with the PCAOB.

An audit includes performing procedures to assess the risks of material misstatements of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included obtaining and examining, on a test basis, audit evidence regarding the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances.

An audit also includes evaluating the appropriateness of accounting policies and principles used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a reasonable basis for our audit opinion.

Chartered Professional Accountants

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

March 5, 2018

Calgary, Canada

INDEPENDENT AUDITORS’ REPORT

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, 2017, 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, 2017, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Report on the Consolidated Financial Statements

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company, which comprise the consolidated statements of financial position as at December 31, 2017 and December 31, 2016, the consolidated statements of income (loss) and comprehensive income (loss), changes in equity and cash flows for the years then ended, and the related notes (collectively referred to as the "consolidated financial statements") and our report dated March 5, 2018 expressed an unmodified (unqualified) opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB and in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada.

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, 2018

Calgary, Canada

Baytex Energy Corp.

Consolidated Statements of Financial Position

(thousands of Canadian dollars)

As at	December 31, 2017			December 31, 2016
ASSETS
Current assets
Cash	$	—		$	2,705
Trade and other receivables (note 18)	112,844			112,171
Financial derivatives (note 18)	18,510			2,219
	131,354			117,095
Non-current assets
Exploration and evaluation assets (note 6)	272,974			308,462
Oil and gas properties (note 7)	3,958,309			4,152,169
Other plant and equipment (note 8)	9,474			16,359
	$	4,372,111		$	4,594,085
LIABILITIES
Current liabilities
Trade and other payables (note 18)	$	144,542		$	112,973
Financial derivatives (note 18)	50,095			28,532
Onerous contracts (note 19)	2,574			9,504
	197,211			151,009
Non-current liabilities
Bank loan (note 9)	212,138			187,954
Long-term notes (note 10)	1,474,184			1,566,116
Asset retirement obligations (note 11)	368,995			331,517
Deferred income tax liability (note 15)	204,698			375,695
Financial derivatives (note 18)	—			2,833
	2,457,226			2,615,124
SHAREHOLDERS’ EQUITY
Shareholders' capital (note 12)	4,443,576			4,422,661
Contributed surplus	15,999			21,405
Accumulated other comprehensive income	463,104			629,863
Deficit	(3,007,794		)	(3,094,968		)
	1,914,885			1,978,961
	$	4,372,111		$	4,594,085

Commitments and contingencies (note 20)

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	2017			2016
Revenue, net of royalties
Petroleum and natural gas sales	$	1,091,534		$	780,095
Royalties	(241,892		)	(178,116		)
	849,642			601,979
Expenses
Operating	269,283			240,705
Transportation	33,985			28,257
Blending	51,012			9,622
General and administrative	47,389			50,866
Exploration and evaluation (note 6)	8,253			5,976
Depletion and depreciation (notes 7 and 8)	481,929			508,309
Impairment (notes 6 and 7)	—			423,176
Share-based compensation (note 13)	15,509			13,882
Financing and interest (note 16)	113,638			114,199
Financial derivatives (gain) loss (note 18)	(5,177		)	43,207
Foreign exchange gain (note 17)	(87,060		)	(42,678		)
Gain on disposition of oil and gas properties (note 7)	(12,081		)	(43,907		)
Other	2,216			8,152
	918,896			1,359,766
Net loss before income taxes	(69,254		)	(757,787		)
Income tax recovery (note 15)
Current income tax recovery	(1,085		)	(8,042		)
Deferred income tax recovery	(155,343		)	(264,561		)
	(156,428		)	(272,603		)
Net income (loss) attributable to shareholders	$	87,174		$	(485,184	)
Other comprehensive loss
Foreign currency translation adjustment	(166,759		)	(75,519		)
Comprehensive loss	$	(79,585	)	$	(560,703	)
Net income (loss) per common share (note 14)
Basic	$	0.37		$	(2.29	)
Diluted	$	0.37		$	(2.29	)
Weighted average common shares (note 14)
Basic	234,787			212,298
Diluted	237,249			212,298

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, 2015	$	4,296,831		$	22,045		$	705,382		$	(2,609,784	)	$	2,414,474
Vesting of share awards (note 12)	14,522			(14,522		)	—			—			—
Share-based compensation (note 13)	—			13,882			—			—			13,882
Issued for cash (note 12)	115,014			—			—			—			115,014
Issuance costs, net of tax (note 12)	(3,706		)	—			—			—			(3,706		)
Comprehensive loss for the year	—			—			(75,519		)	(485,184		)	(560,703		)
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 13)	—			15,509			—			—			15,509
Comprehensive 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

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	2017			2016
CASH PROVIDED BY (USED IN):
Operating activities
Net income (loss) for the year	$	87,174		$	(485,184	)
Adjustments for:
Share-based compensation (note 13)	15,509			13,882
Unrealized foreign exchange gain (note 17)	(86,649		)	(41,436		)
Exploration and evaluation (note 6)	8,253			5,976
Depletion and depreciation (notes 7 and 8)	481,929			508,309
Impairment (notes 6 and 7)	—			423,176
Non-cash financing and accretion (note 16)	13,156			10,514
Loss on onerous contracts (note 19)	—			10,116
Unrealized financial derivatives loss (note 18)	2,439			140,136
Gain on disposition of oil and gas properties (note 7)	(12,081		)	(43,907		)
Deferred income tax recovery	(155,343		)	(264,561		)
Payments on onerous contracts (note 19)	(6,746		)	(770		)
Asset retirement obligations settled (note 11)	(13,471		)	(5,616		)
Change in non-cash working capital (note 19)	(8,962		)	(23,270		)
	325,208			247,365
Financing activities
Increase (decrease) in bank loan	33,347			(62,569		)
Redemption of long-term notes (note 10)	(8,582		)	—
Issuance of common shares, net of issuance costs (note 12)	—			109,939
	24,765			47,370
Investing activities
Additions to exploration and evaluation assets (note 6)	(7,118		)	(4,716		)
Additions to oil and gas properties (note 7)	(319,148		)	(220,067		)
Additions to other plant and equipment, net of dispositions	(238		)	5,129
Property acquisitions (notes 4 and 7)	(71,643		)	(117		)
Proceeds from disposition of oil and gas properties (note 7)	11,786			63,237
Change in non-cash working capital (note 19)	33,683			(135,743		)
	(352,678		)	(292,277		)
Change in cash	(2,705		)	2,458
Cash, beginning of year	2,705			247
Cash, end of year	$	—		$	2,705
Supplementary information
Interest paid	$	105,513		$	104,183
Income taxes paid	$	49		$	5,332

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, 2017 and 2016

(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, 2018.

The consolidated financial statements have been prepared on a historical cost basis, with the exception of certain fair value measurements noted in the accounting policies set forth below. The consolidated financial statements are presented in Canadian dollars which is the functional currency of the Company. All financial information is rounded to the nearest thousand, except per share amounts or when 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 calculation of 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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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 and future abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the calculation of 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. The determination of fair value assigned to assets acquired and liabilities assumed often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of oil and gas properties and E&E assets acquired include estimates of reserves acquired, forecast benchmark commodity prices 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.

Financial Derivatives

Financial derivatives are measured at fair value on each reporting date. The Company uses estimates of future commodity prices 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 amounts recorded for asset retirement obligations are based on the Company's net ownership interest in wells and facilities, 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.

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.

Legal

The Company is engaged in litigation and claims arising in the normal course of operations where the actual outcome may vary from the amount recognized in the consolidated financial statements. None of these claims are expected to materially affect the Company's financial position or reported results of operations.

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Income Taxes

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

3. SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd. and Baytex Energy 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 jointly controlled operations. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by jointly controlled operations.

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.

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.

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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.

Borrowing costs that are directly attributable to an item of oil and gas properties that takes a substantial period of time to construct are capitalized as part of the asset. Capitalization of borrowing costs ceases when the asset is in the condition and location necessary for its intended use.

Depletion and Depreciation

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

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

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

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

Impairment

Non-derivative financial assets

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

Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. Impairment losses are recognized in net income or loss. 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

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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.

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.

Revenue Recognition

Revenue associated with sales of petroleum and natural gas is recognized when title passes to the purchaser at the delivery point and collection is reasonably assured. Revenue from the sale of petroleum and natural gas in which the Company has an interest with other producers is recognized based on the Company's working interest and the terms of the relevant agreements. Purchases

Page 9

and sales of product that are entered into in contemplation of each other with the same counterparty with the right and intent to settle net are recorded on a net basis.

Transportation Expense

Costs paid by Baytex for the transportation of crude oil, natural gas, condensate and NGLs to the point of title transfer are recognized when transportation is provided. For the U.S. operations, Baytex does not have sufficient information to bifurcate these costs and therefore transportation expenses have been included as part of operating expense.

Financial Instruments

Financial instruments are measured at fair value on initial recognition of the instrument and are classified into one of the following five categories: fair value through profit or loss (“FVTPL”), loans and receivables, held-to-maturity investments, available-for-sale financial assets and other financial liabilities.

Subsequent measurement of financial instruments is based on their initial classification. FVTPL financial assets are measured at fair value and changes in fair value are recognized in net income or loss. Available-for-sale financial assets are measured at fair value with changes in fair value recorded in other comprehensive income or loss until the instrument is derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the effective interest method. Cash and financial derivatives are classified at FVTPL. Trade and other receivables are classified as loans and receivables, which are measured at amortized cost. Trade and other payables, bank loan and long-term notes are classified as other financial liabilities, which are measured at 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.

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

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

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

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. When current income tax or deferred income tax arises from the initial accounting for a business combination, the tax effect is included in the accounting for the business combination as goodwill.

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

Page 10

differences deductible to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs.

Share-based Compensation Plans

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

Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus dividend equivalents). Each performance award entitles the holder to be issued the number of common shares designated in the performance award (plus dividend equivalents) multiplied by a payout multiplier. Under the Share Award Incentive Plan, common shares are issued as to one-sixth every six months from the date of issuance. 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.

Future Accounting Pronouncements

Revenue from Contracts with Customers

In April 2016, the IASB issued its final amendments to IFRS 15 Revenue from Contracts with Customers, which will replace IAS 11 Construction Contracts and IAS 18 Revenue and the related interpretations on revenue recognition. The new standard moves away from a revenue recognition model based on an earnings process to an approach that is based on transfer of control of a good or service to a customer. The standard also requires extensive new disclosures, as to the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. IFRS 15 can be applied retrospectively to each period presented or retrospectively as a cumulative-effect adjustment as of the date of adoption. The new standard is effective for annual periods beginning on or after January 1, 2018 with early adoption permitted. The Company has substantially completed its review of the various revenue streams and underlying contracts with customers and does not anticipate a material impact to the Company's net income. The Company will expand the disclosures in the notes to the financial statements as prescribed by IFRS 15 to provide additional information on the Company's various revenue streams and contractual arrangements.

Financial Instruments

In July 2014, the IASB issued IFRS 9 Financial Instruments which is intended to replace IAS 39 Financial Instruments: Recognition and Measurement. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classifications: amortized cost and fair value. 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. In addition, IFRS 9 provides a hedge accounting model that is more in line with risk management activities. The Company currently does not apply hedge accounting to its derivative contracts nor does it intend to apply hedge accounting upon adoption of IFRS 9. The standard is effective for annual periods beginning on or after January 1, 2018 with early adoption permitted. The Company will adopt IFRS 9 in its financial statements for the annual period beginning on January 1, 2018. The Company has concluded that the standard will not have a material impact on the consolidated financial statements.

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 with early adoption permitted if IFRS 15 has been adopted. The standard shall be applied retrospectively to each period presented or retrospectively as a cumulative-effect adjustment as of the date of adoption. The Company will adopt IFRS 16 on January 1, 2019. The Company is developing a plan to identify and review its various lease agreements in order to determine the impact that adoption of IFRS 16 will have on the consolidated financial statements.

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4. PROPERTY ACQUISITION

On January 20, 2017, Baytex acquired heavy oil properties in the Peace River area of Alberta for total consideration of $66.1 million, including closing adjustments. The purchase price was adjusted for the results of operations between the effective date of December 1, 2016 and closing of the acquisition. The acquired properties provide additional development opportunities located immediately adjacent to Baytex's existing Peace River lands.

The acquisition was accounted for as a business combination whereby the net assets acquired and the liabilities assumed were recorded at fair value at the acquisition date. The fair value of the oil and gas properties acquired was determined using a third-party evaluation of proved plus probable reserves with an effective date of December 31, 2017, utilizing forward prices at the date of acquisition and adjustment for the results of operations between the acquisition date and December 31, 2017. The asset retirement obligations were determined using internal estimates of the timing and estimated costs associated with the abandonment, restoration and reclamation of the wells and facilities acquired using a market discount rate of 12%.

Final estimates of fair value assigned to the assets acquired and liabilities assumed at the date of acquisition are set forth below.

Consideration for the acquisition:
Cash paid	$	66,084
Total consideration	$	66,084
Purchase price equation:
Oil and gas properties	$	89,526
Crude oil inventory(1)	988
Trade and other payables	(5,400		)
Asset retirement obligations	(19,030		)
Total net assets acquired	$	66,084

(1) Crude oil inventory is included as part of trade and other receivables, as at the acquisition date.

For the period from January 20, 2017 to December 31, 2017, the acquired properties contributed revenues, net of royalties, of $61.0 million and operating income (revenues, net of royalties, less operating, transportation and blending expenses) of $10.8 million.

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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	2017			2016			2017			2016			2017			2016			2017			2016
Revenue, net of royalties
Petroleum and natural gas sales	$	470,239		$	299,632		$	621,295		$	480,463		$	—		$	—		$	1,091,534		$	780,095
Royalties	(58,672		)	(37,720		)	(183,220		)	(140,396		)	—			—			(241,892		)	(178,116		)
	411,567			261,912			438,075			340,067			—			—			849,642			601,979
Expenses
Operating	181,995			142,242			87,288			98,463			—			—			269,283			240,705
Transportation	33,985			28,257			—			—			—			—			33,985			28,257
Blending	51,012			9,622			—			—			—			—			51,012			9,622
General and administrative	—			—			—			—			47,389			50,866			47,389			50,866
Exploration and evaluation	8,253			5,976			—			—			—			—			8,253			5,976
Depletion and depreciation	199,149			210,778			280,933			293,231			1,847			4,299			481,929			508,309
Impairment	—			256,559			—			166,617			—			—			—			423,176
Share-based compensation	—			—			—			—			15,509			13,882			15,509			13,882
Financing and interest	—			—			—			—			113,638			114,199			113,638			114,199
Financial derivatives (gain) loss	—			—			—			—			(5,177		)	43,207			(5,177		)	43,207
Foreign exchange gain	—			—			—			—			(87,060		)	(42,678		)	(87,060		)	(42,678		)
Gain on disposition of oil and gas properties	(12,048		)	(3,883		)	(33		)	(40,024		)	—			—			(12,081		)	(43,907		)
Other	—			—			—			—			2,216			8,152			2,216			8,152
	462,346			649,551			368,188			518,287			88,362			191,927			918,896			1,359,766
Net income (loss) before income taxes	(50,779		)	(387,639		)	69,887			(178,220		)	(88,362		)	(191,927		)	(69,254		)	(757,787		)
Income tax recovery
Current income tax recovery	—			(6,577		)	(1,085		)	(1,156		)	—			(309		)	(1,085		)	(8,042		)
Deferred income tax expense (recovery)	622			(99,215		)	(118,163		)	(112,907		)	(37,802		)	(52,439		)	(155,343		)	(264,561		)
	622			(105,792		)	(119,248		)	(114,063		)	(37,802		)	(52,748		)	(156,428		)	(272,603		)
Net income (loss)	$	(51,401	)	$	(281,847	)	$	189,135		$	(64,157	)	$	(50,560	)	$	(139,179	)	$	87,174		$	(485,184	)
Total oil and natural gas capital expenditures(1)	$	173,131		$	16,990		$	212,992		$	144,673		$	—		$	—		$	386,123		$	161,663

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

As at	December 31, 2017		December 31, 2016
Canadian assets	$	1,677,821	$	1,625,546
U.S. assets	2,684,816		2,955,965
Corporate assets	9,474		12,574
Total consolidated assets	$	4,372,111	$	4,594,085

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6. EXPLORATION AND EVALUATION ASSETS

	December 31, 2017			December 31, 2016
Balance, beginning of year	$	308,462		$	578,969
Capital expenditures	7,118			4,716
Divestitures	(1,276		)	(2,353		)
Impairment	—			(166,617		)
Exploration and evaluation expense	(8,253		)	(5,976		)
Transfer to oil and gas properties	(20,198		)	(85,069		)
Foreign currency translation	(12,879		)	(15,208		)
Balance, end of year	$	272,974		$	308,462

At December 31, 2017, there were no indicators of impairment for exploration and evaluation assets on any of the Company's CGUs. During the year ended December 31, 2017, the Company transferred $20.2 million from exploration and evaluation to oil and gas properties upon establishment of developed reserves in the U.S. CGU that were previously classified as undeveloped reserves.

During the year ended December 31, 2016, the Company derecognized $166.6 million of exploration and evaluation assets in the U.S. CGU due to changes to the Company's development plan, which resulted in possible reserves being reclassified to contingent resources. The Company also transferred $85.1 million from exploration and evaluation assets to oil and gas properties upon establishment of proved plus probable reserves in the U.S. CGU that were previously classified as possible reserves.

7. OIL AND GAS PROPERTIES

	Cost			Accumulated depletion			Net book value
Balance, December 31, 2015	$	7,584,281		$	(2,910,106	)	$	4,674,175
Capital expenditures	220,067			—			220,067
Property acquisitions	54			—			54
Transferred from exploration and evaluation assets	85,069			—			85,069
Change in asset retirement obligations	35,714			—			35,714
Divestitures	(59,874		)	42,959			(16,915		)
Impairment	—			(256,559		)	(256,559		)
Foreign currency translation	(101,274		)	15,616			(85,658		)
Depletion	—			(503,778		)	(503,778		)
Balance, December 31, 2016	$	7,764,037		$	(3,611,868	)	$	4,152,169
Capital expenditures	319,148			—			319,148
Property acquisitions(1)	136,007			—			136,007
Transferred from exploration and evaluation assets	20,198			—			20,198
Transferred from other assets	5,124			—			5,124
Change in asset retirement obligations	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

(1) Includes $53.5 million related to the acquisition of heavy oil properties completed during the year ended December 31, 2017, in addition to amounts related to the property acquisition disclosed in note 4.

During the fourth quarter of 2017, the Company closed an arrangement to swap its working interest in certain oil and gas properties in exchange for non-monetary proceeds of $40.0 million. The fair value of non-monetary proceeds, including producing oil and gas properties geographically located in the Company's Lloydminster CGU, was determined based on the proved plus probable reserves evaluated as at December 31, 2017 by an independent reserve engineer. The Company recorded a gain of $19.3 million on the swap as a result of the fair value of acquired assets exceeding the carrying value of the disposed assets. The disposed assets included $26.5 million of oil and gas properties and $8.0 million of asset retirement obligations.

Page 14

At the end of each reporting period, the Company performs an assessment to determine whether there is any indication of impairment or reversal of previously recorded impairments for the CGUs that comprise oil and gas properties. The assessment of indicators is subjective in nature and requires Management to make judgments based on the information available at the reporting date. The Company determined that there were no indicators of impairment or impairment reversals for any of the Company's CGUs as at December 31, 2017.

In 2016, the Company recorded a $26.6 million impairment expense in its Lloydminster CGU on assets that were reclassified from oil and gas assets to assets held for sale prior to their disposition in the fourth quarter of 2016. The carrying value of the assets transferred to assets held for sale exceeded the fair value (being the sales price) resulting in the impairment.

At December 31, 2016, indicators of impairment existed for the Peace River CGU as a result of downward technical revisions to reserves. Impairment of $230.0 million was recorded in the Peace River CGU. The recoverable amount for the Peace River CGU was not sufficient to support the carrying amounts of the assets resulting in the impairment at December 31, 2016. The recoverable amount of oil and gas properties of $550.2 million for the Peace River CGU was estimated based on their fair value less costs of disposal at December 31, 2016. For impairment assessments of oil and gas properties, the Company estimates the recoverable amount using a discounted cash flow model based on an independent reserve report approved by the Board of Directors on an annual basis and a range of pre-tax discount rates of 10% to 15%. The total impairment expense recorded to oil and gas properties by the Company in 2016 was $256.6 million.

The recoverable amount of the Peace River CGU is classified as a Level 3 fair value measurement and was calculated at December 31, 2016 using the following benchmark reference prices for the years 2017 to 2021 adjusted for commodity differentials specific to the Company:

	2017	2018	2019	2020	2021
WTI crude oil (US$/bbl)	55.00	65.00	70.00	71.40	72.83
NYMEX natural gas (US$/MMBtu)	3.50	3.50	3.50	4.00	4.08
Exchange rate (CAD/USD)	1.28	1.22	1.18	1.18	1.18

8. OTHER PLANT AND EQUIPMENT

	Cost			Accumulated depreciation			Net book value
Balance, December 31, 2015	$	72,878		$	(46,854	)	$	26,024
Capital expenditures	1,934			—			1,934
Dispositions, net of acquisitions	(7,063		)	—			(7,063		)
Foreign currency translation	(51		)	46			(5		)
Depreciation	—			(4,531		)	(4,531		)
Balance, December 31, 2016	67,698			(51,339		)	16,359
Capital expenditures	329			—			329
Dispositions, net of acquisitions	(255		)	—			(255		)
Transferred to oil and gas properties	(5,124		)	—			(5,124		)
Foreign currency translation	—			12			12
Depreciation	—			(1,847		)	(1,847		)
Balance, December 31, 2017	$	62,648		$	(53,174	)	$	9,474

9. BANK LOAN

	December 31, 2017			December 31, 2016
Bank loan - U.S. dollar denominated(1)	$	167,159		$	191,286
Bank loan - Canadian dollar denominated	46,217			—
Bank loan - principal	213,376			191,286
Unamortized debt issuance costs	(1,238		)	(3,332		)
Bank loan	$	212,138		$	187,954

(1) U.S. dollar denominated bank loan balance as at December 31, 2017 was US$133.5 million (US$142.5 million as at December 31, 2016).

Page 15

On March 31, 2016, Baytex amended its credit facilities to grant the banking syndicate first priority security over its assets. The amended revolving extendible secured credit facilities are comprised of a US$25 million operating loan and a US$350 million syndicated loan for Baytex and a US$200 million syndicated loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. (collectively, the "Revolving Facilities").

The Revolving Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The facilities contain standard commercial covenants including the financial covenants detailed below and do not require any mandatory principal payments prior to maturity on June 4, 2019. Baytex may request an extension of the Revolving Facilities which could extend the revolving period for up to four years (subject to a maximum four-year period at any time). Advances (including letters of credit) under the Revolving 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 exceeds any of the covenants under the Revolving 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, 2017, Baytex had $14.6 million of outstanding letters of credit (December 31, 2016 - $12.6 million) under the Revolving Facilities.

At December 31, 2017, Baytex was in compliance with all of the covenants contained in the Revolving Facilities. The following table summarizes the financial covenants contained in the Revolving Facilities and Baytex's compliance therewith as at December 31, 2017.

		Ratio for the Quarter(s) ending:
Covenant Description	Position as at December 31, 2017	December 31, 2017 to March 31, 2018	June 30, 2018 to September 30, 2018	December 31, 2018	Thereafter
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.50:1.00	5.00:1.00	4.50:1.00	4.00:1.00	3.50:1.00
Interest Coverage (3)  (Minimum Ratio)	4.54:1.00	1.25:1.00	1.50:1.00	1.75:1.00	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, 2017, the Company's Senior Secured Debt totaled $228 million.

(2) Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, 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. Bank EBITDA for the twelve months ended December 31, 2017 was $454 million.

(3) Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expenses 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, 2017 were $100 million.

10. LONG-TERM NOTES

	December 31, 2017			December 31, 2016
7.5% notes (US$6,400 – principal) redeemed July 13, 2017	$	—		$	8,593
6.75% notes (US$150,000 – principal) due February 17, 2021	187,770			201,405
5.125% notes (US$400,000 – principal) due June 1, 2021	500,720			537,080
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	500,720			537,080
Total long-term notes - principal	1,489,210			1,584,158
Unamortized debt issuance costs	(15,026		)	(18,042		)
Total long-term notes - net of unamortized debt issuance costs	$	1,474,184		$	1,566,116

On July 13, 2017, the Company redeemed the remaining US$6.4 million principal amount of 7.5% senior unsecured notes assumed pursuant to the acquisition of Aurora Oil and Gas Limited on June 11, 2014.

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 Revolving 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 2.5:1. As at December 31, 2017, the fixed charge coverage ratio was 4.54:1.00.

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11. ASSET RETIREMENT OBLIGATIONS

	December 31, 2017			December 31, 2016
Balance, beginning of year	$	331,517		$	296,002
Liabilities incurred	5,825			5,642
Liabilities settled	(13,471		)	(5,616		)
Liabilities acquired (1)	22,264			—
Liabilities divested	(19,940		)	(10,590		)
Accretion	8,682			6,174
Change in estimate (2)	(24,028		)	20,402
Changes in discount rates and inflation rates (3)	61,011			20,260
Foreign currency translation	(2,865		)	(757		)
Balance, end of year	$	368,995		$	331,517

(1) Includes $3.2 million related to the acquisition of other heavy oil properties during the year ended December 31, 2017, in addition to amounts related to the property acquisition disclosed in note 4.

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

(3) The change in discount rate includes $64.0 million related to the Peace River property acquisition (note 4). Obligations acquired are initially measured at fair value using a market rate of interest. The revaluation of obligations acquired using the risk-free discount rate results in an increase to the asset retirement 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. These costs are expected to be incurred over the next 50 years.

The undiscounted amount of estimated cash flow required to settle the asset retirement obligations is $420.3 million (December 31, 2016 - $365.1 million). Based on an inflation rate of 2.00% (December 31, 2016 - 1.75%), the undiscounted amount of estimated future cash flows required to settle the obligation is $756.7 million (December 31, 2016 - 605.4 million).

The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2017 using an estimated annual inflation rate of 2.00% (December 31, 2016 - 1.75%) and discounted at a risk free rate of 2.50% (December 31, 2016 - 2.25%) is $369.0 million (December 31, 2016 - $331.5 million).

12. SHAREHOLDERS' CAPITAL

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10,000,000 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, 2017, 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, 2015	210,583	$	4,296,831
Transfer from contributed surplus on vesting and conversion of share awards	958	14,522
Issued for cash	21,908	115,014
Issuance costs, net of tax	—	(3,706		)
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

On December 12, 2016, Baytex issued 21.9 million common shares for aggregate gross proceeds of approximately $115.0 million ($109.9 million net of issue costs). Issuance costs of $5.1 million ($3.7 million after tax) were recorded as a reduction to shareholders' capital.

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13. SHARE AWARD INCENTIVE PLAN

The Company recorded compensation expense related to the share awards of $15.5 million for the year ended December 31, 2017 ($13.9 million for the year ended December 31, 2016).

The weighted average fair value of share awards granted during the year ended December 31, 2017 was $5.75per restricted and performance award and $3.04 per restricted and performance award for the year ended December 31, 2016.

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, 2015	729		613		1,342
Granted	1,313		1,583		2,896
Vested and converted to common shares	(450	)	(409	)	(859	)
Forfeited	(84	)	(50	)	(134	)
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

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

14. NET INCOME (LOSS) PER SHARE

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

	Years Ended December 31
	2017					2016
	Net income		Weighted average common shares (000s)	Net income per share		Net loss			Weighted average common shares (000s)	Net loss per share
Net income (loss) - basic	$	87,174	234,787	$	0.37	$	(485,184	)	212,298	$	(2.29	)
Dilutive effect of share awards	—		2,462	—		—			—	—
Net income (loss) - diluted	$	87,174	237,249	$	0.37	$	(485,184	)	212,298	$	(2.29	)

For the years ended December 31, 2017 and 2016, the effect of no share awards and 3.2 million share awards, respectively, were excluded from the calculation of dilutive earnings per share as they were determined to be anti-dilutive.

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15. INCOME TAXES

The provision for income taxes has been computed as follows:

	Years Ended December 31
	2017			2016
Net loss before income taxes	$	(69,254	)	$	(757,787	)
Expected income taxes at the statutory rate of 26.93% (2016 – 27.00%)(1)	(18,650		)	(204,602		)
Increase (decrease) in income tax recovery resulting from:
Share-based compensation	4,177			3,610
Non-taxable portion of foreign exchange (gain) loss	(11,615		)	(5,309		)
Effect of change in income tax rates(1)	(104		)	1,180
Effect of rate adjustments for foreign jurisdictions	(42,214		)	(63,745		)
Effect of U.S. tax reform(2)	(91,830		)	—
Effect of change in deferred tax benefit not recognized(3)	(11,615		)	(5,309		)
Adjustments and assessments(4)	15,423			1,572
Income tax recovery	$	(156,428	)	$	(272,603	)

(1) Expected income tax rate decreased due to a decrease in the corporate income tax rate in Saskatchewan (from 12% to 11.75%).

(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.

(3) A deferred income tax asset has not been recognized for allowable capital losses of $86 million related to the unrealized foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes ($129 million as at December 31, 2016).

(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.

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.

Page 19

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

As at	January 1, 2017			Recognized in Net Loss			Share Issuance Costs		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
Financial derivatives	—			—			—		—			—
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.

As at	January 1, 2016			Recognized in Net Loss			Share Issuance Costs		Foreign Currency Translation Adjustment			December 31, 2016
Taxable temporary differences:
Petroleum and natural gas properties	$	(1,105,470	)	$	112,710		$	—	$	25,181		$	(967,579	)
Financial derivatives	(29,961		)	37,830			—		—			7,869
Deferred income	(28,387		)	27,968			—		—			(419		)
Other	(6,595		)	2,327			1,370		(2,120		)	(5,018		)
Deductible temporary differences:
Asset retirement obligations	83,189			10,231			—		(404		)	93,016
Financial derivatives	1,582			(1,582		)	—		—			—
Non-capital losses	383,450			30,530			—		(9,028		)	404,952
Finance costs	46,937			44,547			—		—			91,484
Net deferred income tax liability(1)	$	(655,255	)	$	264,561		$	1,370	$	13,629		$	(375,695	)

(1) Non-capital loss carry-forwards at December 31, 2016 totaled $1,191.7 million and expire from 2023 to 2036.

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

	December 31, 2017		December 31, 2016
Canadian Tax Pools
Canadian oil and natural gas property expenditures	$	308,366	$	198,525
Canadian development expenditures	176,188		250,239
Canadian exploration expenditures	1,343		210
Undepreciated capital costs	228,739		256,549
Non-capital losses	337,808		151,959
Financing costs and other	46,986		69,025
Total Canadian tax pools	$	1,099,430	$	926,507
U.S. Tax Pools
Depletion	$	183,406	$	297,252
Intangible drilling costs	204,857		388,727
Tangibles	108,631		136,969
Non-capital losses	1,140,673		1,039,782
Other	303,357		201,896
Total U.S. tax pools	$	1,940,924	$	2,064,626

16. FINANCING AND INTEREST

	Years Ended December 31
	2017		2016
Interest on bank loan	$	11,439	$	12,860
Interest on long-term notes	89,043		90,825
Non-cash financing	4,474		4,340
Accretion on asset retirement obligations (note 11)	8,682		6,174
Financing and interest	$	113,638	$	114,199

17. FOREIGN EXCHANGE

	Years Ended December 31
	2017			2016
Unrealized foreign exchange gain	$	(86,649	)	$	(41,436	)
Realized foreign exchange gain	(411		)	(1,242		)
Foreign exchange gain	$	(87,060	)	$	(42,678	)

18. 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.

Categories of Financial Instruments

The estimated fair values of the financial instruments have been determined based on the Company's assessment of available market information. To estimate fair values of its financial instruments, Baytex uses quoted market prices when available, or third-party models and valuation methodologies that use observable market data. Baytex aims to maximize the use of observable inputs, where practical. The fair values of financial instruments, other than financial derivatives, bank loan and long-term notes, are equal to their carrying amounts due to the short-term maturity of these instruments. The fair value of financial derivatives are based on mark-to-market values of the underlying financial derivative contracts. The fair value of the bank loan is based on the principal amount of borrowings outstanding. The fair value of the long-term notes are based on the trading value of the notes.

Fair Value of Financial Instruments

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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.

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, 2017						December 31, 2016
	Carrying value			Fair value			Carrying value			Fair value			Fair Value Measurement Hierarchy
Financial Assets
FVTPL(1)
Cash	$	—		$	—		$	2,705		$	2,705		Level 1
Derivatives	18,510			18,510			2,219			2,219			Level 2
Total	$	18,510		$	18,510		$	4,924		$	4,924
Loans and receivables
Trade and other receivables	$	112,844		$	112,844		$	112,171		$	112,171		—
Total	$	112,844		$	112,844		$	112,171		$	112,171
Financial Liabilities
FVTPL(1)
Derivatives	$	(50,095	)	$	(50,095	)	$	(31,365	)	$	(31,365	)	Level 2
Total	$	(50,095	)	$	(50,095	)	$	(31,365	)	$	(31,365	)
Other financial liabilities
Trade and other payables	$	(144,542	)	$	(144,542	)	$	(112,973	)	$	(112,973	)	—
Bank loan	(212,138		)	(213,376		)	(187,954		)	(191,286		)	—
Long-term notes	(1,474,184		)	(1,430,902		)	(1,566,116		)	(1,435,165		)	Level 1
Total	$	(1,830,864	)	$	(1,788,820	)	$	(1,867,043	)	$	(1,739,424	)

(1) FVTPL means fair value through profit or loss.

There were no transfers between Level 1 and Level 2 in either 2017 or 2016.

Financial Risk

Baytex is exposed to a variety of financial risks, including market risk, liquidity risk and credit risk. The Company monitors and, when appropriate, utilizes derivative contracts to manage its exposure to these risks. The Company does not enter into derivative contracts for speculative purposes.

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.

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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, 2017 and 2016, 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 $12.4 million.

The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities at the reporting date are as follows:

	Assets				Liabilities
	December 31, 2017		December 31, 2016		December 31, 2017		December 31, 2016
U.S. dollar denominated		US$51,665		US$66,950		US$1,294,615		US$1,197,732

Interest Rate Risk

The Company's interest rate risk arises from the floating rate Revolving Facilities (note 9). As at December 31, 2017, the $213.4 million principal amount of the Company's bank loan is subject to movements in floating interest rates. A change of 100 basis points in interest rates would impact net income or loss before income taxes for the year ended December 31, 2017 by approximately $2.1 million.

Commodity Price Risk

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

When assessing the potential impact of crude oil price changes on the crude oil financial derivative contracts outstanding as at December 31, 2017, a $1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $11.9 million.

When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2017, a $0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $1.6 million.

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Financial Derivative Contracts

Baytex had the following financial derivative contracts outstanding as of March 5, 2018:

	Period	Volume	Price/Unit(1)		Index	Fair Value(2) ($ millions)
Oil
Basis swap	Jan 2018 to Jun 2018	2,000 bbl/d	WTI less US$14.23/bbl		WCS	$	3.1
Basis swap	Jan 2018 to Dec 2018	6,000 bbl/d	WTI less US$14.24/bbl		WCS	$	15.0
Fixed - Sell	Jan 2018 to Dec 2018	13,000 bbl/d	US$51.64/bbl		WTI	$	(45.0	)
3-way option (3)	Jan 2018 to Dec 2018	2,000 bbl/d	US$60.00/US$54.40/US$40.00		WTI	$	(1.2	)
Fixed - Sell	Jan 2018 to Dec 2018	4,000 bbl/d	US$61.31/bbl		Brent	$	(6.5	)
Fixed - Sell (4)	Feb 2018 to Dec 2018	1,000 bbl/d	US$61.04/bbl		WTI	$	—
Swaption (4)(5)	Jan 2019 to Dec 2019	2,000 bbl/d	US$59.60/bbl		WTI	$	—
3-way option (3)(4)	Jan 2019 to Dec 2019	2,000 bbl/d	US$70.00/US$60.00/US$50.00		WTI	$	—
3-way option (3)(4)	Jan 2019 to Dec 2019	1,000 bbl/d	US$75.50/US$65.50/US$55.50		Brent	$	—
Natural Gas
Fixed - Sell	Jan 2018 to Dec 2018	10,000 mmbtu/d		US$3.03	NYMEX	$	0.9
Fixed - Sell	Jan 2018 to Dec 2018	5,000 GJ/d		$2.67	AECO	$	2.1
Fixed - Sell (4)	Feb 2018 to Dec 2018	5,000 mmbtu/d		US$2.99	NYMEX	$	—
Total						$	(31.6	)
Current asset						$	18.5
Current liability						$	(50.1	)

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

(2) Fair values as at December 31, 2017. For the purposes of the table, contracts entered subsequent to December 31, 2017 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$60/US$54.40/US$40 contract, Baytex receives WTI plus US$14.40/bbl when WTI is at or below US$40/bbl; Baytex receives US$54.40/bbl when WTI is between US$40/bbl and US$54.40/bbl; Baytex receives the market price when WTI is between US$54.40/bbl and US$60/bbl; and Baytex receives US$60/bbl when WTI is above US$60/bbl.

(4) Contracts entered subsequent to December 31, 2017.

(5) For these contracts, the counterparty has the right, if exercised on December 31, 2018, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

Financial derivatives are marked-to-market at the end of each reporting period, with the following reflected in the consolidated statements of income or loss:

	Years Ended December 31
	2017			2016
Realized financial derivatives gain	$	(7,616	)	$	(96,929	)
Unrealized financial derivatives loss	2,439			140,136
Financial derivatives (gain) loss	$	(5,177	)	$	43,207

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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.

Period	Product	Volume	Price/Unit(1)
Jan 2018 to Dec 2018	WCS	2,000 bbl/d	WTI less US$14.00/bbl

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

As at December 31, 2017, Baytex had committed to deliver the following volumes of raw bitumen to market on rail:

Period	Volume
Jan 2018 to Apr 2018	1,000 bbl/d
Jan 2018 to Dec 2018	5,000 bbl/d
Apr 2018	1,000 bbl/d
May 2018 to Dec 2018	2,000 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, 2017, Baytex had available unused bank credit facilities in the amount of $494.6 million (as at December 31, 2016 - $580.8 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, 2017 is outlined in the table below:

	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	144,542	$	144,542	$	—	$	—	$	—
Bank loan(1) (2)	213,376		—		213,376		—		—
Long-term notes(2)	1,489,210		—		—		988,490		500,720
Interest on long-term notes	398,635		86,377		172,754		99,609		39,895
	$	2,245,763	$	230,919	$	386,130	$	1,088,099	$	540,615

(1) The bank loan is covenant-based with a revolving period that is extendible annually for up to a four-year term. Unless extended, the revolving period will end on June 4, 2019, with all amounts to be repaid on such date.

(2) Principal amount of instruments.

Credit Risk

Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. 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. None of the Company's financial assets are secured by any other type of collateral. 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, 2017 relates to accrued revenues for December 2017. 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. Joint interest receivables are typically collected within one to three months following production. At December 31, 2017, US$7.6 million of accounts receivable relates to joint interest receivables from the operator of our joint operations in the Eagle Ford.

Should Baytex 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. For the year ended December 31, 2017, the allowance for doubtful accounts increased by $0.2 million (2016 - no change).

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As at December 31, 2017, allowance for doubtful accounts was $1.6 million (2016 - $1.4 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, 2017, accounts receivable that Baytex has deemed past due (more than 90 days) but not impaired was $0.7 million (2016 - $0.9 million).

The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2017:

Trade and Other Receivables Aging	December 31, 2017
Current (less than 30 days)	$	107,796
31-60 days	2,939
61-90 days	1,427
Past due (more than 90 days)	682
	$	112,844

19. SUPPLEMENTAL INFORMATION

Change in Non-Cash Working Capital Items

	Years Ended December 31
	2017			2016
Trade and other receivables	$	(673	)	$	(14,078	)
Trade and other payables	31,569			(154,865		)
Non-cash working capital acquired	(4,357		)	—
	$	26,539		$	(168,943	)
Changes in non-cash working capital related to:
Operating activities	$	(8,962	)	$	(23,270	)
Investing activities	33,683			(135,743		)
Foreign currency translation on non-cash working capital	1,818			(9,930		)
	$	26,539		$	(168,943	)

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.

	Years Ended December 31
	2017			2016
Balance, beginning of year	$	9,504		$	—
Liabilities incurred	—			10,116
Liabilities settled	(6,746		)	(770		)
Foreign currency translation	(184		)	158
Balance, end of year	$	2,574		$	9,504

As at December 31, 2017, the Company has a provision totaling $2.6 million for an onerous contract related to an office sublease (December 31, 2016 - $9.5 million related to an office sublease and a transportation agreement). The provision represents the difference between the minimum future payments that we are required to make and the estimated recoveries.

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.

	Years Ended December 31
	2017		2016
Operating	$	13,424	$	9,528
General and administrative	36,086		23,070
Total employee compensation costs	$	49,510	$	32,598

20. 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, 2017, 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	$	29,926	7,727		13,510		8,689		—
Processing agreements	41,845		6,993		9,164		9,004		16,684
Transportation agreements	31,948		2,602		14,635		13,661		1,050
Total	$	103,719	$	17,322	$	37,309	$	31,354	$	17,734

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, 2017 were $6.5 million (December 31, 2016 - $7.7 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.

21. 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:

	Years Ended December 31
	2017		2016
Short-term employee benefits	$	7,840	$	7,278
Share-based compensation	3,569		6,613
Termination payments	275		—
Total compensation for key management personnel	$	11,684	$	13,891

22. CAPITAL DISCLOSURES

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, 2017, our capital structure was comprised of shareholders' capital, long-term debt, working capital and the bank loan.

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Baytex monitors capital based on the ratio of net debt to 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.

The Company's Revolving Facilities are comprised of a US$25 million operating loan and a US$350 million syndicated loan for Baytex and a US$200 million syndicated loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. At December 31, 2017, Baytex was in compliance with all of the covenants contained in the Revolving Facilities and had unused capacity of $494.6 million.

We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our ability to generate funds for capital investments, debt repayment, settlement of our abandonment obligations and potential future dividends. In addition, the Company uses a ratio of net debt to adjusted funds flow to manage its capital structure. We eliminate changes in non-cash working capital 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. Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income or loss.

Adjusted funds flow is reconciled to the nearest measure determined in accordance with IFRS, cash flow from operating activities, as set forth below.

	Years Ended December 31
	2017		2016
Cash flow from operating activities	$	325,208	$	247,365
Change in non-cash working capital	8,962		23,270
Asset retirement obligations settled	13,471		5,616
Adjusted funds flow	$	347,641	$	276,251

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.

	As at December 31
	2017			2016
Bank loan - principal	$	213,376		$	191,286
Long-term notes - principal	1,489,210			1,584,158
Trade and other payables	144,542			112,973
Cash	—			(2,705		)
Trade and other receivables	(112,844		)	(112,171		)
Net debt	$	1,734,284		$	1,773,541

Availability under the Company's existing Revolving Facilities and the computed net debt to adjusted funds flow ratio as at December 31, 2017 and 2016 is set forth below.

	As at December 31
	2017		2016
Available undrawn credit facilities	$	494,634	$	580,767
Net debt to adjusted funds flow ratio	5.0		6.4

We utilized the Revolving Facilities to close the property acquisition (note 4) on January 20, 2017 which reduced the undrawn amount of the credit facility at December 31, 2017 as compared to December 31, 2016.

The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2016 is attributed to higher adjusted funds flow from improved commodity prices and higher annual production in 2017, along with a decrease in net debt as at December 31, 2017.

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