EX-99.2 3 a2208178zex-99_2.htm EX 99.2 12ZAR77301 CON. FIN. STMTS.

MANAGEMENT'S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING

The management of Baytex Energy Corp. is responsible for establishing and maintaining adequate internal control over financial reporting over the Company. Under the supervision of our 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 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2011, 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, 2011 has been audited by Deloitte & Touche LLP, the Company's Independent Registered Chartered Accountants, who also audited the Company's Consolidated Financial Statements for the year ended December 31, 2011.

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 Baytex Energy Corp. 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.

Deloitte & Touche LLP were appointed by the Company's shareholders 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 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 Chartered Accountants 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 Deloitte & Touche LLP and reviews their fees. The Independent Registered Chartered Accountants have access to the Audit Committee without the presence of management.

Anthony W. Marino President and Chief Executive Officer Baytex Energy Corp.		W. Derek Aylesworth Chief Financial Officer Baytex Energy Corp.

March 13, 2012

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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

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

We have audited the accompanying consolidated financial statements of Baytex Energy Corp. and subsidiaries (the "Company"), which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010, and the consolidated statements of income and comprehensive income, statements of changes in equity, and statements of cash flows for the years ended December 31, 2011 and December 31, 2010, and the notes to the consolidated financial statements.

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.

Auditor's 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 Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's 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, the auditor considers 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 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 basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Baytex Energy Corp. and subsidiaries as at December 31, 2011, December 31, 2010 and January 1, 2010 and their financial performance and cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 13, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

Calgary, Canada
March 13, 2012		Independent Registered Chartered Accountants

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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

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

We have audited the internal control over financial reporting of Baytex Energy Corp. and subsidiaries (the "Company") as of December 31, 2011, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of the Company and our report dated March 13, 2012 expressed an unqualified opinion on those financial statements.

Calgary, Canada
March 13, 2012		Independent Registered Chartered Accountants

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

As at				December 31, 2011			December 31, 2010			January 1, 2010
(thousands of Canadian dollars)
ASSETS
Current assets
Cash			$	7,847		$	–		$	10,177
Trade and other receivables (note 6)				206,951			151,792			137,154
Crude oil inventory				898			1,802			1,384
Financial derivatives (note 23)				10,879			13,921			29,453
				226,575			167,515			178,168
Non-current assets
	Deferred income tax asset (note 19)			10,133			7,870			1,789
	Financial derivatives (note 23)			180			2,622			2,541
	Exploration and evaluation asset (note 7)			129,774			113,082			124,621
	Oil and gas properties (note 8)			2,032,160			1,624,629			1,512,035
	Other plant and equipment (note 9)			25,233			27,550			27,096
	Goodwill (note 10)			37,755			37,755			37,755
			$	2,461,810		$	1,981,023		$	1,884,005
LIABILITIES
Current liabilities
	Trade and other payables (note 12)		$	225,831		$	183,314		$	186,516
	Dividends or distributions payable to shareholders/unitholders			25,936			22,742			19,674
	Bank loan (note 11)			–			–			265,088
	Convertible debentures (note 14)			–			–			7,736
	Financial derivatives (note 23)			25,205			20,312			12,004
				276,972			226,368			491,018
Non-current liabilities
	Bank loan (note 11)			311,960			303,773			–
	Long-term debt (note 13)			297,731			146,893			146,498
	Asset retirement obligations (note 15)			260,411			169,611			141,869
	Unit-based payment liability (note 17)			–			–			91,559
	Deferred income tax liability (note 19)			93,217			14,383			160,719
	Financial derivatives (note 23)			14,785			8,859			1,418
				1,255,076			869,887			1,033,081
SHAREHOLDERS'/UNITHOLDERS' EQUITY
Shareholders' capital (note 16)				1,680,184			1,484,335			–
Unitholders' capital (note 16)				–			–			1,331,161
Contributed surplus				85,716			129,129			–
Accumulated other comprehensive loss				(3,546	)		(10,323	)		–
Deficit				(555,620	)		(492,005	)		(480,237	)
				1,206,734			1,111,136			850,924
			$	2,461,810		$	1,981,023		$	1,884,005

Commitments and contingencies (note 26)

See accompanying notes to the consolidated financial statements.

On behalf of the Board

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

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CONSOLIDATED STATEMENTS OF INCOME
AND COMPREHENSIVE INCOME

Years Ended December 31			2011			2010
(thousands of Canadian dollars, except per common share and per trust unit amounts)
Revenues, net of royalties (note 20)		$	1,096,642		$	834,292
Expenses
Exploration and evaluation			13,865			24,502
Production and operating			209,177			171,704
Transportation and blending			249,850			188,591
General and administrative			39,335			40,747
Share-based or unit-based compensation (note 17)			33,845			94,199
Financing costs (note 21)			44,611			34,570
Gain on divestitures of oil and gas properties			(37,946	)		(16,227	)
Loss (gain) on financial derivatives (note 23)			18,030			(4,817	)
Foreign exchange loss (gain) (note 22)			7,834			(9,148	)
Depletion and depreciation (note 8 & 9)			248,468			202,796
			827,069			726,917
Net income before income taxes			269,573			107,375
Deferred income tax expense (recovery) (note 19)			52,141			(124,240	)
Net income attributable to shareholders/unitholders		$	217,432		$	231,615
Other comprehensive income (loss)
Foreign currency translation adjustment			6,777			(10,323	)
Comprehensive income attributable to shareholders/unitholders		$	224,209		$	221,292
Net income per common share or trust unit (note 18)
Basic		$	1.88		$	2.08
Diluted		$	1.83		$	2.01
Weighted average common shares or trust units (note 18)
Basic			115,960			111,450
Diluted			118,921			115,151

See accompanying notes to the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

			Shareholders' capital			Unitholders' capital			Contributed surplus			Accumulated other comprehensive income (loss)			Deficit			Total equity
(thousands of Canadian dollars)
Balance at January 1, 2010		$	–		$	1,331,161		$	–		$	–		$	(480,237	)	$	850,924
Distributions to unitholders			–			–			–			–			(243,383	)		(243,383	)
Issued on conversion of debentures			–			19,897			–			–			–			19,897
Exercise of unit rights			–			82,649			–			–			–			82,649
Issued pursuant to distribution reinvestment plan			–			51,699			–			–			–			51,699
Comprehensive income (loss) for the period			–			–			–			(10,323	)		231,615			221,292
Change in effective tax rate on issue costs			–			(1,071	)		–			–			–			(1,071	)
Exchanged for shares, pursuant to the Arrangement			1,484,335			(1,484,335	)		129,129			–			–			129,129
Balance at December 31, 2010		$	1,484,335		$	–		$	129,129		$	(10,323	)	$	(492,005	)	$	1,111,136
Dividends to shareholders			–			–			–			–			(281,047	)		(281,047	)
Exercise of share rights			122,306			–			(77,258	)		–			–			45,048
Share-based compensation			–			–			33,845			–			–			33,845
Issued pursuant to dividend reinvestment plan			73,543			–			–			–			–			73,543
Comprehensive income for the period			–			–			–			6,777			217,432			224,209
Balance at December 31, 2011		$	1,680,184		$	–		$	85,716		$	(3,546	)	$	(555,620	)	$	1,206,734

See accompanying notes to the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31				2011			2010
(thousands of Canadian dollars)
CASH PROVIDED BY (USED IN):
Operating activities
Net income for the year			$	217,432		$	231,615
Adjustments for:
	Share-based or unit-based compensation (note 17)			33,845			94,199
	Unrealized foreign exchange loss (gain) (note 22)			8,490			(8,999	)
	Exploration and evaluation			10,130			18,913
	Depletion and depreciation			248,468			202,796
	Unrealized loss on financial derivatives (note 23)			16,166			43,312
	Gain on divestitures of oil and gas properties			(37,946	)		(16,227	)
	Deferred income tax expense (recovery) (note 19)			52,141			(124,240	)
	Financing costs (note 21)			44,611			34,570
	Change in non-cash working capital (note 22)			(10,889	)		(11,704	)
	Asset retirement expenditures (note 15)			(10,588	)		(2,829	)
				571,860			461,406
Financing activities
Payments of dividends or distributions				(204,308	)		(188,615	)
Increase in bank loan				4,290			48,045
Proceeds from issuance of long-term debt (note 13)				145,810			–
Repayment of convertible debentures (note 14)				–			(341	)
Issuance of common shares or trust units (note 16)				45,048			26,021
Interest paid				(34,730	)		(28,499	)
				(43,890	)		(143,389	)
Investing activities
Additions to exploration and evaluation assets (note 7)				(9,104	)		(37,411	)
Additions to oil and gas properties				(358,744	)		(194,208	)
Property acquisitions				(76,164	)		(22,412	)
Corporate acquisitions (note 5)				(120,006	)		(40,314	)
Proceeds from divestitures				47,396			19,033
Additions to other plant and equipment, net of disposals (note 9)				(1,252	)		(8,237	)
Acquisition of financing entities (note 19)				–			(38,000	)
Change in non-cash working capital (note 22)				(2,553	)		(5,956	)
				(520,427	)		(327,505	)
Impact of foreign currency translation on cash balances				304			(689	)
Change in cash				7,847			(10,177	)
Cash, beginning of year				–			10,177
Cash, end of year			$	7,847		$	–

See accompanying notes to the consolidated financial statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
AS AT DECEMBER 31, 2011, DECEMBER 31, 2010 AND JANUARY 1, 2010
AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010
(all tabular amounts in thousands of Canadian dollars, except per common share and per trust unit 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 - 3^rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 - 8^th Avenue S.W., Calgary, Alberta, T2P 1G1.

Baytex Energy Trust (the "Trust") completed the conversion of its legal structure from an income trust to a corporation at year-end 2010 pursuant to a Plan of Arrangement under the Business Corporations Act (Alberta) (the "Arrangement"). Pursuant to the Arrangement, (i) on December 31, 2010, the trust units of the Trust were exchanged for common shares of Baytex on a one-for-one basis and (ii) on January 1, 2011, the Trust was dissolved and terminated, with Baytex being the successor to the Trust. The reorganization into a corporation has been accounted for on a continuity of interest basis, and accordingly, the consolidated financial statements reflect the financial position, results of operations and cash flows as if the Company had always carried on the business formerly carried on by the Trust.

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. Canadian generally accepted accounting principles have been revised to incorporate IFRS and publicly accountable enterprises are required to apply such standards for years beginning on or after January 1, 2011. Accordingly, these consolidated financial statements were prepared in accordance with IFRS 1, First-time Adoption of IFRS. The significant accounting policies set out below were consistently applied to all the periods presented.

In these financial statements, the term "previous GAAP" refers to Canadian generally accepted accounting principles prior to the adoption of IFRS. Previous GAAP differs in some areas from IFRS. In preparing these consolidated financial statements, management has amended certain accounting, valuation and consolidation methods applied in the previous GAAP financial statements to comply with IFRS. The date of transition to IFRS was January 1, 2010 and the comparative figures for 2010 were restated to reflect these adjustments. Reconciliations and descriptions of the effect of the transition from previous GAAP to IFRS on equity, net income and comprehensive income are included in note 29.

The consolidated financial statements were approved and authorized by the Board of Directors on March 13, 2012.

The consolidated financial statements have been prepared on the historical cost basis, except for derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency. All financial information is rounded to the nearest thousand, except per share or per trust unit amounts and when otherwise indicated.

3.     SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries from the respective dates of acquisition of the subsidiary companies. The date of acquisition is the date on which the Company obtains control and the subsidiary companies continue to be consolidated until the date such control

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ceases. Control exists when the Company has the ability to direct the activities of an entity to generate returns from its activities. Inter-company transactions and balances are eliminated upon consolidation. A portion of the Company's exploration, development and production activities is conducted jointly with others and involve jointly controlled assets. These jointly controlled assets are accounted for using the proportionate consolidation method whereby the consolidated financial statements reflect only the Company's proportionate interest.

Operating Segments Reporting

Baytex's operations are grouped into one operating segment for reporting consistent with the internal reporting provided to the chief operating decision-maker of the Company.

Measurement Uncertainty and Judgements

The preparation of the consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenue and expenses during the reporting period. Actual results can differ from those estimates.

In particular, amounts recorded for depletion of oil and gas properties are based on a unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account the level of development required to produce the reserves. The Company's total proved plus probable reserves are estimated annually using independent reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate a 50 percent or greater statistical probability of being recovered. Due to the inherent uncertainties and the necessarily limited nature of reservoir data, estimates of reserves are inherently imprecise, require the application of judgement and are subject to change as additional information becomes available. The impact of future changes to estimates on the consolidated financial statements of subsequent periods could be material.

Amounts recorded for depreciation are based on estimated useful lives of depreciable assets; management reviews these estimates at each reporting date.

The Company's capital assets are aggregated into cash-generating units based on their ability to generate largely independent cash flows and are used for impairment testing. The definition of the Company's cash-generating units is subject to management's judgement.

Impairment of assets and group of assets are calculated based on the higher of value-in-use calculations and fair value less costs to sell. These calculations require the use of estimates and assumptions on highly uncertain matters such as future commodity prices, effects of inflation and technology improvements on operating expenses, production profiles and the outlook of market supply-and-demand conditions for oil and natural gas products. Any changes to these estimates and assumptions could impact the carrying value of assets. The Company assesses internal and external indicators of impairment in determining whether the carrying values of the assets may not be recoverable.

Fair value of financial instruments, where active market quotes are not available are estimated using the Company's assessment of available market inputs and are described in note 23. These estimates may vary from the actual prices that will be achieved upon settlement of the financial instruments.

Fair values of share-based compensation are measured at the later of grant date or December 31, 2010, taking into consideration management's best estimate of the number of shares that will vest. Fair values of unit-based compensation were remeasured at each reporting date until the December 31, 2010 corporate conversion using a binomial-lattice pricing model, taking into consideration management's best estimate of the expected volatility, expected life of the option and estimated number of units that will vest.

The amounts recorded for asset retirement obligations are estimated based on the Company's net ownership interest in all 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 the discount and inflation rates. Any changes

9

to these estimates could change the amount recorded for asset retirement obligations and may materially impact the consolidated financial statements of future periods.

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 could reasonably be expected to materially affect the Company's financial position or reported results of operations.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty.

Business Combinations

Business combinations are accounted for using the acquisition method of accounting. The cost of an acquisition is measured as cash paid and the fair value of other assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and liabilities assumed, including contingent liabilities 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. Any deficiency of the cost of acquisition below the fair values of the identifiable net assets acquired is credited to net income in the statements of income and comprehensive income in the period of acquisition. Associated transaction costs are expensed when incurred.

Crude Oil Inventory

Crude oil inventory, consisting of production in transit in pipelines at the reporting date, is valued at the lower of cost, using the weighted average cost method, or net realizable value. Costs include direct and indirect expenditures incurred in bringing the crude oil to its existing condition and location.

Exploration and Evaluation Assets, Oil and Gas Properties and Other Plant and Equipment

a)     Pre-license Costs

Pre-license costs are costs incurred before the legal rights to explore a specific area have been obtained. These costs are expensed in the period in which they are incurred.

b)     Exploration and Evaluation ("E&E") Costs

Once the legal right to explore has been acquired, costs directly associated with an exploration well are capitalized as an intangible asset until the drilling of the well program/project is complete and the results have been evaluated. Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing. E&E costs are not depleted and are carried forward until technical feasibility and commercial viability of extracting a mineral resource is considered to be determined. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when proved and/or probable reserves are determined to exist. All such carried costs are subject to technical, commercial and management review quarterly to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the impairment costs are charged to exploration and evaluation expense. Upon determination of proven and/or probable reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified to oil and gas properties.

c)     Development Costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as oil and gas properties only when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves and are accumulated on a geotechnical area basis.

Major maintenance and repairs consist of the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and has been completely written off is replaced and it is probable that there are future economic benefits associated with the

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item, the expenditure is capitalized. The costs of the day-to-day servicing of property, plant and equipment are recognized in net income as incurred.

The carrying amount of any replaced or sold component of an oil and gas property is derecognized and included in net income in the period in which the item is derecognized.

d)     Borrowing Costs and Other Capitalized Costs

Borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset form part of the cost of that asset. A qualifying asset is an asset that requires a period of one year or greater to get ready for its intended use or sale. Baytex has had no qualifying assets that would allow for borrowing costs to be capitalized to the asset. All such borrowing costs are expensed as incurred.

No general and administrative expenses have been capitalized since Baytex's inception.

e)     Depletion and Depreciation

The net carrying value of oil and gas properties is depleted using the units of production method using estimated proved and probable petroleum and natural gas reserves, by reference to the ratio of production in the year to the related proven and probable reserves at forecast prices, taking into account estimated future development costs necessary to bring those reserves into production. For purposes of this 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. Future development costs are estimated as the costs of development required to produce the reserves. These estimates are prepared by independent reserve engineers at least annually.

The depreciation methods and estimated useful lives for other assets 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.

Impairment of Non-financial Assets

The goodwill balance is assessed for impairment at least annually at year end or more frequently if events or changes in circumstances indicate that the asset may be impaired. E&E assets are assessed for impairment when they are reclassified to oil and gas properties and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. The Company assesses other assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable.

Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets (the "cash-generating unit" or "CGU"). Goodwill acquired is allocated to CGUs expected to benefit from synergies of the related business combination.

If any such indication of impairment exists or when annual impairment testing for a CGU is required, the Company makes an estimate of its recoverable amount. A CGU's recoverable amount is the higher of its fair value less costs to sell and its value-in-use. In assessing value-in-use, the estimated future cash flows are adjusted for the risks specific to the CGU and are discounted to their present value using a pre-tax discount rate that reflects current market

11

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 amount reduces first the carrying amount of any goodwill allocated to the CGU. Any remaining impairment is allocated to the individual assets in the CGU on a pro rata basis. Impairment is charged to net income in the period in which it occurs.

For all assets excluding goodwill, an assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depletion and depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in net income. After such a reversal, the depletion or depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Impairment losses recognized in relation to goodwill are not reversed for subsequent increases in its recoverable amount.

Asset Retirement Obligations

The Company recognizes a liability at the discounted value for the future asset retirement costs associated with its oil and gas properties 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 to expense over its useful life. The discount in the liability unwinds until the date of expected settlement of the retirement obligations and is recognized as a finance cost in the statements of income and comprehensive income. The liability will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations to the extent that the liability exists on the statements of financial position.

Foreign Currency Translation

Transactions completed in foreign currencies are reflected in Canadian dollars at the foreign currency exchange rates prevailing at the time of the transactions. Monetary assets and liabilities denominated in foreign currencies are reflected in the statements of financial position at the Canadian equivalent at the foreign currency exchange rates prevailing at the reporting date. Foreign exchange gains and losses are included in net income.

Revenues and expenses of foreign operations are translated to Canadian dollars using average foreign currency exchange rates for the period. Monetary assets and liabilities that form part of the net investment in the foreign operation are translated at the period-end foreign currency exchange rate. Gains or losses resulting from the translation are included in accumulated other comprehensive income (loss) in shareholders'/unitholders' equity and are recognized in net income when there has been a disposal or partial disposal of the foreign operation.

Revenue Recognition

Revenue associated with sales of petroleum and natural gas is recognized when title passes to the purchaser at the pipeline delivery point. Revenue is measured net of discounts, customs duties and royalties. With respect to royalties, the Company is acting as a collection agent on behalf of the Crown and other royalty interest holders.

Revenue from the production of oil 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 joint venture agreements.

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 or 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. Available-for-sale financial

12

instruments are measured at fair value with changes in fair value recorded in other comprehensive income (loss) until the instrument is derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the effective interest method.

All risk management contracts are recorded in the statements of financial position at fair value unless they were entered into and continue to be held in accordance with the Company's expected purchase, sale and usage requirements. All changes in their fair value are recorded in net income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income until the underlying hedged transaction is recognized in net income. The Company has elected not to use cash flow hedge accounting on its risk management contracts with financial counterparties resulting in all changes in fair value being recorded in net income.

Cash is classified as FVTPL. Trade and other receivables are classified as loans and receivables, which are measured at amortized cost. Trade and other payables and the bank loan are classified as other financial liabilities, which are measured at amortized cost.

The convertible debentures have been classified as liabilities, net of the fair value of the conversion feature which has been classified as a financial derivative liability. The financial derivative liability requires a fair value method of accounting and changes in the fair value of the instrument are recognized in the net income. The liability component is classified as other financial liabilities. The liability component will accrete up to the principal balance at maturity. The accretion and the interest paid are reported as finance expense in the consolidated statements of income and comprehensive income (loss). If the debentures were converted to trust units, the fair value of the conversion feature would be reclassified to unitholders' capital along with the principal amounts converted.

An embedded derivative is a component of a contract that modifies the cash flows of the contract. These hybrid contracts are considered to consist of a host contract plus an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative. The Company has no material embedded derivatives.

The transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability classified at FVTPL are expensed immediately. For a financial asset or 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 over the term of the financial instrument.

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. The Company does not use financial derivatives for trading or speculative purposes. These instruments are classified as FVTPL unless designated for hedge accounting. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting. As a result, for all derivative instruments, the Company applies the fair value method of accounting 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 and comprehensive income 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 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 sales contracts are recognized in revenue in the period of settlement.

Income Taxes

Current and deferred income taxes are recognized in net income, except when they relate to items that are recognized directly in equity. Where current and deferred income taxes are recognized directly in equity when

13

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.

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 or substantively enacted at the end of the reporting period.

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

Share Rights Plan and Share Award Incentive Plan

The Trust's Trust Unit Rights Incentive Plan (the "Unit Rights Plan"), which was superseded by the Company's Common Share Rights Incentive Plan (the "Share Rights Plan"), is described in note 17. The exercise price of the share rights under the Share Rights Plan may be reduced in future periods in accordance with the terms of the Share Rights Plan.

Prior to the conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability was re-measured at each reporting date and at settlement date. Any changes in fair value were recognized in net income for the period. The conversion of the outstanding unit rights to share rights in connection with the Arrangement effectively changed the related classification from a liability plan to an equity-settled plan. The expense recognized from the date of modification over the remainder of the vesting period was determined based on the fair value of the reclassified equity awards at the date of the modification using a binomial-lattice pricing model.

Baytex's Share Award Incentive Plan is described in note 17.

4.     CHANGES IN ACCOUNTING POLICIES

Future Accounting Pronouncements

Financial Instruments

IASB published IFRS 9, "Financial Instruments" and replaces 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: at amortized cost or fair value.

IFRS 9 is effective for annual periods beginning on or after January 1, 2015, with earlier application permitted. The adoption of this standard may have an impact on the Company's accounting for financial assets and financial liabilities.

Consolidation, Joint Ventures and Disclosures

In May 2011, the IASB issued new standards, IFRS 10, "Consolidated Financial Statements", IFRS 11, "Joint Arrangements" and IFRS 12, "Disclosure of Interests in Other Entities". IAS 27, "Separate Financial Statements" and IAS 28, "Investments in Associates and Joint Ventures" were amended based on the issuance of IFRS 10, IFRS 11 and IFRS 12. Each of the new and revised standards is effective for annual periods beginning on or after January 1, 2013, with earlier application permitted. The adoption of these standards may have an impact on the consolidated financial statements of the Company.

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Consolidated Financial Statements

IFRS 10, "Consolidated Financial Statements" replaces the consolidation guidance in IAS 27, "Consolidated and Separate Financial Statements" by introducing a single consolidation model for all entities based on control, irrespective of the nature of the investee. Under IFRS 10, control is based on whether an investor has 1) power over the investee; 2) exposure, or rights, to variable returns from its involvement with the investee; and 3) the ability to use its power over the investee to affect the amount of the returns.

Joint Arrangements

IFRS 11, "Joint Arrangements" replaces IAS 31, "Interest in Joint Ventures". The new standard redefines joint operations and joint ventures and requires joint operations to be proportionately consolidated and joint ventures to be equity accounted.

Disclosure of Interests in Other Entities

IFRS 12, "Disclosure of Interests in Other Entities", requires enhanced disclosures about both consolidated entities and unconsolidated entities in which an entity has involvement. The objective of IFRS 12 is to require information so that financial statement users may evaluate the basis of control, any restrictions on consolidated assets and liabilities, risk exposures arising from involvements with unconsolidated structured entities and non-controlling interest holders' involvement in the activities of consolidated entities.

Fair Value Measurement

In May 2011, the IASB issued IFRS 13, "Fair Value Measurement" which replaces the guidance on fair value measurement in existing IFRS accounting literature with a single standard. IFRS 13 is effective for annual periods beginning on or after January 1, 2013 with early application permitted. The adoption of this standard may have an impact on the consolidated financial statements of the Company.

Presentation of Financial Statements

In June 2011, the IASB amended IAS 1, "Presentation of Financial Statements" to require companies preparing financial statements in accordance with IFRS to group together items within other comprehensive income that may be reclassified to the net income section of the income statement. The amendments also reaffirm existing requirements that items in other comprehensive income and profit or loss should be presented as either a single statement or two consecutive statements. The amendment to IAS 1 is effective for annual periods beginning on or after July 1, 2012 with earlier application permitted. The adoption of this amended standard is not expected to have a material impact on the consolidated financial statements of the Company.

5.     BUSINESS COMBINATIONS

2011 Corporate Acquisition

On February 3, 2011, Baytex acquired all the issued and outstanding shares of a private company, which was a junior heavy oil producer with operational focus in the Seal area of northern Alberta and the Lloydminster area of western Saskatchewan, for total consideration of $120.9 million (net of cash acquired). This acquisition provides additional development opportunities in the Seal area where Baytex already possesses significant leasehold and

15

operating infrastructure. The acquisition has been accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized below:

Consideration for the acquisition:
Cash paid for exploration and evaluation assets and oil and gas properties		$	120,006
Cash paid for working capital (net of cash acquired)			869
Total consideration		$	120,875
Recognized amounts of identifiable assets acquired and liabilities assumed:
Trade and other receivables		$	1,664
Exploration and evaluation assets			14,944
Oil and gas properties			131,635
Trade and other payables			(795	)
Asset retirement obligations			(2,031	)
Deferred income tax liability			(24,542	)
Total net assets acquired		$	120,875

Acquisition-related costs totaling $0.3 million have been excluded from the consideration transferred and have been recognized as an expense in the year ended December 31, 2011, within the "general and administrative" line item in the consolidated statements of income and comprehensive income. The fair value of the acquired trade and other receivables approximates the carrying value due to their short term nature.

From the period of February 3, 2011 to December 31, 2011, the acquired properties contributed revenues, net of royalties, of $38.3 million and revenues, net of royalties, production and operating expenses ("operating income") of $25.5 million to Baytex's operations. If the acquisition had occurred on January 1, 2011, management estimates its pro forma revenues, net of royalties and operating income would have been approximately $41.4 million and $27.9 million, respectively, for the year ended December 31, 2011. It is impracticable to derive all amounts necessary to determine contributed net income from the acquired properties as operations were immediately merged with Baytex's operations to realize synergies.

The fair values of assets and liabilities recognized are estimates due to the uncertainty of provisional amounts recognized.

2011 Property Acquisition

On February 3, 2011, Baytex acquired heavy oil properties in the Seal area of northern Alberta and the Lloydminster area of western Saskatchewan, for total consideration of $38.4 million. This acquisition provides additional development opportunities in the Seal area where Baytex already possesses significant leasehold and operating infrastructure. The acquisition has been accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized below:

Consideration for the acquisition:
Cash paid		$	38,439
Total consideration		$	38,439
Recognized amounts of identifiable assets acquired and liabilities assumed:
Exploration and evaluation assets		$	1,700
Oil and gas properties			37,247
Asset retirement obligations			(508	)
Total net assets acquired		$	38,439

Acquisition-related costs totaling $0.1 million have been excluded from the consideration transferred and have been recognized as an expense in the year ended December 31, 2011, within the "General and administrative" line item in the consolidated statements of income and comprehensive income.

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From the period of February 3, 2011 to December 31, 2011, the acquired properties contributed revenues, net of royalties, of $9.6 million and operating income of $6.4 million to Baytex's operations. If the acquisition had occurred on January 1, 2011, management estimates its pro forma revenues, net of royalties and operating income would have been approximately $10.4 million and $7.0 million, respectively, for the year ended December 31, 2011. It is impracticable to derive all amounts necessary to determine contributed net income from the acquired properties as operations were immediately merged with Baytex's operations to realize synergies.

The fair values of assets and liabilities recognized are estimates due to the uncertainty of provisional amounts recognized.

2010 Corporate Acquisition

On May 26, 2010, Baytex acquired all the issued and outstanding shares of a private company, which was a junior heavy oil producer with operational focus in east central Alberta through to west central Saskatchewan, for total consideration of $40.3 million (net of cash acquired). The acquired assets provide a number of cold heavy oil development opportunities and were readily integrated into Baytex's existing producing infrastructure in the Lloydminster area. The acquisition has been accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized below:

Consideration for the acquisition:
Cash paid (net of cash acquired)		$	40,314
Total consideration		$	40,314
Recognized amounts of identifiable assets acquired and liabilities assumed:
Trade and other receivables		$	1,722
Exploration and evaluation assets			2,534
Oil and gas properties			48,313
Trade and other payables			(1,436	)
Asset retirement obligations			(2,207	)
Deferred income tax liability			(8,612	)
Total net assets acquired		$	40,314

Acquisition-related costs totaling $0.6 million have been excluded from the consideration transferred and have been recognized as an expense in the year ended December 31, 2010, within the "general and administrative" line item in the consolidated statements of income and comprehensive income. The fair value of the acquired trade and other receivables approximates the carrying value due to their short term nature.

From the period of May 26, 2010 to December 31, 2010, the acquired properties contributed revenues, net of royalties, of $8.7 million and operating income of $3.9 million to Baytex's operations. If the acquisition had occurred on January 1, 2010, management estimates its pro forma revenues, net of royalties and operating income would have been approximately $14.9 million and $3.6 million, respectively, for the year ended December 31, 2010. It is impracticable to derive all amounts necessary to determine contributed net income from the acquired properties as operations were immediately merged with Baytex's operations to realize synergies.

6.     TRADE AND OTHER RECEIVABLES

As at			December 31, 2011			December 31, 2010			January 1, 2010
Petroleum and natural gas sales and accrual		$	161,567		$	119,827		$	107,657
Joint venture			42,928			30,536			28,581
Prepaid, deposits and other			3,415			3,282			3,252
Allowance for doubtful accounts			(959	)		(1,853	)		(2,336	)
		$	206,951		$	151,792		$	137,154

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7.     EXPLORATION AND EVALUATION ASSETS

Cost
As at January 1, 2010			$	124,621
	Capital expenditures			37,411
	Corporate acquisition			2,534
	Exploration and evaluation expense			(18,913	)
	Transfer to oil and gas properties			(29,116	)
	Divestitures			(113	)
	Foreign currency translation			(3,342	)
As at December 31, 2010			$	113,082
	Capital expenditures			9,104
	Corporate acquisition			14,944
	Property acquisition			18,013
	Exploration and evaluation expense			(10,130	)
	Transfer to oil and gas properties			(14,398	)
	Divestitures			(2,058	)
	Foreign currency translation			1,217
As at December 31, 2011			$	129,774

8.     OIL AND GAS PROPERTIES

Cost
As at January 1, 2010			$	1,512,035
	Capital expenditures			218,651
	Corporate acquisition			48,313
	Transferred from exploration and evaluation assets			29,116
	Change in asset retirement obligations			21,766
	Divestitures			(4,072	)
	Foreign currency translation			(6,458	)
As at December 31, 2010			$	1,819,351
	Capital expenditures			364,578
	Corporate acquisition			131,635
	Property acquisitions			61,137
	Transferred from exploration and evaluation assets			14,398
	Change in asset retirement obligations			84,879
	Divestitures			(10,233	)
	Foreign currency translation			5,674
As at December 31, 2011			$	2,471,419

Accumulated depletion
As at January 1, 2010			$	–
	Depletion for the period			195,015
	Divestitures			(107	)
	Foreign currency translation			(186	)
As at December 31, 2010			$	194,722
	Depletion for the period			244,893
	Divestitures			(667	)
	Foreign currency translation			311
As at December 31, 2011			$	439,259

Carrying value
As at January 1, 2010		$	1,512,035
As at December 31, 2010		$	1,624,629
As at December 31, 2011		$	2,032,160

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For the year ended December 31, 2011, Baytex disposed of assets in Kaybob and Dodsland areas which consisted of $9.0 million of oil and gas properties and $2.1 million of exploration and evaluation assets for net cash proceeds of $47.4 million. Gains totaling $36.3 million were recognized in the statements of income and comprehensive income.

The carrying value of petroleum and natural gas properties are subject to impairment tests, which were calculated at December 31, 2011 using the following benchmark reference prices for the years 2012 to 2016 adjusted for commodity differentials specific to the Company:

		2012		2013		2014		2015		2016
WTI crude oil (US$/bbl)		98.07		94.90		92.00		97.42		99.37
AECO natural gas ($/MMBtu)		3.16		3.78		4.13		5.53		5.65
Exchange rate (USD/CAD)		1.01		1.01		1.01		1.01		1.01

Oil and natural gas prices reflect the NYMEX futures market for the period ending 2012. This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2016 have been adjusted for estimated inflation at an estimated annual rate of 2 percent. Based on the impairment test calculations, the Company's estimated discounted future net cash flows associated with proved and probable reserves exceeded the net book value of the oil and gas properties.

9.     OTHER PLANT AND EQUIPMENT

Cost
As at January 1, 2010			$	49,341
	Capital expenditures			8,473
	Disposals			(236	)
	Foreign currency translation			(54	)
As at December 31, 2010			$	57,524
	Capital expenditures			1,252
	Foreign currency translation			25
As at December 31, 2011			$	58,801

Accumulated depletion
As at January 1, 2010			$	22,245
	Depreciation			7,781
	Disposals			(26	)
	Foreign currency translation			(26	)
As at December 31, 2010			$	29,974
	Depreciation			3,575
	Foreign currency translation			19
As at December 31, 2011			$	33,568

Carrying value
As at January 1, 2010		$	27,096
As at December 31, 2010		$	27,550
As at December 31, 2011		$	25,233

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Field inventory held is valued at the lower of cost, using the weighted average cost method, or net realizable value and is not depreciated.

10.  GOODWILL

As at			December 31, 2011			December 31, 2010			January 1, 2010
Cost		$	37,755		$	37,755		$	37,755
Impairment			–			–			–
Carrying value		$	37,755		$	37,755		$	37,755

The carrying value, calculated based on the higher of value-in-use (as compared to fair value less cost to sell), of the CGU was determined to be lower than its recoverable amount and no impairment loss was recognized.

The Company estimates value-in-use by using a discounted cash flow model using a pre-tax discount rate. The reserve reports generated by an external party and approved by senior management on an annual basis is the source for information for the determination of the value-in-use value assigned. The reserve reports are based on a remaining reserve life of 50 years. The forecasted cash flows include reserves where there is at least a 50% probability that the estimated proved plus probable reserves will be recovered. Value-in-use, related to this goodwill impairment test, was determined by discounting the future cash flows generated from the CGU using key assumptions as noted in note 8 "Oil and Gas Properties".

11.  BANK LOAN

As at			December 31, 2011			December 31, 2010			January 1, 2010
Bank loan		$	311,960		$	303,773		$	265,088

Baytex Energy Ltd. ("Baytex Energy"), a wholly-owned subsidiary of Baytex, has established credit facilities with a syndicate of chartered banks. On June 14, 2011, Baytex Energy reached agreement with its lending syndicate to amend the credit facilities to (i) increase the amount available under the facilities to $700 million (from $650 million), (ii) extend the revolving period from 364 days (with a one-year term out following the revolving period) to three years, which is extendible annually for a 1, 2 or 3 year period (subject to a maximum three-year term at any time), and (iii) change the structure of the facilities from reserves-based to covenant-based (with standard commercial covenants for facilities of this nature). The credit facilities do not require any mandatory principal payments during the three-year term. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the agent bank's prime lending rate, bankers' acceptance discount rates or London Interbank Offer Rates, plus applicable margins. The credit facilities are secured by a floating charge over all of Baytex Energy's assets and are guaranteed by Baytex and certain of its material subsidiaries. The credit facilities do not include a term-out feature or a borrowing base restriction. In the event that Baytex Energy does not comply with covenants under the credit facilities, Baytex's ability to pay dividends to its shareholders may be restricted.

Financing costs for the year ended December 31, 2011 includes facility amendment fees of $2.3 million ($1.4 million for year ended December 31, 2010). The weighted average interest rate on the bank loan for the year ended December 31, 2011 was 3.69% (3.94% for the year ended December 31, 2010).

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12.  TRADE AND OTHER PAYABLES

As at			December 31, 2011			December 31, 2010			January 1, 2010
Trade payables		$	120,717		$	79,841		$	79,150
Joint venture			17,457			12,284			14,924
Capital and operating expense accruals			74,673			77,656			75,471
Other			12,984			13,533			16,971
		$	225,831		$	183,314		$	186,516

13.  LONG-TERM DEBT

As at			December 31, 2011			December 31, 2010			January 1, 2010
9.15% senior unsecured debentures (Cdn$150,000 – principal)		$	147,328		$	146,893		$	146,498
6.75% senior unsecured debentures (US$150,000 – principal)			150,403			–			–
		$	297,731		$	146,893		$	146,498

On August 26, 2009, the Trust issued $150.0 million principal amount of Series A senior unsecured debentures bearing interest at 9.15% payable semi-annually with principal repayable on August 26, 2016. As a result of the Arrangement, Baytex assumed all of the rights and obligations of the Trust under the Series A senior unsecured debentures effective January 1, 2011. These debentures are subordinate to Baytex Energy's bank credit facilities. After August 26 of each of the following years, these debentures are redeemable at the Company's option, in whole or in part, with not less than 30 nor more than 60 days' notice at the following redemption prices (expressed as a percentage of the principal amount of the debentures): 2012 at 104.575%, 2013 at 103.05%, 2014 at 101.525% and 2015 at 100%. These notes are carried at amortized cost, net of a $3.6 million transaction cost. The notes accrete up to the principal balance at maturity using the effective interest rate of 9.6%.

On February 17, 2011, Baytex issued US$150.0 million principal amount of Series B senior unsecured debentures bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. These debentures are subordinate to Baytex Energy's bank credit facilities. After February 17 of each of the following years, these debentures are redeemable at the Company's option, in whole or in part, with not less than 30 nor more than 60 days' notice at the following redemption prices (expressed as a percentage of the principal amount of the debentures): 2016 at 103.375%, 2017 at 102.25%, 2018 at 101.525% and 2019 at 100%. These notes are carried at amortized cost, net of a $2.2 million transaction cost. These notes accrete up to the principal balance at maturity using the effective interest rate of 7.0%.

Accretion expense on debentures of $0.2 million has been recorded for the year ended December 31, 2011 (year ended December 31, 2010 – $0.3 million).

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14.  CONVERTIBLE DEBENTURES

		Number of Convertible Debentures			Convertible Debentures			Conversion Feature of Debentures
Balance, January 1, 2010		7,815		$	7,736		$	7,354
Conversion		(7,474	)		(7,426	)		(12,473	)
Accretion		–			31			–
Loss on financial derivative		–			–			5,119
Repayment on maturity		(341	)		(341	)		–
Balance, December 31, 2010 and December 31, 2011		–		$	–		$	–

In June 2005, the Trust issued $100.0 million principal amount of 6.5% convertible unsecured subordinated debentures for net proceeds of $95.8 million. The debentures paid interest semi-annually and were convertible at the option of the holder at any time into fully-paid trust units at a conversion price of $14.75 per trust unit. On the December 31, 2010 maturity date, the outstanding $0.3 million principal amount was repaid at par value.

The debentures were classified as debt net of the fair value of the conversion feature which was classified as a financial derivative liability. This resulted in $95.2 million being classified as debt and $4.8 million being initially classified as a financial derivative liability. The debt portion accreted up to the principal balance at maturity, using the effective interest rate of 7.6%. The accretion and the interest paid were expensed as a finance expense in the consolidated statements of income and comprehensive income. When debentures were converted to trust units, the fair value of the conversion feature under financial derivative liability was reclassified to unitholders' capital along with the principal amounts converted.

15.  ASSET RETIREMENT OBLIGATIONS

			December 31, 2011			December 31, 2010
Balance, beginning of year		$	169,611		$	141,869
Liabilities incurred			5,834			2,030
Liabilities settled			(10,588	)		(2,829	)
Liabilities acquired			5,003			2,207
Liabilities divested			(556	)		(1,254	)
Accretion			6,185			5,862
Change in estimate(1)			84,879			21,766
Foreign currency translation			43			(40	)
Balance, end of year		$	260,411		$	169,611

(1)

Changes in the status of wells, changes in discount rates and changes in the estimated costs of abandonment and reclamation are factors resulting in a change in estimate.

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 52 years. The undiscounted amount of estimated cash flow required to settle the asset retirement obligations using an estimated annual inflation rate of 2.0% at December 31, 2011 is $315.9 million (December 31, 2010 – $288.8 million, January 1, 2010 – $279.3 million). The amount of estimated cash flow required to settle the asset retirement obligations using an estimated annual inflation rate of 2.0% and discounted at a risk free rate of 2.5% at December 31, 2011 (December 31, 2010 – 3.5% and January 1, 2010 – 4.0%) is $260.4 million (December 31, 2010 – $169.6 million and January 1, 2010 – $141.9 million).

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16.  SHAREHOLDERS'/UNITHOLDERS' CAPITAL

Unitholders' Capital

		Number of Trust Units			Amount
Balance, January 1, 2010		109,299		$	1,331,161
Issued on conversion of debentures		507			19,897
Issued on exercise of unit rights		2,337			26,021
Transfer from unit-based payment liability on exercise of unit rights		–			56,628
Issued pursuant to distribution reinvestment plan		1,569			51,699
Change in effective tax rate on issue costs		–			(1,071	)
Exchanged for shares, pursuant to the Arrangement		(113,712	)		(1,484,335	)
Balance, December 31, 2010 and December 31, 2011		–		$	–

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, 2011, no preferred shares have been issued by the Company and all common shares issued were fully paid.

		Number of Common Shares			Amount
Balance, January 1, 2010		–		$	–
Issued for units, pursuant to the Arrangement		113,712			1,484,335
Balance, December 31, 2010		113,712		$	1,484,335
Issued on exercise of share rights		2,665			45,048
Transfer from contributed surplus on exercise of share rights		–			77,258
Issued pursuant to dividend reinvestment plan		1,516			73,543
Balance, December 31, 2011		117,893		$	1,680,184

Baytex has a Dividend Reinvestment Plan (the "DRIP") that allows eligible holders in Canada and the United States to reinvest their monthly cash dividends to acquire additional common shares. At the discretion of Baytex, common shares will either be issued from treasury or acquired in the open market at prevailing market prices. Pursuant to the terms of the DRIP, common shares were issued from treasury at a five percent discount to the arithmetic average of the daily volume weighted average trading prices of the common shares on the Toronto Stock Exchange (in respect of participants resident in Canada or any jurisdiction other than the United States) or the New York Stock Exchange (in respect of participants resident in the United States) for the period commencing on the second business day after the dividend record date and ending on the second business day immediately prior to the dividend payment date. Commencing with the dividends declared on December 15, 2011, the discount was reduced to three percent. Baytex reserves the right at any time to change or eliminate the discount on common shares acquired through the DRIP from treasury.

The holders of common shares or trust units may receive dividends or distributions as declared from time to time and are entitled to one vote per share or trust unit at any meetings of the holders of common shares or trust units. All common shares rank among themselves equally and with regard to the Company's net assets in the event of termination or winding-up of the Company.

Monthly dividends of $0.22 per common share in December 2011 and $0.20 per month for each of the previous eleven months were declared by the Company during the year ended December 31, 2011 for total dividends declared of $281.0 million. Monthly distributions of $0.20 per trust unit in December 2010 and $0.18 per trust unit for each of the previous eleven months were declared by the Trust during the year ended December 31, 2010 for total distributions declared of $243.4 million.

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Subsequent to December 31, 2011, the Company announced that monthly dividends in respect of January and February 2012 operations of $0.22 per common share totaling $26.1 million each month will be payable on February 15, 2012 and March 15, 2012 to shareholders of record at January 31, 2012 and February 29, 2012, respectively.

17.  EQUITY BASED PLANS

Share Rights Plan

The Trust had a Unit Rights Plan pursuant to which rights to acquire trust units ("unit rights") were granted to eligible directors, officers and employees of the Trust and its subsidiaries. The maximum number of trust units issuable pursuant to the Unit Rights Plan was a "rolling" maximum equal to 10% of the outstanding trust units plus the number of trust units which were issuable on the exchange of outstanding exchangeable shares. Any increase in the issued and outstanding trust units resulted in an increase in the number of trust units available for issuance under the Unit Rights Plan, and any exercises of unit rights made new grants available under the Unit Rights Plan, effectively resulting in a re-loading of the number of unit rights available to grant under the Unit Rights Plan. Under the Unit Rights Plan, unit rights had a maximum term of five years and vested and became exercisable as to one-third on each of the first, second and third anniversaries of the grant date.

The Unit Rights Plan provided that the exercise price of the unit rights may be reduced to account for future distributions, subject to certain performance criteria. Effective November 16, 2009, the Unit Rights Plan was amended to (i) base the exercise price of unit rights on the closing price of the trust units on the trading day prior to the date of grant (previously based on a five-day volume weighted average trading price) and (ii) permit the granting of unit rights with a fixed exercise price. Effective October 25, 2010, the Unit Rights Plan was amended to provide holders of unit rights who are not subject to taxation in the United States with the ability to elect at the time of exercise to pay an exercise price per unit right equal to (i) the original exercise price reduced for distributions paid subsequent to grant date or (ii) the original exercise price.

Pursuant to the terms of the Unit Rights Plan, the Arrangement (as described in note 1) constituted a capital reorganization which resulted in each holder of unit rights exchanging such rights for equivalent rights to acquire common shares of Baytex ("share rights") on a one-for-one basis on December 31, 2010. The share rights are subject to the terms of the Share Rights Plan. The Share Rights Plan is substantially similar to the Unit Rights Plan other than amendments necessary to reflect:

•

The entitlement of holders to receive common shares instead of trust units;

•

The exercise price, as calculated for unit rights outstanding at the effective time of the Arrangement, will be carried forward under the Share Rights Plan and, if applicable, future adjustments to the exercise price after the completion of the Arrangement will be based on dividends paid on the common shares of Baytex rather than distributions paid on the trust units of the Trust; and

•

The administration of the Share Rights Plan will be carried out by Baytex as opposed to Baytex Energy.

As a result of the adoption of the Share Award Incentive Plan (as described below), no further grants will be made under the Share Rights Plan effective January 1, 2011.

Baytex recorded compensation expense of $15.6 million for the year ended December 31, 2011 (year ended December 31, 2010 – $94.2 million) related to the share rights under the Share Rights Plan or the unit rights under the Unit Rights Plan.

Baytex used a binomial-lattice pricing model to calculate the estimated weighted average fair value of the share rights and unit rights. The following assumptions were used to arrive at the estimate of fair values at each reporting

24

date, with the expense recognized from the December 31, 2010 date of modification over the remainder of the vesting period determined based on the fair value of the reclassified unit rights at the date of the modification:

As at			December 31, 2010			January 1, 2010
Expected annual exercise price reduction (on unit rights or share rights with declining exercise price)			Various		$	2.16
Share or unit price		$	46.61		$	29.70
Expected volatility(1)			43.8%			43.4%
Risk free interest rate			1.99%			2.57%
Forfeiture rate			4.6%			4.6%

(1)

Expected volatility is estimated by considering the historical average price volatility of the common shares/trust units commensurate with the term of the right.

The number of share rights or unit rights outstanding and exercise prices are detailed below:

		Number of share or unit rights (000's)			Weighted average exercise price
Balance, January 1, 2010		8,120		$	16.68
Granted(2)		190			32.71
Exercised(1)		(2,337	)		11.13
Forfeited(1)		(212	)		20.35
Balance, December 31, 2010		5,761		$	17.02
Granted		–			–
Exercised(1)		(2,665	)		16.92
Forfeited(1)		(125	)		23.05
Balance, December 31, 2011		2,971		$	16.98

(1)

Weighted average exercise price reflects the grant price less the reduction in exercise price.

(2)

Weighted average exercise price of rights granted is based on the exercise price at the date of grant.

The following table summarizes information about the share rights outstanding at December 31, 2011:

		Exercise Prices Applying Original Grant Price										Exercise Prices Applying Original Grant Price Reduced for Dividends and Distributions Subsequent to Grant Date
PRICE RANGE		Number Outstanding at December 31, 2011 (000's)		Weighted Average Grant Price		Weighted Average Remaining Term (years)		Number Exercisable at December 31, 2011 (000's)		Weighted Average Exercise Price		Number Outstanding at December 31, 2011 (000's)		Weighted Average Exercise Price		Weighted Average Remaining Term (years)		Number Exercisable at December 31, 2011 (000's)		Weighted Average Exercise Price
$5.08 to $12.00		–		$        –		–		–		$        –		1,385		$10.88		1.5		1,305		$10.97
$12.01 to $19.00		1,174		17.63		1.8		1,067		17.85		369		17.01		2.1		285		17.28
$19.01 to $26.00		648		20.23		1.2		584		20.01		1,014		22.85		2.8		616		22.85
$26.01 to $33.00		1,105		27.94		2.9		648		27.79		177		28.45		3.1		96		27.94
$33.01 to $40.00		41		35.60		3.6		7		35.35		24		34.78		3.6		4		35.29
$40.01 to $47.72		3		44.96		4.0		1		44.35		2		43.29		4.0		1		42.63
$5.08 to $47.72		2,971		$22.30		2.1		2,307		$21.25		2,971		$16.98		2.1		2,307		$15.60

Share Award Incentive Plan

In connection with the Arrangement, the unitholders of the Trust approved, at a special meeting held on December 9, 2010, the adoption by the Company effective January 1, 2011 of 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 plan of the

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Company, including the Share Rights Plan) shall not at any time exceed 10% 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 as described below) with such common shares to be issued as to one-third on each of the first, second and third anniversary dates of the date of grant. Each performance award entitles the holder to be issued as to one-third on each of the first, second and third anniversary dates of the date of grant the number of common shares designated in the performance award (plus dividend equivalents as described below) multiplied by a payout multiplier. 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 payment of dividends from the grant date to the applicable issue date.

The Company recorded compensation expense of $18.2 million for the year ended December 31, 2011 and related to the share awards (year ended December 31, 2010 – $nil).

The fair value of share awards is determined at the date of grant using the closing price of the common shares and, for performance awards, an estimated payout multiplier. The amount of compensation expense is reduced by an estimated forfeiture rate, which has been estimated at 4.6% of outstanding awards. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. The estimated weighted average fair value for share awards is $50.27 per restricted award and performance award granted during the year ended December 31, 2011 (no share awards were granted during the year ended December 31, 2010).

The number of share awards outstanding is detailed below:

		Number of restricted awards (000's)		Number of performance awards (000's)		Number of share awards (000's)
Balance, January 1, 2010 and December 31, 2010		–		–		–
Granted		389		243		632
Forfeited		(24	)	(14	)	(38	)
Balance, December 31, 2011		365		229		594

Under the terms of the Share Award Incentive Plan, the Compensation Committee of the Board of Directors of Baytex has the authority to approve the granting of share awards. The Compensation Committee's historical practice is to split the share award into two equal amounts, with 50% granted immediately and 50% granted six months subsequent to the initial grant date (with such grant being conditional on the grantee continuing to be employed by the Company or its subsidiaries on such date).

18.  NET INCOME PER SHARE AND PER TRUST UNIT

Baytex calculates basic income per share and per trust unit based on the net income attributable to shareholders or unitholders and a weighted average number of shares or units outstanding during the period. Diluted income per share or trust unit amounts reflect the potential dilution that could occur if share rights or unit rights were exercised, share awards were converted and convertible debentures were converted. The treasury stock method is used to determine the dilutive effect of share rights or unit rights whereby any proceeds from the exercise of share rights or unit rights or other dilutive instruments and the amount of compensation expense, if any, attributed to future

26

services not yet recognized are assumed to be used to purchase common shares or trust units at the average market price during the periods.

			Years Ended December 31
			2011								2010
			Net income		Common shares (000's)			Net income per share			Net income		Trust units (000's)			Net income per unit
Net income – basic		$	217,432		115,960		$	1.88		$	231,615		111,450		$	2.08
Dilutive effect of share rights or unit rights			–		2,643						–		3,304
Dilutive effect of share awards			–		318						–		–
Conversion of convertible debentures			–		–						297		397
Net income – diluted		$	217,432		118,921		$	1.83		$	231,912		115,151		$	2.01

For the year ended December 31, 2011, nil share rights (year ended December 31, 2010 – 0.1 million unit rights) were excluded in calculating the weighted average number of diluted common shares outstanding as they were anti-dilutive.

19.  INCOME TAXES

The provision for (recovery of) income taxes has been computed as follows:

				Years Ended December 31
				2011			2010
Net income before income taxes			$	269,573		$	107,375
Expected income taxes at the statutory rate of 26.95% (2010 – 28.49%)(1)				72,650			30,591
Increase (decrease) in income taxes resulting from:
	Net income of the Trust prior to the Arrangement			–			(69,342	)
	Non-taxable portion of foreign exchange loss (gain)			1,580			(1,333	)
	Non-deductible (taxable) items			–			(2,854	)
	Share-based or unit-based compensation			9,120			26,838
	Effect of change in income tax rates			(9,902	)		11,132
	Effect of rate adjustments for foreign jurisdictions			(3,464	)		(3,730	)
	Effect of change in opening tax pool balances			(14,740	)		(5,740	)
	Effect of change in valuation allowance			(1,770	)		–
	Deferred credit(2)			–			(109,800	)
	Other			(1,333	)		(2	)
Deferred income tax expense (recovery)			$	52,141		$	(124,240	)

(1)

The change in statutory rate is related to a legislated reduction in the Canadian Federal corporate income tax rate and changes in the provincial apportionment of income.

(2)

In May 2010, Baytex acquired a number of private entities for use in its internal financing structure for approximately $38.0 million. The transaction resulted in the recognition of a future income tax asset of approximately $147.8 million with a corresponding deferred credit of $109.8 million recognized under previous GAAP, reflecting the difference between the future income tax asset recognized on the transaction and the cash paid. Under IFRS, the deferred credit is derecognized through net income as a deferred income tax recovery.

27

The components of the net deferred income tax liability are as follows:

As at				December 31, 2011			December 31, 2010			January 1, 2010
Deferred income tax liabilities:
	Petroleum and natural gas properties		$	(280,118	)	$	(224,923	)	$	(196,118	)
	Financial derivatives			–			(4,463	)		(9,432	)
	Partnership deferral			(86,019	)		(52,327	)		(2,921	)
	Other			(2,700	)		(5,025	)		(3,875	)
Deferred income tax assets:
	Asset retirement obligations			55,038			43,339			36,446
	Financial derivatives			7,362			7,870			1,789
	Non-capital losses			219,874			227,149			13,185
	Finance costs			3,479			1,867			1,996
Net deferred income tax liability(1)(2)			$	(83,084	)	$	(6,513	)	$	(158,930	)

(1)

Non-capital loss carry-forwards totaled $803.1 million (December 31, 2010 – $842.3 million, January 1, 2010 – $48.4 million) and expire from 2014 to 2031.

(2)

Baytex has recognized a net deferred tax asset of $10.3M relating to its US subsidiary. The Company has reviewed the reserves report, undeveloped land holdings and budget forecasts for this subsidiary and has determined that it is probable that future taxable profits will be sufficient to utilize the deductible temporary differences.

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

As at				January 1, 2010			Recognized in Net Income			Acquired in Business Combination			Other			December 31, 2010
Deferred income tax liabilities:
	Petroleum and natural gas properties		$	(196,118	)	$	(19,641	)	$	(9,164	)	$	–		$	(224,923	)
	Financial derivatives			(9,432	)		4,969			–			–			(4,463	)
	Partnership deferral			(2,921	)		(49,406	)		–			–			(52,327	)
	Other			(3,875	)		(1,009	)		–			(141	)		(5,025	)
Deferred income tax assets:
	Asset retirement obligations			36,446			6,341			552			–			43,339
	Financial derivatives			1,789			6,081			–			–			7,870
	Non-capital losses			13,185			175,964			38,000			–			227,149
	Finance costs			1,996			941			–			(1,070	)		1,867
Net deferred income tax liability			$	(158,930	)	$	124,240		$	29,388		$	(1,211	)	$	(6,513	)

As at				January 1, 2011			Recognized in Net Income			Acquired in Business Combination			Other			December 31, 2011
Deferred income tax liabilities:
	Petroleum and natural gas properties		$	(224,923	)	$	(25,724	)	$	(25,059	)	$	–		$	(275,706	)
	Financial derivatives			(4,463	)		4,463			–			–			–
	Partnership deferral			(52,327	)		(33,692	)		–			–			(86,019	)
	Other			(5,025	)		2,213			–			112			(2,700	)
Deferred income tax assets:
	Asset retirement obligations			43,339			11,182			517			–			55,038
	Financial derivatives			7,870			(508	)		–			–			7,362
	Non-capital losses			227,149			(11,687	)		–			–			215,462
	Finance costs			1,867			1,612			–			–			3,479
Net deferred income tax liability			$	(6,513	)	$	(52,141	)	$	(24,542	)	$	112		$	(83,084	)

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20.  REVENUES

			Years Ended December 31
			2011			2010
Petroleum and natural gas revenues		$	1,305,814		$	1,003,295
Royalty charges			(212,172	)		(170,844	)
Royalty income			3,000			1,841
Revenues, net of royalties		$	1,096,642		$	834,292

21.  FINANCING COSTS

Baytex incurred financing costs on its outstanding liabilities as follows:

			Years Ended December 31
			2011			2010
Bank loan and other		$	12,489		$	12,547
Long-term debt			22,935			14,198
Accretion on asset retirement obligations			6,185			5,862
Convertible debentures			–			320
Debt financing costs			3,002			1,643
Financing costs		$	44,611		$	34,570

22.  SUPPLEMENTAL INFORMATION

Change in Non-Cash Working Capital Items

				Years Ended December 31
				2011			2010
Trade and other receivables			$	(55,159	)	$	(14,638	)
Crude oil inventory				905			(418	)
Trade and other payables				40,992			(2,678	)
Foreign exchange				(180	)		74
			$	(13,442	)	$	(17,660	)
Changes in non-cash working capital related to:
	Operating activities		$	(10,889	)	$	(11,704	)
	Investing activities			(2,553	)		(5,956	)
			$	(13,442	)	$	(17,660	)

Foreign Exchange

			Years Ended December 31
			2011			2010
Unrealized foreign exchange loss (gain)		$	8,490		$	(8,999	)
Realized foreign exchange gain			(656	)		(149	)
Foreign exchange loss (gain)		$	7,834		$	(9,148	)

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Income Statement Presentation

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

			Years Ended December 31
			2011			2010
Production and operating		$	6,457		$	5,675
General and administrative			25,529			24,400
Total employee compensation costs		$	31,986		$	30,075

23.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, dividends or distributions payable to shareholders or unitholders, bank loan, financial derivatives, long-term debt and convertible debentures.

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. These estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction. The fair values of financial instruments, other than bank loan and long-term debt, are equal to their carrying amounts due to the short-term maturity of these instruments. The fair value of the bank loan approximates its carrying value as it is at a market rate of interest. The fair value of the long-term debt is based on the trading value of the debentures.

Fair Value of Financial Instruments

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

•

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

•

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

•

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

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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, 2011						December 31, 2010						January 1, 2010
As at				Carrying Value			Fair Value			Carrying Value			Fair Value			Carrying Value			Fair Value		Fair Value Measurement Hierarchy
Financial Assets
FVTPL
	Cash		$	7,847		$	7,847		$	–		$	–		$	10,177		$	10,177		Level 1
	Derivatives			11,059			11,059			16,543			16,543			31,994			31,994		Level 2
Total FVTPL			$	18,906		$	18,906		$	16,543		$	16,543		$	42,171		$	42,171
Loans and receivables
	Trade and other receivables		$	206,951		$	206,951		$	151,792		$	151,792		$	137,154		$	137,154		–
Total loans and receivables			$	206,951		$	206,951		$	151,792		$	151,792		$	137,154		$	137,154
Financial Liabilities
FVTPL
	Derivatives		$	(39,990	)	$	(39,990	)	$	(29,171	)	$	(29,171	)	$	(13,422	)	$	(13,422	)	Level 2
Total FVTPL			$	(39,990	)	$	(39,990	)	$	(29,171	)	$	(29,171	)	$	(13,422	)	$	(13,422	)
Other financial liabilities
	Trade and other payables		$	(225,831	)	$	(225,831	)	$	(183,314	)	$	(183,314	)	$	(186,516	)	$	(186,516	)	–
	Dividends or distributions payable to shareholders / unitholders			(25,936	)		(25,936	)		(22,742	)		(22,742	)		(19,674	)		(19,674	)	–
	Bank loan			(311,960	)		(311,960	)		(303,773	)		(303,773	)		(265,088	)		(265,088	)	–
	Convertible debentures			–			–			–			–			(7,736	)		(7,736	)	–
	Long-term debt			(297,731	)		(314,201	)		(146,893	)		(163,875	)		(146,498	)		(162,750	)	–
Total other financial liabilities			$	(861,458	)	$	(877,928	)	$	(656,722	)	$	(673,704	)	$	(625,512	)	$	(641,764	)

There were no transfers between Level 1 and 2 in the period.

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.

Foreign currency risk

Baytex is exposed to fluctuations in foreign currency as a result of the U.S. dollar portion of its bank loan, its Series B senior unsecured debentures, crude oil sales based on U.S. dollar indices and commodity contracts that are settled in U.S. dollars. The Company's net income and cash flow will therefore be impacted by fluctuations in foreign exchange rates.

To manage the impact of currency exchange rate fluctuations, the Company may enter into agreements to fix the Canada–U.S. exchange rate.

31

At December 31, 2011, the Company had in place the following currency derivative contracts:

Type		Period		Amount per month		Sales Price		Reference
Monthly forward spot sale		June 2010 to June 2012		US$1.00 million		1.0250		(1	)
Monthly forward spot sale		January 2011 to June 2012		US$3.00 million		1.0622		(1	)
Monthly forward spot sale		January 2011 to August 2012		US$1.00 million		1.0565		(1	)
Monthly forward spot sale		January 2011 to September 2012		US$1.50 million		1.0553		(1	)
Monthly forward spot sale		November 2011 to October 2013		US$1.00 million		1.0433		(1	)
Monthly forward spot sale		Calendar 2012		US$6.25 million		1.0084		(2	)
Monthly average rate forward		Calendar 2012		US$1.25 million		1.0209		(2	)
Monthly spot collar		Calendar 2012		US$0.75 million		0.9524 - 1.0503		(1	)
Monthly spot collar		Calendar 2012		US$0.25 million		1.0200 - 1.0700		(1	)
Monthly average collar		Calendar 2012		US$0.25 million		0.9700 - 1.0310		(1	)
Monthly average collar		Calendar 2012		US$0.50 million		0.9750 - 1.0305		(1	)
Monthly average collar		Calendar 2012		US$0.75 million		1.0225 - 1.0425		(1	)
Monthly average collar		Calendar 2012		US$0.25 million		1.0295 - 1.0545		(1	)
Monthly forward spot sale		Calendar 2013		US$4.50 million		1.0007		(2	)
Monthly average rate forward		Calendar 2013		US$0.25 million		1.0023		(1	)
Monthly average collar		Calendar 2013		US$0.25 million		0.9700 - 1.0310		(1	)

(1)

Actual contract rate (CAD/USD).

(2)

Based on the weighted average contract rates (CAD/USD).

The following table demonstrates the effect of movements in the Canadian – United States exchange rate on net income before income taxes and comprehensive income due to changes in the fair value of the currency swaps as well as gains and losses on the revaluation of U.S. dollar denominated monetary assets and liabilities at December 31, 2011.

$0.01 Increase (Decrease) in CAD/USD
			Exchange Rate
Loss (gain) on currency derivative contracts		$	1,648
Loss (gain) on other monetary assets/liabilities			2,954
Impact on net income before income taxes and comprehensive income		$	4,602

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, 2011

December 31, 2010

January 1, 2010

December 31, 2011

December 31, 2010

January 1, 2010

U.S. dollar denominated

US$107,138

US$72,663

US$67,389

US$402,979

US$230,878

US$198,690

Subsequent to December 31, 2011, Baytex added the following currency contracts:

Type		Period		Amount per month		Sales Price		Reference
Monthly spot collar		Calendar 2012		US$1.00 million		0.9800 - 1.0722		(1)
Monthly spot collar		Calendar 2012		US$1.00 million		0.9900 - 1.0720		(1)
Monthly spot collar		Calendar 2012		US$0.50 million		0.9900 - 1.0785		(1)
Monthly spot collar		June 2012 to December 2012		US$1.00 million		0.9800 - 1.0720		(1)
Monthly average rate forward		January 2012 to June 2012		US$1.00 million		1.0500		(1)(2)

(1)

Actual contract rate (CAD/USD).

(2)

Counterparty has the option to extend the term of the contract for an additional six months.

Interest rate risk

The Company's interest rate risk arises from its floating rate bank credit facilities. As at December 31, 2011, $312.0 million of the Company's total debt is subject to movements in floating interest rates. A change of 100 basis points in interest rates would impact net income before taxes for the year ended December 31, 2011 by

32

approximately $3.4 million. Baytex uses a combination of short-term and long-term debt to finance operations. The bank loan is typically at floating rates of interest and long-term debt is typically at fixed rates of interest.

As at December 31, 2011, Baytex had the following interest rate swap financial derivative contracts:

Type		Period		Notional Principal Amount		Fixed interest rate		Floating rate index
Swap – pay fixed, receive floating		September 27, 2011 to September 27, 2014		US$90.0 million		4.06%		3-month LIBOR
Swap – pay fixed, received floating		September 25, 2012 to September 25, 2014		US$90.0 million		4.39%		3-month LIBOR

When assessing the potential impact of forward interest rate changes on financial derivative contracts outstanding as at December 31, 2011, an increase of 100 basis points would decrease the unrealized loss at December 31, 2011 by $4.2 million, while a decrease of 100 basis points would increase the unrealized loss at December 31, 2011 by $3.3 million.

Commodity Price Risk

Baytex monitors and, when appropriate, utilizes financial derivative contracts or physical delivery contracts to manage the risk associated with changes in commodity prices. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors of Baytex. Under the Company's risk management policy, financial derivatives are not to be used for speculative purposes.

When assessing the potential impact of oil price changes on the financial derivative contracts outstanding as at December 31, 2011, a 10% increase would increase the unrealized loss at December 31, 2011 by $43.2 million, while a 10% decrease would decrease the unrealized loss at December 31, 2011 by $43.2 million.

When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2011, a 10% increase would increase the unrealized loss at December 31, 2011 by $1.1 million, while a 10% decrease would decrease the unrealized loss at December 31, 2011 by $1.0 million.

Financial Derivative Contracts

At December 31, 2011, Baytex had the following financial derivative contracts:

Oil		Period		Volume		Price/Unit(1)		Index
Fixed – Sell		January to March 2012		1,750 bbl/d		US$93.83		WTI
Fixed – Sell		January to June 2012		3,600 bbl/d		US$100.59		WTI
Time Spread		January to December 2012		500 bbl/d		Dec 2014 plus US$3.25		WTI
Time Spread		January to December 2012		500 bbl/d		Dec 2014 plus US$0.65		WTI
Fixed – Sell		Calendar 2012		7,450 bbl/d		US$93.44		WTI
Price collar		Calendar 2012		400 bbl/d		US$98.00 - 104.52		WTI
Price collar		Calendar 2012		300 bbl/d		US$100.00 - 104.90		WTI
Price collar		Calendar 2012		200 bbl/d		US$97.50 - 104.25		WTI
Price collar		Calendar 2012		300 bbl/d		US$100.00 - 105.92		WTI
Fixed – Buy		Calendar 2012		200 bbl/d		US$102.50		WTI
Fixed – Buy		January to June 2013		250 bbl/d		US$102.07		WTI
Fixed – Buy		July to December 2013		350 bbl/d		US$101.70		WTI
Fixed – Buy		Calendar 2014		380 bbl/d		US$101.06		WTI

(1)

Based on the weighted average price/unit for the remainder of the contract.

33

Natural Gas		Period		Volume		Price/Unit(1)		Index
Basis swap		January to June 2012		1,000 mmBtu/d		NYMEX less US$0.328		AECO
Basis swap		Calendar 2012		1,000 mmBtu/d		NYMEX less US$0.390		AECO
Basis swap		Calendar 2012		1,000 mmBtu/d		NYMEX less US$0.370		AECO
Basis swap		Calendar 2012		1,000 mmBtu/d		NYMEX less US$0.450		AECO
Basis swap		Calendar 2012		1,000 mmBtu/d		NYMEX less US$0.430		AECO
Basis swap		Calendar 2012		1,000 mmBtu/d		NYMEX less US$0.410		AECO
Basis swap		Calendar 2012		1,500 mmBtu/d		NYMEX less US$0.490		AECO
Basis swap		Calendar 2012		1,000 mmBtu/d		NYMEX less US$0.515		AECO
Basis swap		Calendar 2012		2,000 mmBtu/d		NYMEX less US$0.520		AECO
Basis swap		Calendar 2012		2,500 mmBtu/d		NYMEX less US$0.530		AECO
Sold call		Calendar 2012		6,000 mmBtu/d		US$5.25		NYMEX
Fixed – Sell		Calendar 2012		7,000 mmBtu/d		US$5.07		NYMEX

(1)

Based on the weighted average price/unit for the remainder of the contract.

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

			Years Ended December 31
			2011			2010
Realized loss (gain) on financial derivatives		$	1,864		$	(48,129	)
Unrealized loss on financial derivatives			16,166			43,312
Loss (gain) on financial derivatives		$	18,030		$	(4,817	)

Included in unrealized gain on financial derivatives is a loss of $5.1 million for the year ended December 31, 2010, respectively ($nil for year ended December 31, 2011) relating to the conversion feature of the convertible debentures.

Subsequent to December 31, 2011, Baytex added the following financial derivative contracts:

Oil		Period		Volume		Price/Unit(1)		Index
Fixed – Sell		January to June 2012(2)		500 bbl/d		US$108.00		WTI
Fixed – Sell		January to June 2012(2)		500 bbl/d		US$108.45		WTI
Fixed – Sell		January to December 2012		500 bbl/d		US$101.70		WTI
Fixed – Sell		March 2012		2,500 bbl/d		US$108.30		WTI
Fixed – Sell		March to December 2012		200 bbl/d		US$97.00-US$117.60		WTI
Fixed – Sell		March to December 2012		300 bbl/d		US$97.00-US$116.60		WTI
Fixed – Sell		April to June 2012		1,200 bbl/d		US$105.23		WTI
Fixed – Sell		April to June 2012(3)		500 bbl/d		US$107.70		WTI
Fixed – Sell		July to September 2012		300 bbl/d		US$107.38		WTI
Fixed – Sell		July to December 2012(2)		500 bbl/d		US$107.30		WTI
Fixed – Sell		July to December 2012(4)		500 bbl/d		US$108.80		WTI
Fixed – Sell		July to December 2012(4)		500 bbl/d		US$108.65		WTI
Fixed – Sell		July to December 2012(4)		500 bbl/d		US$107.80		WTI
Fixed – Sell		July to December 2012(4)		500 bbl/d		US$109.25		WTI

(1)

Based on the weighted average price/unit for the remainder of the contract.

(2)

Counterparty has the option to extend the term of the contract for an additional six months.

(3)

Counterparty has the option to extend the term of the contract for an additional six months on 250 bbl/d.

(4)

Counterparty has the option to increase the volume on the contract to 1,000 bbl/d.

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Physical Delivery Contracts

At December 31, 2011, the following physical delivery contracts were entered into and continue to be 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; therefore, no asset or liability has been recognized in the consolidated financial statements.

Heavy Oil		Period		Volume		Weighted Average Price/Unit(1)
WCS Blend		October 2011 to December 2014		2,000 bbl/d		WTI × 81.00%
WCS Blend		January to March 2012		4,000 bbl/d		WTI less US$11.78
WCS Blend		April to June 2012		1,500 bbl/d		WTI less US$13.42
WCS Blend		July to September 2012		500 bbl/d		WTI less US$15.00
WCS Blend		October to December 2012		500 bbl/d		WTI less US$18.00
WCS Blend		Calendar 2012		4,000 bbl/d		WTI less US$18.13
WCS Blend		January to June 2013		1,250 bbl/d		WTI × 80.00%
WCS Blend		January to June 2013		4,250 bbl/d		WTI less US$18.18
WCS Blend		July to December 2013		2,750 bbl/d		WTI × 80.00%
WCS Blend		July to December 2013		2,750 bbl/d		WTI less US$21.00

(1)

Based on the weighted average price/unit for the remainder of the contract.

Subsequent to December 31, 2011, Baytex added the following physical purchase contract:

Condensate (diluent)		Period		Volume		Price/Unit
Condensate		April 2012 to March 2013		640 bbl/d		WTI plus US$6.70

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 continuously monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements and opportunities to issue additional common shares. As at December 31, 2011, Baytex had available unused bank credit facilities in the amount of $388.0 million.

The timing of cash outflows (excluding interest) relating to financial liabilities is outlined in the table below:

			Total			Less than 1 year			1-3 years			3-5 years			Beyond 5 years
Trade and other payables		$	225,831		$	225,831		$	–		$	–		$	–
Dividends payable to shareholders			25,936			25,936			–			–			–
Bank loan(1)			311,960			–			311,960			–			–
Long-term debt(2)			302,550			–			–			150,000			152,550
		$	866,277		$	251,767		$	311,960		$	150,000		$	152,550

(1)

The bank loan is a three-year covenant-based revolving loan that is extendible annually, for a one, two or three year period (subject to a maximum three-year term at any time). Unless extended, the revolving period will end on June 14, 2014 with all amounts to be re-paid 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 and/or parental guarantees may be

35

obtained prior to the commencement of business with certain counterparties. Credit risk may also arise from financial derivative instruments. Due to the short term nature of accounts receivable, the maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company considers that all financial assets that are not impaired or past due for each of the reporting dates under review are of good credit quality. None of the Company's financial assets are secured by collateral.

Baytex considers all amounts greater than 90 days as past due. The average collection on petroleum and natural gas sales is 30 to 60 days from the date of the invoice. Should Baytex determine that the ultimate collection of a receivable is in doubt based on the processes for managing credit risk, the carrying amount of accounts receivable is reduced through the use of an allowance for doubtful accounts and the amount of the loss is recognized in net income. If the Company subsequently determines that an account is uncollectible, the account is written-off with a corresponding change to allowance for doubtful accounts. For the year ended December 31, 2011, $0.9 million was written-off in relation to balances already previously provided for (year ended December 31, 2010 – $0.5 million write-off).

Movements in allowance for doubtful accounts were as follows:

At January 1, 2010		$	(2,336	)
Foreign currency translation			4
Charge for the period			–
Amounts written off			479
Unused amounts reversed			–
At December 31, 2010		$	(1,853	)
Foreign currency translation			(2	)
Charge for the period			–
Amounts written off			896
Unused amounts reversed			–
At December 31, 2011		$	(959	)

Included in the allowance for doubtful accounts are individually impaired trade receivables of $0.3 million (December 31, 2010 – $0.2 million). As at December 31, 2011, accounts receivable that Baytex has deemed past due but not impaired is $4.5 million (December 31, 2010 – $4.6 million).

24.  OPERATING LEASES

At December 31, 2011, the future minimum lease payments under non-cancellable operating lease rentals are payable as follows:

			Total			Less than 1 year			1-5 years			Beyond 5 years
Gross operating leases		$	50,984		$	6,286		$	24,446		$	20,252
Operating subleases			(867	)		(533	)		(334	)		–
Net operating leases		$	50,117		$	5,753		$	24,112		$	20,252

Operating lease and sublease payments recognized as an expense during the year ended December 31, 2011 was $5.5 million (December 31, 2010 – $4.8 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 renewal options to extend its lease at the option of the lessee at lease payments based on market prices on one of its leased office buildings. None of the operating lease agreements contain purchase options or escalation clauses or any restrictions regarding dividends, further leases or additional debt.

36

25.  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.

Transaction with key management personnel (including directors):

			December 31, 2011			December 31, 2010
Short-term employee benefits		$	8,585		$	7,550
Share-based compensation			14,271			47,876
Total compensation for key management personnel		$	22,856		$	55,426

26.  COMMITMENTS AND CONTINGENCIES

At December 31, 2011 Baytex had processing and transportation obligations as summarized below:

			Total			Less than 1 year			1-2 years			2-3 years			3-4 years			4-5 years			Beyond 5 years
Processing and transportation agreements		$	5,198		$	3,238		$	1,881		$	79		$	–		$	–		$	–

At December 31, 2011 Baytex has $0.4 million of outstanding letters of credit ($nil – December 31, 2010 and January 1, 2010).

Baytex is engaged in litigation and claims arising in the normal course of operations, none of which could reasonably be expected to materially affect the Company's financial position or reported results of operations.

27.  GEOGRAPHIC INFORMATION

Baytex has operations principally in Canada and the United States. Baytex's entire operating activities are related to the acquisition, development and production of oil and natural gas. The following geographic information has been prepared by segregating the results into the geographic areas in which Baytex operates.

			Canada						United States						Total
			2011			2010			2011			2010			2011			2010
Years ended December 31
Gross revenues to external customers		$	1,267,589		$	986,041		$	41,225		$	19,095		$	1,308,814		$	1,005,136
Royalties			(200,786	)		(165,631	)		(11,386	)		(5,213	)		(212,172	)		(170,844	)
Revenue, net of royalties to external customers		$	1,066,803		$	820,410		$	29,839		$	13,882		$	1,096,642		$	834,292
As at December 31
Exploration and evaluation assets		$	76,592		$	58,233		$	53,182		$	54,849		$	129,774		$	113,082
Oil and gas properties			1,812,206			1,484,463			219,954			140,166			2,032,160			1,624,629
Other plant and equipment			24,965			27,270			268			280			25,233			27,550
Goodwill			37,755			37,755			–			–			37,755			37,755
Total non current assets		$	1,963,727		$	1,621,554		$	271,508		$	191,954		$	2,235,235		$	1,813,508

28.  CAPITAL DISCLOSURES

The Company's objectives when managing capital are to: (i) maintain financial flexibility in its capital structure; (ii) optimize its cost of capital at an acceptable level of risk; and (iii) preserve its ability to access capital to sustain the future development of the business through maintenance of investor, creditor and market confidence.

37

Baytex considers its capital structure to include total monetary debt and shareholders'/unitholders' equity. Total monetary debt is the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as deferred tax assets or liabilities and unrealized gains or losses on financial derivative contracts)) and the principal amount of long-term debt. At December 31, 2011, total monetary debt was $650.6 million.

The Company's financial strategy is designed to maintain a flexible capital structure consistent with the objectives stated above and to respond to changes in economic conditions and the risk characteristics of its underlying assets. Baytex is in compliance with all financial covenants relating to its senior unsecured debentures and the credit facilities of Baytex Energy. In order to manage its capital, the Company may adjust the amount of its dividends, adjust its level of capital spending, issue new shares or debt, or sell assets to reduce debt.

Baytex monitors capital based on the current and projected ratio of total monetary debt to funds from operations and the current and projected level of its undrawn bank credit facilities. Funds from operations is a financial term commonly used in the oil and gas industry. Funds from operations represents cash flow from operating activities before changes in non-cash working capital and other operating items. The Company's objectives are to maintain a total monetary debt to funds from operations ratio of less than two times and to have access to undrawn bank credit facilities of not less than $100 million. The total monetary debt to funds from operations ratio may increase beyond two times, and the undrawn credit facilities may decrease to below $100 million at certain times due to a number of factors, including acquisitions, changes to commodity prices and changes in the credit market. To facilitate management of the total monetary debt to funds from operations ratio and the level of undrawn bank credit facilities, the Company continuously monitors its funds from operations and evaluates its dividend policy and capital spending plans.

Although Baytex has changed its legal form to a corporation, the Company's financial objectives and strategy over the last two completed fiscal years as described above have remained substantially unchanged. These objectives and strategy are reviewed on an annual basis and Baytex believes its financial metrics are within acceptable limits pursuant to its capital management objectives.

29.  FIRST-TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS

The Company has prepared financial statements which comply with IFRS applicable for periods beginning on or after January 1, 2011 and the significant accounting policies meeting those requirements are described in note 3.

The general principle that should be applied on first-time adoption of IFRS is that standards in force at the first reporting date should be applied retrospectively. However, IFRS 1, "First-Time Adoption of International Financial Reporting Standards", provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas. The Company has taken all mandatory exceptions and the following optional exemptions:

•

IFRS 2, "Share-based Payment", has not been applied to any liabilities arising from share-based payment transactions that settled before January 1, 2010.



•

Deemed costs of oil and gas assets are based on exploration and evaluation assets at the amount determined under previous GAAP and assets in the development or production phases at the amount determined for the cost centre under previous GAAP, allocated to the cost centres' underlying assets pro rata using reserve values as of January 1, 2010.



•

IFRS Interpretations Committee ("IFRIC") 4, "Determining whether an Arrangement contains a Lease", transition rules have been applied that allow determination of whether any existing arrangement at January 1, 2010 contains a lease on the basis of the facts and circumstances existing at that date.



•

IFRS 3, "Business Combinations", has not been applied to acquisitions of subsidiaries or of interests in associates and joint ventures that occurred before January 1, 2010, the Company's date of transition.



•

Cumulative translation differences are deemed to be $nil at January 1, 2010 and deficit adjusted by the same amount.



•

Asset retirement liabilities included in the cost of property, plant and equipment are measured as at January 1, 2010 in accordance with IAS 37, "Provisions, Contingent Liabilities and Contingent Assets", and the difference between that amount and the carrying amount of those liabilities at January 1, 2010 determined under previous GAAP are recognized directly in deficit.



•

IAS 23, "Borrowing Costs", transition rules have been applied that allow application of the standard to borrowing costs related to qualifying assets for which the commencement date for capitalization is on or after the effective date, January 1, 2010.

38

Baytex Energy Corp.
Consolidated Statements of Income and Comprehensive Income – IFRS
(thousands of Canadian dollars)

					Year Ended December 31, 2010
		Note			Previous GAAP			Effect of transition to IFRS			IFRS
Revenues
Petroleum and natural gas		F, N		$	1,005,136		$	(170,844	)	$	834,292
Royalties		N			(162,332	)		162,332			–
Gain on financial derivatives					9,935			(9,935	)		–
					852,739			(18,447	)		834,292
Expenses
Exploration and evaluation		B			–			24,502			24,502
Production and operating					171,740			(36	)		171,704
Transportation and blending					188,591			–			188,591
General and administrative					39,774			973			40,747
Unit-based compensation		J			8,344			85,855			94,199
Financing costs		H, I			32,828			1,742			34,570
Gain on divestitures of oil and gas properties		C			–			(16,227	)		(16,227	)
Gain on financial derivatives		G			–			(4,817	)		(4,817	)
Foreign exchange gain					(9,148	)		–			(9,148	)
Depletion and depreciation		D			266,527			(63,731	)		202,796
					698,656			28,261			726,917
Net income before income taxes					154,083			(46,708	)		107,375
Income tax expense (recovery)
Current		F			8,512			(8,512	)		–
Deferred		L, M			(32,060	)		(92,180	)		(124,240	)
					(23,548	)		(100,692	)		(124,240	)
Net income attributable to unitholders				$	177,631		$	53,984		$	231,615
Other comprehensive income (loss)
Foreign currency translation adjustment					(10,708	)		385			(10,323	)
Comprehensive income				$	166,923		$	54,369		$	221,292

39

Baytex Energy Corp.
Consolidated Statements of Financial Position – IFRS
(thousands of Canadian dollars) (unaudited)

As at						December 31, 2010									January 1, 2010
			Note			Previous GAAP			Effect of transition to IFRS			IFRS			Previous GAAP			Effect of transition to IFRS			IFRS
Assets
Current assets
	Cash		O		$	–		$	–		$	–		$	10,177		$	–		$	10,177
	Trade and other receivables		A			151,792			–			151,792			137,154			–			137,154
	Crude oil inventory					1,802			–			1,802			1,384			–			1,384
	Future income tax asset		A,M			5,480			(5,480	)		–			1,371			(1,371	)		–
	Financial derivatives					13,921			–			13,921			29,453			–			29,453
						172,995			(5,480	)		167,515			179,539			(1,371	)		178,168
Non-current assets
	Deferred income tax asset		A,M			150,190			(142,320	)		7,870			418			1,371			1,789
	Financial derivatives					2,622			–			2,622			2,541			–			2,541
	Exploration and evaluation assets		B			–			113,082			113,082			–			124,621			124,621
	Oil and gas properties		A,C,D,I			1,683,650			(59,021	)		1,624,629			1,663,752			(151,717	)		1,512,035
	Other plant and equipment		E			–			27,550			27,550			–			27,096			27,096
	Goodwill					37,755			–			37,755			37,755			–			37,755
					$	2,047,212		$	(66,189	)	$	1,981,023		$	1,884,005		$	–		$	1,884,005
Liabilities
Current liabilities
	Trade and other payables		A		$	179,269		$	4,045		$	183,314		$	180,493		$	6,023		$	186,516
	Distributions payable to unitholders					22,742			–			22,742			19,674			–			19,674
	Bank loan					–			–			–			265,088			–			265,088
	Convertible debentures					–			–			–			7,736			–			7,736
	Future income tax liability		A,M			3,756			(3,756	)		–			8,683			(8,683	)		–
	Financial derivatives		G			20,312			–			20,312			4,650			7,354			12,004
						226,079			289			226,368			486,324			4,694			491,018
Non-current liabilities
	Bank loan					303,773			–			303,773			–			–			–
	Long-term debt		H			150,000			(3,107	)		146,893			150,000			(3,502	)		146,498
	Deferred credit		L			109,800			(109,800	)		–			–			–			–
	Asset retirement obligations		I			52,373			117,238			169,611			54,593			87,276			141,869
	Unit-based payment liability		J			–			–			–			–			91,559			91,559
	Deferred income tax liability		A,M			167,302			(152,919	)		14,383			179,673			(18,954	)		160,719
	Financial derivatives					8,859			–			8,859			1,418			–			1,418
						1,018,186			(148,299	)		869,887			872,008			161,073			1,033,081
Shareholders'/Unitholders' Equity
Shareholders' capital			J			1,390,034			94,301			1,484,335			–			–			–
Unitholders' capital			G,J			–			–			–			1,295,931			35,230			1,331,161
Conversion feature of convertible debentures			G			–			–			–			374			(374	)		–
Contributed surplus			J			20,131			108,998			129,129			20,371			(20,371	)		–
Accumulated other comprehensive (loss) income			K			(14,607	)		4,284			(10,323	)		(3,899	)		3,899			–
Deficit						(366,532	)		(125,473	)		(492,005	)		(300,780	)		(179,457	)		(480,237	)
						1,029,026			82,110			1,111,136			1,011,997			(161,073	)		850,924
					$	2,047,212		$	(66,189	)	$	1,981,023		$	1,884,005		$	–		$	1,884,005

40

A)    Presentation Differences

Certain presentation differences between previous GAAP and IFRS have no impact on reported comprehensive income or total equity.

Some line items are described differently (renamed) under IFRS compared to previous GAAP. These line items are as follows (with previous GAAP descriptions in brackets):

•

Trade and other receivables (Accounts receivable)



•

Oil and gas properties (Petroleum and natural gas properties)



•

Deferred income tax asset/liability (Future income tax asset/liability)



•

Trade and other payables (Accounts payable and accrued liabilities)

B)    Exploration and Evaluation

Under previous GAAP, petroleum and natural gas properties included certain exploration and evaluation expenditures incurred within a country-by-country cost centre. Under IFRS, such exploration and evaluation expenditures are recognized as tangible or intangible based on their nature and subject to technical, commercial and management review quarterly to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are expensed.

Exploration and evaluation assets at January 1, 2010 were deemed to be $124.6 million, being the amount recorded as the undeveloped land balance under previous GAAP. This has resulted in the reclassification from property, plant and equipment to intangible exploration assets of $124.6 million in the opening IFRS statement of financial position.

During the year ended December 31, 2010, Baytex expensed $18.9 million of exploration and evaluation assets related to lease expiries and $5.6 million in direct exploration costs. For the year ended December 31, 2010, Baytex had exploration and evaluation capital expenditures of $37.4 million, corporate acquisitions of $2.5 million, divestitures of $0.1 million, transfers to oil and gas properties of $29.1 million, transfers to expense related to lease expiries of $18.9 million and a decrease due to foreign currency translation of $3.3 million.

C)    Oil and Gas Properties

IFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at its time of adoption, to measure exploration and evaluation assets at the amount determined under the entity's previous GAAP and to measure oil and gas assets in the development and production phases by allocating the amount determined under the entity's previous GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of that date. The Company has allocated the amount recognized under previous GAAP as at January 1, 2010 using reserve values to the assets at an area level. This has resulted in oil and gas properties of $1,512.0 million in the opening IFRS statement of financial position.

Previous GAAP utilized full cost accounting whereby gains and losses were not recognized upon the divestiture of oil and gas assets unless such a divestiture would alter the rate of depletion by 20% or more. Under IFRS, gains and losses are recognized based on the difference between the net proceeds from the divestiture and the carrying value of the asset disposed. For the year ended December 31, 2010, a gain of $16.2 million was recognized relating to a divestiture of oil and gas assets.

D)    Depletion

Upon transition to IFRS, the Company adopted a policy of depleting oil and gas properties on a "units of production" basis over proved plus probable reserves on an area basis rather than a cost pool basis under previous GAAP. The depletion policy under previous GAAP was units of production over proved reserves on a country basis.

There is no impact to depletion on transition to IFRS at January 1, 2010. For the year ended December 31, 2010, this change resulted in a decrease in depletion expense of $67.4 million with a corresponding increase in oil and gas properties.

41

E)    Other Plant and Equipment

Contains amounts previously grouped within petroleum and natural gas properties.

F)     Current Income Tax Expense

Under previous GAAP, Saskatchewan resource surcharge expense was classified as current income tax. Under IFRS, Saskatchewan resource surcharge is considered a royalty and is netted against petroleum and natural gas revenues. Saskatchewan resource surcharge for the year ended December 31, 2010 netted in revenues is $8.5 million.

G)    Conversion Feature of Convertible Debentures

Under previous GAAP, the convertible debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders' or shareholders' equity. The debt portion accreted up to the principal balance at maturity. If the debentures were converted to trust units, a portion of the value of the conversion feature under unitholders' equity was reclassified to unitholders' capital along with principal amounts converted.

Under IFRS, the conversion feature of the convertible debentures has been classified as a financial derivative liability. The financial derivative liability requires a fair value method of accounting and changes in the fair value of the derivative liability are recognized in the statements of income and comprehensive income. If the debentures were converted to trust units, the fair value of the conversion feature under financial derivative liability was reclassified to unitholders'/shareholders' capital along with the principal amounts converted. The impact on adoption to IFRS at January 1, 2010 was an additional liability of $7.4 million, an increase of $33.4 million in unitholders' capital with a corresponding $40.4 million charge to deficit and a decrease of $0.4 million in the conversion feature of convertible debentures.

Under IFRS, for the year ended December 31, 2010, the increase in unitholders'/shareholders' equity of $12.1 million and the increase of $0.4 million in conversion feature of convertible debentures had a corresponding decrease in the $7.4 million liability recorded at January 1, 2010 and a $5.1 million decrease in gain on financial derivatives in net income.

H)    Long-term Debt

Under previous GAAP, the Company's policy was to immediately expense transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability. Under IFRS, the transaction costs for financial instruments carried at amortized cost are included in the calculation of the effective interest rate and effectively amortized through net income over the term of the instrument. Baytex's $150.0 million principal amount of Series A senior unsecured debentures are classified as other financial liabilities. Under IFRS, the senior unsecured debentures are carried at amortized cost, net of the associated $3.6 million transaction costs, which will accrete up to the principal balance at maturity using the effective interest rate. Under IFRS, a reduction in the long-term debt liability of $3.5 million had a corresponding decrease in deficit at January 1, 2010. Accretion expense included in finance costs for the year ended December 31, 2010 is $0.4 million.

I)      Asset Retirement Obligations

Under IFRS, Baytex uses a risk free interest rate to discount the estimated fair value of its asset retirement obligations associated with the related oil and gas properties. Under previous GAAP, the Company used a credit-adjusted risk free interest rate. A lower discount rate under IFRS increases the asset retirement obligations. In addition, under IFRS the asset retirement obligations are measured using the best estimate of the expenditures to be incurred and current discount rates at each remeasurement date with the corresponding adjustment to the cost of the related oil and gas properties. Existing liabilities under previous GAAP are not remeasured using current discount rates.

Under previous GAAP, the Company's asset retirement obligations were recorded using the credit-adjusted risk free rate of 8.0%. Under IFRS, the Company's asset retirement obligations are recorded using the risk free rate of 3.5% at December 31, 2010 (4.0% at January 1, 2010 and 3.5% at December 31, 2010). Under IFRS, an additional liability

42

of $87.3 million was charged to deficit at January 1, 2010. At December 31, 2010, excluding the January 1, 2010 adjustment, the lower discount rates used resulted in an additional liability of $30.1 million and a resulting $29.2 million increase to the related oil and gas properties. At December 31, 2010, excluding the January 1, 2010 adjustment, the lower discount rates used resulted in an additional liability of $30.0 million and a resulting $28.7 million increase to the related oil and gas properties.

For the year ended December 31, 2010, the $4.5 million accretion expense on asset retirement obligations under previous GAAP was reclassified to finance costs and an additional accretion expense on asset retirement obligations of $1.4 million has been recognized in net income under IFRS.

J)     Unit-based Compensation

Under previous GAAP, the obligation associated with the Unit Rights Plan is considered to be equity-based and the related unit-based compensation was calculated using the binomial-lattice model to estimate the fair value of the outstanding unit rights at grant date. The exercise of unit rights was recorded as an increase in unitholders' capital with a corresponding reduction in contributed surplus.

Under IFRS, prior to the conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability is remeasured at each reporting date and at settlement date. Any changes in fair value are recognized in net income for the period. For periods prior to the conversion to a corporation remeasuring the fair value of the obligation each reporting period will increase or decrease the unit-based payment liability, unitholders' capital and compensation expense recognized. Upon conversion to a corporation, the outstanding Unit Rights Plan was modified to become the new Share Rights Plan, effectively changing the related classification from liability-settled to equity-settled. The expense recognized from the date of the plan modification over the remainder of the vesting period is determined based on the fair value of the reclassified unit rights at the date of the modification. Upon transition of IFRS at January 1, 2010, an additional unit-based payment liability of $91.6 million and a decrease of $20.4 million in contributed surplus resulted in a corresponding $71.2 million charge to deficit.

Under IFRS, in addition to the January 1, 2010 adjustments discussed above, at December 31, 2010 immediately prior to the conversion to a corporation, the remeasurement of the liability at reporting date and at settlement date resulted in the recognition of an additional unit-based compensation expense of $85.9 million, with a corresponding decrease of $0.3 million in contributed surplus, an increase of $48.0 million in shareholders'/unitholders' equity and an increase of $37.6 million in unit-based payment liability.

K)    Accumulated Other Comprehensive Loss

Under previous GAAP, amounts are composed entirely of currency translation adjustments on self-sustaining foreign operations. Under IFRS, the Company has elected to deem cumulative currency translation differences as $nil at January 1, 2010. At January 1, 2010, this has resulted in a decrease in accumulated other comprehensive loss with a corresponding increase in deficit of $3.9 million.

L)     Deferred Credit

Baytex acquired several private entities to be used in its internal financing structure. Under previous GAAP, the excess of amounts assigned to the acquired assets over the consideration paid is classified as a deferred credit. Under IFRS, the deferred credit is derecognized through net income as a deferred income tax recovery. For the year ended December 31, 2010, a deferred income tax recovery of $109.8 million was recorded in net income for amounts previously recognized as a deferred credit.

M)   Deferred Income Taxes

Under IFRS, deferred income taxes are required to be presented as non-current. Upon transition to IFRS, the Company recognized a $27.6 million reduction in the net deferred income tax liability entirely resulting from the tax impact of the adjustments from previous GAAP to IFRS with a decrease to deficit of $25.8 million and a decrease to unitholders' capital of $1.8 million.

43

For the year ended December 31, 2010, the application of the IFRS adjustments resulted in a $92.2 million increase to the Company's deferred income tax recovery. The increase in deferred income tax recovery is due to the deferred credit derecognized through net income under IFRS.

Under IFRS, taxable and deductible temporary differences related to the legal entity of the Trust must be measured using the highest marginal personal tax rate of 39%, as opposed to the corporate tax rates used under previous GAAP, resulting in an increase to the deferred income tax asset of $5.1 million at January 1, 2010. Upon conversion to a dividend paying corporation on December 31, 2010, the total deferred income tax asset related to the Trust was adjusted to the corporate tax rate of approximately 25% and derecognized through net income on December 31, 2010.

N)    Royalties

Under previous GAAP, gross petroleum and natural gas revenues and royalties were presented separately. Under IFRS, petroleum and natural gas revenues are presented net of crown, third-party, gross overriding royalties and production taxes.

O)    Statements of Cash Flows

With the exception of a $28.5 million interest paid reclass from operating activities to financing activities for the year ended December 31, 2010, the transition from previous GAAP to IFRS had no material effect on the reported cash flows generated by the Company.

30.  CONSOLIDATING FINANCIAL INFORMATION – BASE SHELF PROSPECTUS

On August 4, 2011, Baytex filed a Short Form Base Shelf Prospectus with the securities regulatory authorities in each of the provinces of Canada (other than Québec) and a Registration Statement with the United States Securities and Exchange Commission (collectively, the "Shelf Prospectus"). The Shelf Prospectus allows Baytex to offer and issue common shares, subscription receipts, warrants, options and debt securities by way of one or more prospectus supplements at any time during the 25-month period that the Shelf Prospectus remains in place. The securities may be issued from time to time, at the discretion of Baytex, with an aggregate offering amount not to exceed $500 million (Canadian).

Any debt securities issued by Baytex pursuant to the Shelf Prospectus will be guaranteed by all of its direct and indirect wholly-owned material subsidiaries (the "Guarantor Subsidiaries"). The guarantees of the Guarantor Subsidiaries are full and unconditional and joint and several. These guarantees may in turn be guaranteed by Baytex. Other than investments in its subsidiaries, Baytex has no independent assets or operations.

Pursuant to the credit agreement governing Baytex Energy's credit facilities, Baytex Energy and its subsidiaries are prohibited from paying dividends to their shareholders that would have, or would reasonably be expected to have, a material adverse effect or would adversely affect or impair the ability or capacity of Baytex Energy to pay or fulfill any of its obligations under the credit agreement. In addition, Baytex Energy may not permit any of its subsidiaries to pay any dividends during the continuance of a default or event of default under the credit agreement.

The following tables present consolidating financial information as at December 31, 2011, December 31, 2010 and January 1, 2010 and for the years ended December 31, 2011 and 2010 for: 1) Baytex, on a stand-alone basis, 2) Guarantor subsidiaries, on a stand-alone basis, 3) non-guarantor subsidiaries, on a stand-alone basis and 4) Baytex, on a consolidated basis.

44

(thousands of Canadian dollars)			Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated
As at December 31, 2011
Current assets		$	351		$	225,850		$	374		$	–		$	226,575
Intercompany advances and investments			1,753,047			(515,492	)		72,787			(1,310,342	)		–
Non-current assets			2,435			2,232,800			–			–			2,235,235
Current liabilities			34,502			242,303			167			–			276,972
Bank loan and long-term debt			297,731			311,960			–			–			609,691
Asset retirement obligation and other non-current liabilities		$	–		$	368,413		$	–		$	–		$	368,413
As at December 31, 2010
Current assets		$	15		$	167,473		$	27		$	–		$	167,515
Intercompany advances and investments			1,687,861			(456,094	)		72,318			(1,304,085	)		–
Non-current assets			1,138			1,812,370			–			–			1,813,508
Current liabilities			27,539			198,788			41			–			226,368
Bank loan and long-term debt			146,893			303,773			–			–			450,666
Asset retirement obligation and other non-current liabilities		$	–		$	192,853		$	–		$	–		$	192,853
As at January 1, 2010
Current assets		$	412		$	177,608		$	148		$	–		$	178,168
Intercompany advances and investments			1,522,661			(1,522,596	)		63,892			(63,957	)		–
Non-current assets			42,515			1,663,322			–			–			1,705,837
Current liabilities			39,577			451,357			84			–			491,018
Bank loan and long-term debt			146,498			–			–			–			146,498
Asset retirement obligation and other non-current liabilities		$	–		$	395,565		$	–		$	–		$	395,565

45

(thousands of Canadian dollars)			Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated
Year ended December 31, 2011
Revenues, net of royalties		$	22,012		$	1,098,415		$	9,649		$	(33,434	)	$	1,096,642
Production, operation and exploration			–			223,042			–			–			223,042
Transportation and blending			–			249,850			–			–			249,850
General, administrative and share-based compensation			1,596			72,842			257			(1,515	)		73,180
Financing, derivatives, foreign exchange and other gains/losses			27,497			36,999			(48	)		(31,919	)		32,529
Depletion and depreciation			–			248,468			–			–			248,468
Deferred income tax (recovery) expense			(1,298	)		53,439			–			–			52,141
Net (loss) income		$	(5,783	)	$	213,775		$	9,440		$	–		$	217,432

(thousands of Canadian dollars)			Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated
Year ended December 31, 2010
Revenues, net of royalties		$	262,138		$	800,887		$	10,537		$	(239,270	)	$	834,292
Production, operation and exploration			–			196,206			–			–			196,206
Transportation and blending			–			188,591			–			–			188,591
General, administrative and unit-based compensation			1,500			134,598			348			(1,500	)		134,946
Financing, derivatives, foreign exchange and other gains/losses			(15,270	)		257,405			13			(237,770	)		4,378
Depletion and depreciation			4,811			197,985			–			–			202,796
Deferred income tax expense (recovery)			13,495			(137,739	)		4			–			(124,240	)
Net income (loss)		$	257,602		$	(36,159	)	$	10,172		$	–		$	231,615

46

(thousands of Canadian dollars)			Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated
Year ended December 31, 2011
Cash provided by (used in):
Operating activities		$	56,926		$	514,581		$	353		$	–		$	571,860
Payment of dividends			(204,308	)		9,004			(9,004	)		–			(204,308	)
Increase in bank loan			–			4,290			–			–			4,290
Increase (decrease) in intercompany loans			(18,008	)		110,041			(92,033	)		–			–
Proceeds from issuance of long-term debt			145,810			–			–			–			145,810
Increase in investments						(90,649	)					90,649			–
Increase in equity			45,048			–			90,649			(90,649	)		45,048
Interest paid			(25,468	)		(19,297	)		10,035			–			(34,730	)
Financing activities			(56,926	)		13,389			(353	)		–			(43,890	)
Additions to exploration and evaluation assets			–			(9,104	)		–			–			(9,104	)
Additions to oil and gas properties			–			(358,744	)		–			–			(358,744	)
Property acquisitions			–			(76,164	)		–			–			(76,164	)
Corporate acquisitions			–			(120,006	)		–			–			(120,006	)
Proceeds from divestitures			–			47,396			–			–			47,396
Additions to other plant and equipment, net of disposals			–			(1,252	)		–			–			(1,252	)
Acquisitions of financing entities			–			–			–			–			–
Change in non-cash working capital			–			(2,553	)		–			–			(2,553	)
Investing activities			–			(520,427	)		–			–			(520,427	)
Impact of foreign currency translation on cash balances		$	–		$	304		$	–		$	–		$	304

47

(thousands of Canadian dollars)			Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated
Year ended December 31, 2010
Cash provided by (used in):
Operating activities		$	227,665		$	224,483		$	9,258		$	–		$	461,406
Payment of distributions			(188,615	)		10,455			(10,455	)		–			(188,615	)
Increase in bank loan			–			48,045			–			–			48,045
Increase (decrease) in intercompany loans			(50,915	)		55,324			(4,409	)		–			–
Increase in investments			–			(2,653	)		–			2,653			–
Repayment of convertible debentures			(341	)		–			–			–			(341	)
Increase in equity			26,021			–			2,653			(2,653	)		26,021
Interest paid			(14,180	)		(17,124	)		2,805			–			(28,499	)
Financing activities			(228,030	)		94,047			(9,406	)		–			(143,389	)
Additions to exploration and evaluation assets			–			(37,411	)		–			–			(37,411	)
Additions to oil and gas properties			–			(194,208	)		–			–			(194,208	)
Property acquisitions			–			(22,412	)		–			–			(22,412	)
Corporate acquisitions			–			(40,314	)		–			–			(40,314	)
Proceeds from divestitures			–			19,033									19,033
Additions to other plant and equipment, net of disposals			–			(8,237	)		–			–			(8,237	)
Acquisitions of financing entities			–			(38,000	)		–			–			(38,000	)
Change in non-cash working capital			–			(5,956	)		–			–			(5,956	)
Investing activities			–			(327,505	)		–			–			(327,505	)
Impact of foreign currency translation on cash balances		$	–		$	(689	)	$	–		$	–		$	(689	)

48