Exhibit 99.2

Consolidated Financial Statements of                         

BAYTEX ENERGY TRUST

December 31, 2008

1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Baytex Energy Trust is responsible for establishing and maintaining adequate internal control over financial reporting over the Trust. 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, 2008, 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 the financial statement preparation and presentation.

The effectiveness of the Trust’s internal control over financial reporting as of December 31, 2008 has been audited by Deloitte & Touche LLP, the Trust’s Independent Registered Chartered Accountants, who also audited the Trust’s Consolidated Financial Statements for the year ended December 31, 2008.

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS

Management, in accordance with Canadian generally accepted accounting principles, has prepared the accompanying consolidated financial statements of Baytex Energy Trust.  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 Trust’s unitholders 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 Canadian generally accepted accounting principles.

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 the external auditors and reviews their fees.  The external auditors have access to the Audit Committee without the presence of management.

 (signed) “Anthony W. Marino”    Anthony W. Marino   President and Chief Executive Officer  Baytex Energy Ltd.     March 16, 2009 (signed) “W. Derek Aylesworth” W. Derek Aylesworth, CA Chief Financial Officer Baytex Energy Ltd.

2

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors of Baytex Energy Ltd. and

Unitholders of Baytex Energy Trust:

We have audited the accompanying consolidated balance sheets of Baytex Energy Trust and subsidiaries (the “Trust”) as at December 31, 2008 and 2007, and the related consolidated statements of income and comprehensive income, deficit, and cash flows for the years then ended.  These financial statements are the responsibility of the Trust's management.  Our responsibility is to express an opinion on these 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).  These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Baytex Energy Trust and subsidiaries as ofDecember 31, 2008 and 2007 and the results of their operations and their cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

On March 16, 2009, we reported separately to the Unitholders of Baytex Energy Trust on our audit, conducted in accordance with Canadian generally accepted auditing standards, of the consolidated financial statements for the same periods, prepared in accordance with Canadian generally accepted accounting principles but which excluded Note 19, Differences Between Canadian and United States Generally Accepted Accounting Principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust's internal control over financial reporting as of December 31, 2008, based onthe criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2009 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

(signed) “Deloitte & Touche LLP”                                                                           

Independent Registered Chartered Accountants

Calgary, Canada

March 16, 2009

COMMENTS BY INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS ON CANADA-UNITED STATES OF AMERICA REPORTING DIFFERENCE

The standards of the Public Company Accounting Oversight Board  (United States) require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have a material effect on the comparability of the Trust’s financial statements, such as the changes described in Notes 3 and 19 to the consolidated financial statements.  Although we conducted our audits in accordance with both Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), our report to the Board of Directors of Baytex Energy Ltd. and Unitholders of Baytex Energy Trust, dated March 16, 2009, is expressed in accordance with Canadian reporting standards which do not require a reference to such changes in accounting principles in the auditors’ report when the changes are properly accounted for and adequately disclosed in the financial statements.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants

Calgary, Canada

March 16, 2009

3

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors of Baytex Energy Ltd. and Unitholders of Baytex Energy Trust:

We have audited the internal control over financial reporting of Baytex Energy Trust and subsidiaries (the “Trust”)as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Trust'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 Trust'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 Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, 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, 2008 of the Trust and our report dated March 16, 2009 expressed an unqualified opinion on those financial statements and included a separate report titled Comments by Independent Registered Chartered Accountants on Canada-United States of America Reporting Difference referring to changes in accounting principles.

(signed)  “Deloitte & Touche LLP”

Independent Registered Chartered Accountants

Calgary, Canada

March 16, 2009

4

Baytex Energy Trust
Consolidated Balance Sheets
As at December 31	2008			2007
(thousands of Canadian dollars)
ASSETS
Current assets
Accounts receivable	$	87,551		$	105,176
Crude oil inventory		332			5,997
Financial instruments (note 16)		85,678			-
Future tax asset (note 14)		-			11,525
		173,561			122,698
Petroleum and natural gas properties (note 5)		1,601,017			1,246,697
Goodwill		37,755			37,755
	$	1,812,333		$	1,407,150
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	164,279		$	104,318
Distributions payable to unitholders		17,583			15,217
Bank loan (note 6)		208,482			241,748
Financial instruments (note 16)		-			34,239
Future tax liability (note 14)		25,358			-
		415,702			395,522
Long-term debt (note 7)		217,273			173,854
Convertible debentures (note 8)		10,195			16,150
Asset retirement obligations (note 9)		49,351			45,113
Deferred obligations		74			113
Future tax liability (note 14)		192,411			153,943
		885,006			784,695
Non-controlling interest (note 11)		-			21,235
UNITHOLDERS’ EQUITY
Unitholders’ capital (note 10)		1,129,909			821,624
Conversion feature of debentures (note 8)		498			796
Contributed surplus (note 12)		21,234			18,527
Deficit		(224,314	)		(239,727	)
		927,327			601,220
	$	1,812,333		$	1,407,150

Commitments and contingencies (note 17)

   

See accompanying notes to the consolidated financial statements.

On behalf of the Board
(signed) “Naveen Dargan”	(signed) “Gregory K. Melchin”
Naveen Dargan	Gregory K. Melchin
Director, Baytex Energy Ltd.	Director, Baytex Energy Ltd.

5

Baytex Energy Trust
Consolidated Statements of Income and Comprehensive Income
Years Ended December 31	2008			2007
(thousands of Canadian dollars)
Revenue
Petroleum and natural gas	$	1,159,718		$	745,885
Royalties		(207,522	)		(102,805	)
Gain (loss) on financial instruments (note 16)		59,816			(34,484	)
		1,012,012			608,596
Expenses
Operating		172,471			134,696
Transportation and blending		218,706			155,754
General and administrative		29,603			23,565
Unit-based compensation (note 12)		7,812			7,986
Interest (note 7)		32,962			35,162
Foreign exchange loss (gain) (note 15)		37,746			(32,414	)
Depletion, depreciation and accretion		223,900			189,512
		723,200			514,261
Income before taxes and non-controlling interest		288,812			94,335
Tax expense (recovery) (note 14)
Current expense		10,177			6,713
Future expense (recovery)		15,383			(49,369	)
		25,560			(42,656	)
Income before non-controlling interest		263,252			136,991
Non-controlling interest (note 11)		(3,358	)		(4,131	)
Net income / Comprehensive income	$	259,894		$	132,860

Consolidated Statements of Deficit
Years Ended December 31,		2008			2007
(thousands of Canadian dollars, except per unit data)
Deficit, beginning of year	$	(239,727	)	$	(198,520	)
Net income		259,894			132,860
Distributions to unitholders		(244,481	)		(174,067	)
Deficit, end of year	$	(224,314	)	$	(239,727	)
Net income per trust unit (note 13)
Basic	$	2.83		$	1.66
Diluted	$	2.74		$	1.60
See accompanying notes to the consolidated financial statements.

6

Baytex Energy Trust
Consolidated Statements of Cash Flows
Years Ended December 31,	2008			2007
(thousands of Canadian dollars)
CASH PROVIDED BY (USED IN):
Operating activities
Net income	$	259,894		$	132,860
Items not affecting cash:
Unit-based compensation (note 12)		7,812			7,986
Unrealized foreign exchange loss (gain) (note 15)		41,712			(32,574	)
Depletion, depreciation, and accretion		223,900			189,512
Accretion on debentures and notes (notes 7 & 8)		1,681			2,164
Unrealized (gain) loss on financial instruments (note 16)		(119,917	)		31,320
Future tax expense (recovery)		15,383			(49,369	)
Non-controlling interest (note 11)		3,358			4,131
		433,823			286,030
Change in non-cash working capital (note 15)		38,896			5,140
Asset retirement expenditures (note 9)		(1,443	)		(2,442	)
Decrease in deferred obligations		(39	)		(2,278	)
		471,237			286,450
Financing activities
(Decrease) increase in bank loan		(33,236	)		114,253
Issue of trust units, net of issuance costs (note 10)		10,502			147,221
Payments of distributions		(194,728	)		(144,609	)
		(217,462	)		116,865
Investing activities
Petroleum and natural gas property expenditures		(185,083	)		(148,719	)
Corporate acquisition (note 4)		(3,934	)		(243,273	)
Acquisition of working capital (note 4)		-			(13,229	)
Acquisition of petroleum and natural gas properties		(84,826	)		(2,877	)
Proceeds on disposal of petroleum and natural gas properties		194			723
Change in non-cash working capital (note 15)		19,874			4,060
		(253,775	)		(403,315	)
Change in cash and cash equivalents during the year		-			-
Cash and cash equivalents, beginning of year		-			-
Cash and cash equivalents, end of year	$	-		$	-
See accompanying notes to the consolidated financial statements.

7

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

1.           BASIS OF PRESENTATION

Baytex Energy Trust (the “Trust”) was established on September 2, 2003 under a Plan of Arrangement involving the Trust and Baytex Energy Ltd. (the “Company”). The Trust is an open-ended investment trust created pursuant to a trust indenture. Subsequent to the Plan of Arrangement, the Company is a subsidiary of the Trust.

The consolidated financial statements include the accounts of the Trust and its subsidiaries and have been prepared by management in accordance with Canadian generally accepted accounting principles (“GAAP”) as described in note 2.

Certain comparative figures have been reclassified to conform to the presentation adopted in the current period.

2.           SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The consolidated financial statements include the accounts of the Trust and its wholly owned subsidiaries from their respective dates of acquisition of the subsidiary companies.  Inter-company transactions and balances are eliminated upon consolidation.  Investments in unincorporated joint ventures are accounted for using the proportionate consolidation method as described under the “Joint Interests” heading.

Measurement Uncertainty

The preparation of the consolidated financial statements requires management to make 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 depreciation and depletion and amounts used for ceiling test calculations are based on estimates of petroleum and natural gas reserves and future costs required to develop those reserves.  The Trust’s reserves estimates are evaluated annually by an independent engineering firm.  By their nature, these estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact on the consolidated financial statements of future periods could be material.

Goodwill impairment tests involve estimates of the Trust’s fair value of the net identifiable assets and liabilities annually.  If the fair value is less than the book value, an impairment would be recorded.  Fair value of the Trust’s net identifiable assets and liabilities are based on external market value and reserve estimates and the related future cash flows which are subject to measurement uncertainty.

The amounts recorded for asset retirement obligations were estimated based on the Trust’s net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and the facilities and the estimated time period during which these costs will be incurred in the future.  Any changes to these estimates could change the amount recorded for asset retirement obligations and may materially impact the consolidated financial statements of future periods.

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.

8

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Cash and Cash Equivalents

Cash and cash equivalents include monies on deposit and short-term investments which have an initial maturity date at acquisition of not more than 90 days.

Crude Oil Inventory

Crude oil inventory, consisting of production in transit in pipelines at the balance sheet 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 to its existing condition and location.

Petroleum and Natural Gas Operations

The Trust follows the full cost method of accounting for its petroleum and natural gas operations whereby all costs relating to the exploration for and development of petroleum and natural gas reserves are capitalized on a country-by-country cost centre basis and charged against income, as set out below.  Such costs include land acquisition, drilling of productive and non-productive wells, geological and geophysical, production facilities, carrying costs directly related to unproved properties and corporate expenses directly related to acquisition, exploration and development activities and do not include any costs related to production or general overhead expenses.  These costs along with estimated future capital costs that are based on current costs and that are incurred in developing proved reserves are depleted and depreciated on a unit of production basis using estimated proved petroleum and natural gas reserves, with both production and reserves stated before royalties.  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 gas equates to one barrel of oil.  Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether proved reserves are attributable to the properties or impairment occurs.  Unproved properties are evaluated for impairment on an annual basis.

Gains or losses on the disposition of petroleum and natural gas properties are recognized only when crediting the proceeds to costs would result in a change of 20 percent or more in the depletion rate.

The net amount at which petroleum and natural gas properties are carried is subject to a cost recovery test (“ceiling test”).  The ceiling test is a two-stage process which is performed at least annually.  The first stage of the test is a recovery test which compares the undiscounted future cash flow from proved reserves at forecast prices plus the cost less impairment of unproved properties to the net book value of the petroleum and natural gas assets to determine if the assets are impaired.  An impairment loss exists when the net book value of the petroleum and natural gas assets exceeds such undiscounted cash flow.  The second stage determines the amount of the impairment loss to be recorded.  The impairment is measured as the amount by which the net book value of the petroleum and natural gas assets exceeds the future discounted cash flow from proved plus probable reserves at forecast prices.  Any impairment is recorded as additional depletion and depreciation.

Goodwill

Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of the acquired business.  Goodwill is stated at cost less impairment and is not amortized.  The goodwill balance is assessed for impairment annually at year-end or more frequently if events or changes in circumstances indicate that the asset may be impaired.  The test for impairment is conducted by the comparison of the net book value to the fair value of the Trust.  If the fair value of the Trust is less than the net book value, impairment is deemed to have occurred.  The extent of the impairment is measured by allocating the fair value of the Trust to the identifiable assets and liabilities at their fair values.  Any remainder of this allocation is the implied fair

9

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

value of goodwill.  Any excess of the net book value of goodwill over this implied value is the impairment amount.  Impairment is charged to income in the period in which it occurs.

Convertible Unsecured Subordinated Debentures

The debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders’ equity. The debt portion will accrete up to the principal balance at maturity. The accretion and the interest paid are expensed as interest expense in the consolidated statements of income and comprehensive income. If the debentures are converted to trust units, a portion of the value of the conversion feature under unitholders’ equity will be reclassified to unitholders’ capital along with the principal amounts converted.

Asset Retirement Obligations

The Trust recognizes a liability at the discounted value for the future abandonment and reclamation costs associated with the petroleum and natural gas properties.  The present value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life.  The liability accretes until the date of expected settlement of the retirement obligations.  The related accretion expense is recognized in the statement of income and comprehensive income.  The provision 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 balance sheet.

Joint Interests

A portion of the Trust’s exploration, development and production activities is conducted jointly with others.  These consolidated financial statements reflect only the Trust’s proportionate interest in such activities.

Foreign Currency Translation

The accounts of integrated foreign operations are translated using the temporal method, whereby monetary items are translated into the reporting currency at the exchange rate in effect at the balance sheet date.  Non-monetary items are translated at historical rates while revenues and expenses are translated using average rates over the period. Depreciation and amortization of assets is translated at historical exchange rates at the same exchange rates as the assets to which they relate.  Translation gains and losses relating to the integrated foreign operations are included in the determination of net income for the period.

Foreign currency denominated monetary items are translated into Canadian dollars at the exchange rate in effect at the balance sheet date.  Exchange gains and losses on long-term monetary items that do not qualify for hedge accounting are recognized in income.

Revenue and expenses are translated at the monthly average rate of exchange.  Translation gains and losses are included in net income.

Revenue Recognition

Revenue associated with sales of crude oil, natural gas and natural gas liquids is recognized when title passes to the purchaser, normally at the pipeline delivery point.

10

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Financial Instruments

Financial instruments are measured at fair value on initial recognition of the instrument, into one of the following five categories: held-for-trading, 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. Held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive income until the instrument is derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the effective interest rate method.

All risk management contracts are recorded in the balance sheet at fair value unless they qualify for the normal sale and normal purchase exemption. 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 Trust 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 and cash equivalents and restricted cash are classified as held-for-trading and are measured at fair value which equals the carrying value. Accounts receivable are classified as loans and receivables, which are measured at amortized cost. Accounts payable and accrued liabilities and bank debt are classified as other financial liabilities, which are measured at amortized cost.

The convertible debentures are classified as other financial liabilities. Upon issuance, the convertible debentures were classified into equity and financial liability components on the balance sheet at their fair value. The financial liability, net of issuance costs, is accreted, which is included within interest expense over the maturity of the debentures using the effective interest rate method.

For financial assets and financial liabilities that are not classified as held-for-trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are adjusted to the fair value initially recognized for that financial instrument. These costs are expensed using the effective interest rate method and are recorded within interest expense.

Financial Derivative Contracts

The Trust 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 Trust are related to underlying financial instruments or future petroleum and natural gas production.  The Trust does not use financial derivatives for trading or speculative purposes. These instruments are classified as “held-for-trading” unless designated for hedge accounting.  For derivative instruments that do not qualify as hedges or are not designated as hedges, the Trust applies the fair value method of accounting by recording an asset or liability on the Consolidated Balance Sheet and recognizes changes in the fair value of the instrument in the Statement 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.

The Trust has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments. This documentation specifically ties the derivative instruments to their use and in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated.  When applicable, the Trust identifies relationships between financial instruments and anticipated transactions, as well as its risk management objective and the

11

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

strategy for undertaking the economic hedge transaction.  When specific financial instruments are executed, the Trust assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in a particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

Future Income Taxes

The Trust follows the liability method of accounting for income taxes.  Under this method, future income taxes are recorded for the effect of any difference between the accounting and income tax bases of an asset or liability, using substantively enacted income tax rates. Future tax balances are adjusted for any changes in the tax rate and the adjustment is recognized in income in the period that the rate change occurs.

Unit-based Compensation

The Trust Unit Rights Incentive Plan is described in note 12.  The exercise price of the rights granted under the Plan may be reduced in future periods in accordance with the terms of the Plan. The Trust uses the binomial-lattice model to calculate the estimated fair value of the outstanding rights.

Compensation expense associated with rights granted under the plan is recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus.  The exercise of trust unit rights are recorded as an increase in trust units with a corresponding reduction in contributed surplus.

Non-controlling Interest

The exchangeable shares of the Trust are presented as a non-controlling interest on the consolidated balance sheet because they fail to meet the non-transferability criteria necessary in order for them to be classified as equity.  Net income has been reduced by an amount equivalent to the non-controlling interest’s proportionate share of the Trust’s consolidated net income with a corresponding increase to the non-controlling interest on the consolidated balance sheet.  As the exchangeable shares are converted to trust units, the exchange is accounted for as a step-acquisition where unitholders’ capital is increased by the fair value of the trust units issued.  The difference between the fair value of the trust units issued and the book value of the exchangeable shares is recorded as an increase in petroleum and natural gas properties.

Per-unit Amounts

Basic net income per unit is computed by dividing net income by the weighted average number of trust units outstanding during the year.  Diluted per unit amounts reflect the potential dilution that could occur if trust unit rights were exercised, exchangeable shares were exchanged and convertible debentures were converted.  The treasury stock method is used to determine the dilutive effect of trust unit rights, whereby any proceeds from the exercise of trust unit rights or other dilutive instruments and the amount of compensation expense, if any, attributed to future services and not yet recognized are assumed to be used to purchase trust units at the average market price during the year.

3.           CHANGES IN ACCOUNTING POLICIES

Current Year Accounting Changes

Effective January 1, 2008, the Trust adopted three new accounting standards that were issued by the Canadian Institute of Chartered Accountants ("CICA"): Section 1535, Capital Disclosures, Section 3862, Financial Instruments - Disclosures and Section 3863, Financial Instruments - Presentation.

12

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

A. Capital Disclosures

Effective January 1, 2008, the Trust prospectively adopted the Canadian Institute of Chartered Accountants (“CICA”) Section 1535, “Capital Disclosures” which establishes standards for disclosing information about the Trust’s capital and how it is managed. It requires disclosures of the Trust’s objectives, policies and processes for managing capital, the quantitative data about what the Trust regards as capital, whether the Trust has complied with any capital requirements and if it has not complied, the consequences of such non-compliance. The only effect of adopting this standard are disclosures on the Trust’s capital and how it is managed and are included in Note 18.

B. Financial Instruments - Disclosures, Financial Instruments - Presentation

Effective January 1, 2008, the Trust prospectively adopted Section 3862, “Financial Instruments Disclosures” and Section 3863, “Financial Instruments Presentations.” These new accounting standards replaced Section 3861, “Financial Instruments – Disclosure and Presentation.” Section 3862 requires additional information regarding the significance of financial instruments for the entity's financial position and performance, and the nature, extent and management of risks arising from financial instruments to which the entity is exposed. The additional disclosures required under these standards are included in Note 16.

C. Inventories

Section 3031 replaces the previous inventories standard and requires inventory be valued on a first-in, first-out basis.  The adoption of Section 3031 did not have an impact on the consolidated financial statements of the Trust.

These standards were adopted prospectively.

Future Accounting Changes

A. Goodwill and Intangible Assets

In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets, replacing Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The new Section will be effective on January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Trust is currently evaluating the impact of the adoption of this new Section, however does not expect a material impact on its consolidated financial statements.

B. International Financial Reporting Standards (“IFRS”)

In April 2008, the CICA published the exposure draft "Adopting IFRSs in Canada". The exposure draft proposes to incorporate IFRS into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS. The Trust has performed a diagnostic analysis that identifies differences between the Trust's current accounting policies and IFRS. At this time, the Trust is evaluating the impact of these differences and assessing the need for amendments to existing accounting policies in order to comply with IFRS.

C. Business Combinations

In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business combinations. Section 1582 establishes principles and requirements of the

13

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Trust plans to adopt this standard prospectively effective January 1, 2009 and does not expect the adoption of this statement to have a material impact on our results of operations or financial position.

D. Consolidated Financial Statements

In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Trust plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material impact on the results of operations or financial position.

4.           CORPORATE ACQUISITIONS

On June 4, 2008, Baytex acquired all the issued and outstanding shares of Burmis Energy Inc., a public company which had interests in certain natural gas and light oil properties located primarily in west central Alberta. The results of operations from these properties have been included in the consolidated financial statements since the closing of the acquisition on June 4, 2008. In conjunction with the acquisition, Burmis Energy Inc. was amalgamated with the Company.

This transaction has been accounted for using the purchase method of accounting. The estimated fair value of the assets acquired and liabilities assumed at the date of acquisition is summarized below:

Consideration for the acquisition:
Trust units issued	$	152,053
Net debt assumed		24,480
Costs associated with acquisition		3,934
Total purchase price	$	180,467
Allocation of purchase price:
Property, plant and equipment	$	219,913
Future income taxes		(37,910	)
Asset retirement obligations		(1,536	)
Total net assets acquired	$	180,467

All of the issued and outstanding shares of Burmis were acquired on the basis of 0.1525 of a Baytex trust unit for each Burmis share, resulting in the issuance of 6,383,416 Baytex trust units valued at $23.82 per unit, which was the average closing price of Baytex trust units for the ten trading days bordering the initial public announcement of the transaction.

On June 26, 2007, Baytex acquired all the issued and outstanding shares of a private company which had interests in certain petroleum and natural gas properties and related assets located primarily in the Pembina and Lindbergh areas of Alberta. The results of operations from these properties have been included in the consolidated financial statements since the closing of the acquisition on June 26, 2007. Subsequent to the acquisition, the private company was amalgamated with the Company.

14

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

This transaction has been accounted for using the purchase method of accounting. The fair value of the assets acquired and liabilities assumed at the date of acquisition is summarized below:

Consideration for the acquisition:
Cash paid for property, plant and equipment	$	241,092
Costs associated with acquisition		2,181
Cash paid for working capital		13,229
Total purchase price	$	256,502
Allocation of purchase price:
Working capital	$	13,229
Property, plant and equipment		320,036
Future income taxes		(74,524	)
Asset retirement obligations		(2,239	)
Total net assets acquired	$	256,502

5.           PETROLEUM AND NATURAL GAS PROPERTIES

	As at December 31
	2008			2007
Petroleum and natural gas properties	$	3,648,431		$	3,074,014
Accumulated depletion and depreciation		(2,047,414	)		(1,827,317	)
	$	1,601,017		$	1,246,697

In calculating the Canadian cost centre depletion and depreciation provision for 2008, $63.6million (2007 - $65.0 million) of costs relating to undeveloped properties were excluded, while $385.0 million (2007 - $427.1 million) of future development costs were included for the purposes of the depletion and depreciation calculation.  In calculating the U.S. cost centre depletion and depreciation provision for 2008, $57.6million (2007 - $nil) of costs relating to undeveloped properties were excluded, while $56.3 million (2007 - $nil) of future development costs were included for the purposes of the depletion and depreciation calculation.  No general and administrative expenses have been capitalized since the inception of operations as a trust.

Depletion and depreciation expense related to the Canadian and U.S. cost centers in 2008 were $218.4 million and $1.7 million respectively (2007 – $186.1 million and $nil).

The net book value of petroleum and natural gas properties are subject to a ceiling test, which was calculated at December 31, 2008 using the following benchmark reference prices for the years 2009 to 2013 adjusted for commodity differentials specific to the Trust (notes 16 & 17):

	2009		2010		2011		2012		2013
WTI crude oil (US$/bbl)		53.73		63.41		69.53		79.59		92.01
AECO natural gas ($/MMBtu)		6.82		7.56		7.84		8.38		9.20
Henry Hub (US$/MMBtu)		6.30		7.32		7.56		8.49		9.74
Exchange rate ($US equals $1 CAD)		0.80		0.85		0.85		0.90		0.95

The prices and costs subsequent to 2013 have been adjusted for estimated inflation at an estimated annual rate of 2.0 percent.  Based on the ceiling test calculations, the Trust’s estimated undiscounted future net cash flows associated with proved reserves plus the cost of unproved properties exceeded the net book value of the petroleum and natural gas properties.

15

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

6.           BANK LOAN AND CREDIT FACILITIES

The Company has a credit agreement with a syndicate of chartered banks.  The credit facilities consist of an operating loan and a 364-day revolving loan.  Advances or letters of credit (note 17) 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 rates plus applicable margins or LIBOR rates plus applicable margins.  Effective June 4, 2008, total credit facilities were increased to $485 million from $370 million. The credit facilities are subject to semi-annual review and are secured by a floating charge over all of the Company’s assets.  The credit facilities mature on July 1, 2009 and are eligible for extension.  At December 31, 2008 a total of $208.5 million was drawn under the credit facilities (December 31, 2007 - $241.7 million).

7.           LONG-TERM DEBT

	As at December 31
	2008			2007
10.5% senior subordinated notes (US$247)	$	303		$	244
9.625% senior subordinated notes (US$179,699)		220,059			177,561
		220,362			177,805
Discontinued fair value hedge		(3,089	)		(3,951	)
	$	217,273		$	173,854

The Company has US$0.2 million senior subordinated notes bearing interest at 10.5% payable semi-annually with principal repayable on February 15, 2011.  These notes are unsecured and are subordinate to the Company’s bank credit facilities.

The Company also has US$179.7 million senior subordinated notes bearing interest at 9.625% payable semi-annually with principal repayable on July 15, 2010. These notes are unsecured and are subordinate to the Company’s bank credit facilities. After July 15 in each of the following years, these notes 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 percentage of the principal amount of the notes): 2008 at 102.406%, 2009 and thereafter at 100%.  These notes are carried at amortized cost net of a discontinued fair value hedge of $6.0 million recorded on adoption of CICA Handbook Section 3865 “Hedges”. The notes will accrete up to the principal balance at maturity using the effective interest method. Accretion expense of $1.6 million had been recorded for the year ended December 31, 2008 (December 31, 2007 - $2.0 million) The effective interest rate is 10.6%.  The Company had an interest rate swap contract converting the fixed rate to a floating rate reset quarterly at the three-month LIBOR rate plus 5.2% until the maturity of these notes.  In November 2007, the Company terminated the interest rate swap contract. A gain on termination of $2.0 million was recorded as a reduction to interest expense in 2007.

Interest Expense

The Company incurred interest expense on its outstanding debt as follows:

	2008		2007
Bank loan and miscellaneous financing	$	12,685	$	13,296
Convertible debentures		945		1,295
Long-term debt		19,332		20,571
Total interest	$	32,962	$	35,162

16

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

8.           CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES

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 pay interest semi-annually and are 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. The debentures mature on December 31, 2010, at which time they are due and payable.

The debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders’ equity. This resulted in $95.2 million being classified as debt and $4.8 million being classified as equity. The debt portion will accrete up to the principal balance at maturity, using the effective interest rate of 7.6%. The accretion and the interest paid are expensed as interest expense in the consolidated statement of income and comprehensive income. If the debentures are converted to trust units, a portion of the value of the conversion feature under unitholders’ equity will be reclassified to unitholders’ capital along with the principal amounts converted.

	Number of Debentures			Convertible Debentures			Conversion Feature of Debentures
Balance, December 31, 2006		19,619		$	18,906		$	940
Conversion		(2,999	)		(2,895	)		(144	)
Accretion		-			139			-
Balance, December 31, 2007		16,620		$	16,150		$	796
Conversion		(6,222	)		(6,052	)		(298	)
Accretion		-			97			-
Balance, December 31, 2008		10,398		$	10,195		$	498

9.           ASSET RETIREMENT OBLIGATIONS

	As at December 31
	2008			2007
Balance, beginning of year	$	45,113		$	39,855
Liabilities incurred		871			2,180
Liabilities settled		(1,443	)		(2,442	)
Acquisition of liabilities		1,536			2,239
Disposition of liabilities		(904	)		(585	)
Accretion		3,802			3,404
Change in estimate(1)		376			462
Balance, end of year	$	49,351		$	45,113

(1)Change in status of wells and change in the estimated costs of abandonment and reclamations are factors resulting in a change in estimate.

The Trust’s asset retirement obligations are based on the Trust’s net ownership in wells and facilities.  Management estimates the costs to abandon and reclaim the wells and the facilities and the estimated time period during which these costs will be incurred in the future.  These costs are expected to be incurred over the next 50 years. The undiscounted amount of estimated cash flow required to settle the retirement obligations at December 31, 2008 is $274.0 million.  Estimated cash flow has been discounted at a credit-adjusted risk free rate of 8.0 percent and an estimated annual inflation rate of 2.0 percent.

17

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

10.           UNITHOLDERS’ CAPITAL

The Trust is authorized to issue an unlimited number of trust units.

	Number of Units		Amount
Balance, December 31, 2006		75,122	$	637,156
Issued from treasury for cash		7,000		142,135
Issued on conversion of debentures		203		3,037
Issued on conversion of exchangeable shares		12		230
Issued on exercise of trust unit rights		739		5,482
Transfer from contributed surplus on exercise of trust unit rights		-		2,816
Issued pursuant to distribution reinvestment plan		1,464		27,763
Cumulative effect of change in accounting policy		-		3,005
Balance, December 31, 2007		84,540		821,624
Issued on conversion of debentures		422		6,350
Issued on conversion of exchangeable shares		2,787		86,888
Issued on exercise of trust unit rights		1,386		10,653
Transfer from contributed surplus on exercise of trust unit rights		-		5,105
Issued on acquisition of Burmis Energy Inc. net of issuance costs		6,383		151,903
Issued pursuant to distribution reinvestment plan		2,167		47,386
Balance, December 31, 2008		97,685	$	1,129,909

On October 18, 2004, the Trust implemented a Distribution Reinvestment Plan (“DRIP”).  Under the DRIP, Canadian unitholders are entitled to reinvest monthly cash distributions in additional trust units of the Trust.  At the discretion of the Trust, these additional units will be issued from treasury at 95% of the “weighted average closing price”, or acquired on the market at prevailing market rates. For the purposes of the units issued from treasury, the “weighted average closing price” is calculated as the weighted average trading price of trust units for the period commencing on the second business day after the distribution record date and ending on the second business day immediately prior to the distribution payment date, such period not to exceed 20 trading days.

Trust units are redeemable at the option of the holder.  The redemption price is equal to the lesser of 90 percent of the “market price” of the trust units on the TSX for the ten trading days after the trust units have been surrendered for redemption and the closing market price on the date the trust units have been surrendered for redemption.  Trust units can be redeemed for cash to a maximum of $250,000 per month.  Redemptions in excess of the cash limit, if not waived by the Trust, shall be satisfied by distribution of subordinate, unsecured redemption notes bearing interest at 12% per annum, due and payable no later than September 1, 2033.

11.           NON-CONTROLLING INTEREST

The Company is authorized to issue an unlimited number of exchangeable shares.  The exchangeable shares can be converted (at the option of the holder) into trust units at any time up to September 2, 2013.  Up to 1.9 million exchangeable shares may be redeemed annually by the Company for either a cash payment or the issue of trust units.  The number of trust units issued upon conversion is based upon the exchange ratio in effect at the conversion date.  The exchange ratio is adjusted monthly to account for distributions paid on the trust units by dividing the cash distribution paid by the weighted average trust unit price for the five-day trading period ending on the record date.  Cash distributions are not paid on the exchangeable shares. The exchangeable shares are not publicly traded, although they may be transferred by the holder without first being converted to trust units.

18

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

The exchangeable shares of the Company are presented as a non-controlling interest on the consolidated balance sheet because they fail to meet the non-transferability criteria necessary in order for them to be classified as equity.  Net income has been reduced by an amount equivalent to the non-controlling interest proportionate share of the Trust’s consolidated net income with a corresponding increase to the non-controlling interest on the balance sheet.

	Number of Exchangeable Shares			Amount
Balance, December 31, 2006		1,573		$	17,187
Exchanged for trust units		(7	)		(83	)
Non-controlling interest in net income		-			4,131
Balance, December 31, 2007		1,566		$	21,235
Exchanged for trust units		(1,566	)		(24,593	)
Non-controlling interest in net income		-			3,358
Balance, December 31, 2008		-		$	-

On May 30, 2008, the Trust announced that Baytex Energy Ltd. had elected to redeem all of its exchangeable shares outstanding on August 29, 2008. In connection with this redemption, Baytex ExchangeCo Ltd. exercised its overriding “redemption call right” to purchase such exchangeable shares from holders of record. Each exchangeable share was exchanged for units of the Trust in accordance with the exchange ratio in effect at August 28, 2008.  As at December 31, 2008, there were no exchangeable shares outstanding.

12.           TRUST UNIT RIGHTS INCENTIVE PLAN

The Trust has a Trust Unit Rights Incentive Plan (the “Plan”) whereby the maximum number of trust units issuable pursuant to the Plan is a “rolling” maximum equal to 10.0% of the outstanding trust units plus the number of trust units which may be issued on the exchange of outstanding exchangeable shares. Any increase in the issued and outstanding trust units will result in an increase in the number of trust units available for issuance under the Plan, and any exercises of rights will make new grants available under the Plan, effectively resulting in a re-loading of the number of rights available to grant under the Plan. Trust unit rights are granted at the volume weighted average trading price of the trust units for the five trading days prior to the date of grant, vest over three years and have a term of five years. The Plan provides for the exercise price of the rights to be reduced in future periods by a portion of the future distributions, subject to certain performance criteria.

The Trust recorded compensation expense of $7.8 million for the year ended December 31, 2008 ($8.0 million in 2007) related to the rights granted under the plan.

The Trust uses the binomial-lattice model to calculate the estimated weighted average fair value of $2.42 per unit for rights issued during 2008 ($3.87 per unit in 2007).  The following assumptions were used to arrive at the estimate of fair values:

	2008			2007
Expected annual right’s exercise price reduction	$	2.64		$	2.16
Expected volatility		28% - 39	%		28	%
Risk-free interest rate		2.98% - 4.17	%		3.77% - 4.50	%
Expected life of right (years)	Various (1)			Various (1)

(1) The binomial-lattice model calculates the fair values based on an optimal strategy, resulting in various expected life of unit rights.  The maximum term is limited to five years by the Trust Unit Rights Incentive Plan.

19

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

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

	Number of rights			Weighted average exercise price(1)
Balance, December 31, 2006		6,313		$	14.00
Granted		2,642		$	19.85
Exercised		(739	)	$	7.42
Cancelled		(554	)	$	16.91
Balance, December 31, 2007		7,662		$	14.67
Granted		2,838		$	19.27
Exercised		(1,386	)	$	7.69
Cancelled		(665	)	$	21.79
Balance, December 31, 2008		8,449		$	14.58

(1)    Exercise price reflects grant prices less reduction in exercise price as discussed above.

The following table summarizes information about the unit rights outstanding at December 31, 2008:

Range of Exercise Prices	Number Outstanding at December 31, 2008	Weighted Average Remaining Term	Weighted Average Exercise Price	Number Exercisable at December 31, 2008	Weighted Average Exercise Price
		(years)
$  1.00 to $  6.00	706	0.9	$  3.71	706	$  3.71
$  6.01 to $11.00	1,352	1.8	$  8.35	1,254	$  8.17
$11.01 to $16.00	399	3.2	$15.08	183	$15.14
$16.01 to $21.00	5,947	3.9	$17.18	1,637	$17.05
$21.01 to $32.28	45	4.4	$25.93	-	-
$  1.00 to $32.28	8,449	3.3	$14.58	3,780	$11.52

The following table summarizes the changes in contributed surplus:

Balance, December 31, 2006	$	13,357
Compensation expense		7,986
Transfer from contributed surplus on exercise of trust unit rights (1)		(2,816	)
Balance, December 31, 2007	$	18,527
Compensation expense		7,812
Transfer from contributed surplus on exercise of trust unit rights (1)		(5,105	)
Balance, December 31, 2008	$	21,234

(1) Upon exercise of rights, contributed surplus is reduced with a corresponding increase in unitholders' capital.

13.           NET INCOME PER UNIT

The Trust applies the treasury stock method to assess the dilutive effect of outstanding trust unit rights on net income per unit.  The weighted average exchangeable shares outstanding during the year, converted at the year-end exchange ratio, and the trust units issuable on conversion of convertible debentures, have also been included in the calculation of the diluted weighted average number of trust units outstanding:

20

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

2008	Net income		Trust units		Net income per trust unit
Net income per basic unit	$	259,894		91,683	$	2.83
Dilutive effect of trust unit rights		-		2,955
Conversion of convertible debentures		654		882
Exchange of exchangeable shares		3,358		871
Net income per diluted unit	$	263,906		96,391	$	2.74
2007	Net income		Trust units		Net income per trust unit
Net income per basic unit	$	132,860		80,029	$	1.66
Dilutive effect of trust unit rights		-		2,110
Conversion of convertible debentures		855		1,206
Exchange of exchangeable shares		4,131		2,630
Net income per diluted unit	$	137,846		85,975	$	1.60

The dilutive effect of trust unit incentive rights for the year ended December 31, 2008 did not include 45,000 trust unit rights (2007 – 4.1 million) because the respective proceeds of exercise plus the amount of compensation expense attributed to future services and not yet recognized exceeded the average market price of the trust units during the year.

14.         TAX EXPENSE (RECOVERY)

The provision for (recovery of) taxes has been computed as follows:
	2008			2007
Income before taxes and non-controlling interest	$	288,812		$	94,335
Expected taxes at the statutory rate of 30.22% (2007 – 34.02%)		87,279			32,094
Increase (decrease) in taxes resulting from:
Net income of the Trust		(79,930	)		(62,615	)
Non-taxable portion of foreign exchange loss (gain)		6,204			(5,424	)
Effect of change in tax rate		(1,402	)		(15,806	)
Effect of change in opening tax pool balances		878			(834	)
Effect of change in valuation allowance		-			2,075
Unit-based compensation		2,361			2,717
Other		(7	)		(1,576	)
Future tax expense (recovery)		15,383			(49,369	)
Current tax expense		10,177			6,713
Total tax expense (recovery)	$	25,560		$	(42,656	)

On June 22, 2007, Bill C-52 Budget Implementation Act, which contains legislative provisions to tax publicly traded income trusts in Canada, received Royal Assent in the Canadian House of Commons. The new tax is not expected to apply to the Trust until 2011.  As a result of the tax legislation becoming enacted, an additional future tax recovery of $0.5 million was recorded in 2007.

21

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

The components of the net future tax liability at December 31 were as follows:
	2008			2007
Future tax liabilities:
Petroleum and natural gas properties	$	197,694		$	155,921
Financial instruments		25,358			-
Other		14,215			18,271
Future tax assets:
Asset retirement obligations		(12,652	)		(11,796	)
Non-capital loss carry-forward		(11,813	)		(8,058	)
Valuation allowance on non-capital losses		4,967			-
Financial instruments		-			(11,525	)
Other		-			(395	)
Net future tax liability (1)		217,769			142,418
Current portion of net future tax liability (asset)		25,358			(11,525	)
Long-term portion of net future tax liability	$	192,411		$	153,943

(1) Non-capital loss carry-forwards, excluding those for which a valuation allowance has been taken, amongst Canadian and U.S. subsidiaries, totaled $42.9 million ($62.0 million in 2007) and expire from 2014 to 2017.

15.           SUPPLEMENTAL INFORMATION

Change in Non-Cash Working Capital Items

	2008		2007
Current assets	$	35,460	$	(23,619	)
Current liabilities		23,310		32,819
	$	58,770	$	9,200
Changes in non-cash working capital related to:
Operating activities	$	38,896	$	5,140
Investing activities		19,874		4,060
	$	58,770	$	9,200

Supplemental Cash Flow Information

During the year the Trust made the following cash outlays in respect of interest expense and current income taxes:

	2008		2007
Interest	$	30,655	$	32,321
Current income taxes	$	9,972	$	9,436

Foreign Exchange Loss (Gain)

	2008			2007
Unrealized foreign exchange loss (gain)	$	41,712		$	(32,574	)
Realized foreign exchange (gain) loss		(3,966	)		160
Total foreign exchange loss (gain)	$	37,746		$	(32,414	)

22

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

16.           FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Trust’s financial assets and liabilities are comprised of accounts receivable, accounts payable and accrued liabilities, distributions payable to unitholders, bank loan, financial derivative contracts, long-term debt, convertible debentures and deferred obligations.

Categories of Financial Instruments

Under Canadian generally accepted accounting principles, financial instruments are classified into one of the following 5 categories: held-for-trading, held to maturity, loans and receivables, available-for-sale and other financial liabilities. The carrying value and fair value of the Trust’s financial instruments on the consolidated balance sheet are classified into the following categories:

	December 31, 2008						December 31, 2007
	Carrying Value			Fair Value			Carrying Value			Fair Value
Financial Assets
Loans and receivables
Accounts receivable	$	87,551		$	87,551		$	105,176		$	105,176
Total loans and receivables	$	87,551		$	87,551		$	105,176		$	105,176
Held for trading
Derivatives designated as held for trading	$	85,678		$	85,678			-			-
Total held for trading	$	85,678		$	85,678			-			-
Financial Liabilities
Held for trading
Derivatives designated as held for trading		-			-		$	(34,239	)	$	(34,239	)
Total held for trading		-			-		$	(34,239	)	$	(34,239	)
Other financial liabilities
Accounts payable and accrued liabilities	$	(164,279	)	$	(164,279	)	$	(104,318	)	$	(104,318	)
Distributions payable to unitholders		(17,583	)		(17,583	)		(15,217	)		(15,217	)
Bank loan		(208,482	)		(208,482	)		(241,748	)		(241,748	)
Long-term debt		(217,273	)		(200,557	)		(173,854	)		(182,132	)
Convertible debentures		(10,195	)		(9,837	)		(16,150	)		(19,481	)
Deferred obligations		(74	)		(74	)		(113	)		(113	)
Total other financial liabilities	$	(617,886	)	$	(600,812	)	$	(551,400	)	$	(563,009	)

The estimated fair values of the financial instruments have been determined based on the Trust’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 borrowings approximate their book amounts due to the short-term maturity of these instruments. The fair value of the bank loan approximates its book 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 instrument.  The fair value of the convertible debentures has been calculated based on the lower of trading value and the present value of future cash flows associated with the debentures.

23

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Financial Risk

The Trust is exposed to a variety of financial risk, including market risk, credit risk and liquidity risk. The Trust monitors and, when appropriate, utilizes derivative contracts to manage its exposure to these risks. The Trust 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

The Trust is exposed to fluctuations in foreign currency as a result of its U.S. dollar denominated notes, crude oil sales based on U.S. dollar indices and commodity contracts that are settled in U.S. dollars. The Trust’s net income and cash flow will therefore be impacted by fluctuations in foreign exchange rates.

In order to manage these risks, the Trust may enter into agreements to fix the exchange rate of Canadian to U.S. dollar in order to lessen the impact of currency rate fluctuations.

At December 31, 2008, the Trust had in place the following currency swap:

	Period	Amount	Swap Price
Swap	January 1, 2009 to December 31, 2009	USD 8.3 million per month	CAD/USD 1.2394 (weighted average)

The following table demonstrates the effect of exchange rate movement on net income before taxes and non-controlling interest due to changes in the fair value of its currency swap as well as gains and losses on the revaluation of U.S. dollar denominated monetary assets and liabilities at December 31, 2008.

	$0.10 Increase/Decrease in CAD/USD Exchange Rate
Gain/loss on currency swap	$                 (189)
Gain/loss on other monetary assets/liabilities	10,939
Impact on income before taxes and non-controlling interest	$              10,750

The carrying amounts of the Trust’s foreign currency denominated monetary assets and liabilities at the reporting date are as follows:

	Assets		Liabilities
	December 31, 2008	December 31, 2007	December 31, 2008	December 31, 2007
U.S. dollar denominated	USD   84,070	USD    54,674	USD   191,571	USD  226,528

Subsequent to December 31, 2008, the Trust added the following currency swap:

	Period	Amount	Swap Price
Swap	January 1, 2009 to December 31, 2009	USD 1.7 million per month	CAD/USD 1.2345

Interest rate risk

The Trust’s interest rate risk arises from its floating rate bank loan. As at December 31, 2008, $208.5 million of the Trust’s total debt is subject to movements in floating interest rates. An increase or decrease of 1.0% in interest rates would impact cash flow for the 2008 by approximately $2.2 million.

24

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Commodity Price Risk

The Trust monitors and, when appropriate, utilizes financial derivative agreements or fixed price 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 the Company. Under the Trust’s risk management policy, financial instruments are not used for speculative purposes.

When assessing the potential impact of commodity price changes, a 10% increase in commodity prices could have resulted in a reduction to the unrealized gain in 2008 of $8.5 million relating to the financial derivative instruments outstanding as at December 31, 2008, while a 10% decrease could have resulted in $8.8 million of additional gain.

At December 31, 2008, the Trust had the following commodity derivative contracts:

OIL	Period	Volume	Price	Index
Price collar	Calendar 2009	2,000 bbl/d	USD  90.00 – 136.40	WTI
Price collar	Calendar 2009	2,000 bbl/d	USD 110.00 – 172.70	WTI

Derivative contracts are marked to market at the end of each reporting period, with the following reflected in the income statement:

	2008			2007
Realized (loss) on financial instruments	$	(60,101	)	$	(3,164	)
Unrealized gain (loss) on financial instruments		119,917			(31,320	)
Gain (loss) on financial instruments	$	59,816		$	(34,484	)

Subsequent to December 31, 2008, the Trust added the following commodity derivative contract:

GAS	Period	Volume	Price	Index
Price collar	April 1, 2009 to December 31, 2010	5,000 GJ/d	CAD 5.00 – 6.30	AECO

Liquidity risk

Liquidity risk is the risk that the Trust will encounter difficulty in meeting obligations associated with financial liabilities.  The Trust manages its liquidity risk through cash and debt management.  As at December 31, 2008, the Trust had available unused bank credit facilities in the amount of $183 million. The Trust believes it has sufficient funding capacity through its credit facilities to meet foreseeable borrowing requirements.

25

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

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

Total 1 year 2-3 years 4-5 years Beyond 5 years

Accounts payable and accrued liabilities	164,279	164,279	-	-	-
Distributions payable to unitholders	17,583	17,583	-	-	-
Bank loan (1)	208,482	208,482	-	-	-
Long-term debt (2)	220,362	-	220,362	-	-
Convertible debentures (2)	10,398	-	10,398	-	-
Deferred obligations	74	46	23	5	-
	621,178	390,390	230,783	5	-

(1) The bank loan is a 364-day revolving loan with the ability to extend the term.  The Trust has no reason to believe that it will be unable to extend the credit facility when it matures on July 1, 2009.

 (2) Principal amount of instruments.

Credit risk

Credit risk is the risk that a counterparty to a financial asset will default resulting in the Trust incurring a loss. Most of the Trust’s accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks.  The Trust manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis.  Credit risk may also arise from financial derivative instruments.  The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The 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.

As at December 31, 2008, accounts receivable consists of a balance of $9.9 million which is over 90 days (December 31, 2007 - $3.5 million).  A balance of $2.4 million has been set up as an allowance for doubtful accounts (December 31, 2007 - $0.2 million).

17.           COMMITMENTS AND CONTINGENCIES

At December 31, 2008, the Trust had the following crude oil supply contracts:

Heavy Oil	Period	Volume	Price
Price Swap – WCS Blend	Calendar 2009	10,340 bbl/d	WTI x 67.0% (weighted average)

Subsequent to December 31, 2008, the Trust added the following physical crude oil supply contracts:

Heavy Oil	Period	Volume	Price
Price Swap – WCS Blend	April 1, 2009 to August 30, 2009	775 bbl/d	WTI x 80.0%
Price Swap – WCS Blend	April 1, 2009 to August 30, 2009	775 bbl/d	WTI less US$10.00

At December 31, 2008, the Trust had the following natural gas physical sales contract:

Gas	Period	Volume	Price/GJ
Price Collar	Calendar 2009	5,000 GJ/d	$7.00 - $7.95

26

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

At December 31, 2008, the Trust had the following power contracts:

Power	Period	Volume	Price/MWh
Fixed	October 1, 2008 to December 31, 2009	0.6 MW/hr	$78.61
Fixed	October 1, 2008 to December 31, 2009	0.6 MW/hr	$79.92

Subsequent to December 31, 2008, the Trust added the following physical power contract:

Power	Period	Volume	Price/MWh
Fixed	March 1, 2009 to June 30, 2010	0.6 MW/hr	$76.89

At December 31, 2008, the Trust had operating lease and transportation obligations as summarized below:

Payments Due

	Total		1 year		2 years		3 years		4 years		5 years		Beyond 5 years
Operating leases	$	42,732	$	2,776	$	3,327	$	3,785	$	4,073	$	3,814	$	24,957
Processing and transportation agreements		22,350		8,478		7,435		6,196		178		63		-
Total	$	65,082	$	11,254	$	10,762	$	9,981	$	4,251	$	3,877	$	24,957

Other

At December 31, 2008, there were outstanding letters of credit aggregating $2.3 million (December 31, 2007 - $4.9 million) issued as security for performance under certain contracts.

In connection with a purchase of properties in 2005, Baytex became liable for contingent consideration whereby an additional amount would be payable by Baytex if the price for crude oil exceeds a base price in each of the succeeding six years. An amount payable was not reasonably determinable at the time of the purchase, therefore such consideration should be recognized only when the contingency is resolved. As at December 31, 2008, additional payments totaling $5.3 million have been paid under the agreement and have been recorded as an adjustment to the original purchase price of the properties.  It is currently not determinable if further payments will be required under this agreement, therefore no accrual has been made.

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

18.           CAPITAL STRUCTURE

The Trust’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.

The Trust considers its capital structure to include total monetary debt and unitholders’ equity. Total monetary debt is a non-GAAP term which we define to be the sum of monetary working capital, which is current assets less current liabilities excluding non-cash items such as future income tax assets or liabilities and unrealized financial derivative gains or losses, the principal amount of long-term debt and the balance sheet value of the convertible debentures.

27

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

The Trust’s financial strategy is designed to maintain a flexible capital structure consistent with the objectives above and to respond to changes in economic conditions and the risk characteristics of its underlying assets. In order to maintain the capital structure, the Trust may adjust the amount of its distributions, adjust its level of capital spending, issue new units, issue new debt or sell assets to reduce debt.

The Trust monitors capital based on current and projected ratios of total monetary debt to cash flow, and the current and projected level of its undrawn bank credit facilities. The Trust’s objectives are to maintain a total monetary debt to cash flow 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 cash flow 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 cash flow from operations ratio and the level of undrawn bank credit facilities, the Trust continuously monitors its cash flow from operations and evaluates its distribution policy and capital spending plans.

The Trust’s financial objectives and strategy as described above have remained substantially unchanged over the last two completed fiscal years.  These objectives and strategy are reviewed on an annual basis.  The Trust believes its financial metrics are within acceptable limits pursuant to its capital management objectives.

The Trust is subject to financial covenants relating to its bank loan, senior subordinated notes and convertible debentures. The Trust is in compliance with all financial covenants.

On June 22, 2007, new tax legislation modifying the taxation of specified investment flow-through entities, including income trusts such as the Trust, was enacted (the “New Tax Legislation”). The New Tax Legislation will apply a tax at the trust level on distributions of certain income from trusts. The New Tax Legislation permits “normal growth” for income trusts through the transitional period ending December 31, 2010. However, “undue expansion” could cause the transitional relief to be revisited, and the New Tax Legislation to be effective at a date earlier than January 1, 2011. On December 15, 2006, the Department of Finance released guidelines on normal growth for income trusts and other flow-through entities (the “Guidelines”). Under the Guidelines, trusts will be able to increase their equity capital each year during the transitional period by an amount equal to a safe harbor amount. The safe harbor amount is measured by reference to a trust’s market capitalization as of the end of trading on October 31, 2006.  The safe harbor amounts are 40% for the period from November 2006 to the end of 2007, and 20% per year for each of 2008, 2009 and 2010. For Baytex, the limits are approximately $730 million for 2006/2007 and $365 million for each of the subsequent three years. The safe harbor amounts are cumulative allowing amounts not used in one year to be carried forward to a future year. Two trusts can merge without being impacted by the growth limitations. Limits are not impacted by non-convertible debt-financed growth, but rather focus solely on the issuance of equity to facilitate growth.  At December 31, 2008, the Trust had not exceeded its “normal growth” limits.

28

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

19.           DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES

The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”) which, in most respects, conforms to accounting principles generally accepted in the United States (“U.S. GAAP”).  The significant differences between Canadian GAAP and U.S. GAAP are described in this note.

Reconciliation of net income under Canadian GAAP to U.S. GAAP

For the years ended December 31		2008	2007
	Note
Net income – Canadian GAAP		$     259,894	$    132,860
Increase (decrease) under U.S. GAAP:
Unrealized gain (loss) on financial instruments	D	-	(1,168)
Depletion, depreciation and accretion	A, H	(695,715)	34,741
Interest	D	959	2,351
Unit-based compensation	C	(1,206)	3,149
Income tax recovery (expense)	A,D,H,I	160,235	(16,703)
Non-controlling interest	B	3,358	4,131
Net income (loss) – U.S. GAAP		$     (272,475)	$    159,361
Net income (loss) per trust unit	K
Basic		$           (2.94)	$          1.93
Diluted		$           (2.94)	$          1.86
Weighted average trust units	K
Basic		92,554	82,659
Diluted		92,554	85,975

29

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Condensed Consolidated Statement of Operations – U.S. GAAP

For the years ended December 31		2008	2007
	Note
Revenue
Petroleum and natural gas sales, net of royalties		$       952,196	$     643,080
Gain (loss) on financial instruments	D	59,816	(35,652)
		1,012,012	607,428
Expenses
Operating	C	174,445	135,700
Transportation and blending		218,706	155,754
General and administrative	C	36,647	27,398
Interest	D	32,003	32,891
Foreign exchange loss (gain)		37,746	(32,494)
Depletion, depreciation and accretion	A,H	919,615	154,771
		1,419,162	474,020
Income (loss) before taxes		(407,150)	133,408
Current		10,177	6,713
Future	A,D,H,I	(144,852)	(32,666)
Tax recovery		(134,675)	(25,953)
Net income (loss)/ Comprehensive Income (loss)		$      (272,475)	$      159,361
Consolidated Statement of Accumulated Deficit
Deficit, beginning of the year		$ (1,159,401)	$ (1,403,144)
Net income (loss)		(272,475)	159,361
Distributions to unitholders		(244,481)	(174,067)
Adjustment for fair value of temporary equity	B	469,564	258,449
Deficit, end of the year		$    (1,206,793)	$ (1,159,401)

30

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Condensed Consolidated Balance Sheet

As at December 31		2008		2007
	Note	As Reported	U.S. GAAP	As Reported	U.S. GAAP
Assets
Current assets	D,I	$     173,561	$     173,561	$     122,698	$     122,674
Petroleum and natural gas properties	F	3,648,430	3,548,224	3,074,014	3,058,163
Accumulated depletion & depreciation	A	(2,047,413)	(2,844,948)	(1,827,317)	(1,929,982)
Petroleum and natural gas properties, net		1,601,017	703,276	1,246,697	1,128,181
Deferred charges	H	-	2,059	-	3,016
Goodwill		37,755	37,755	37,755	37,755
		$  1,812,333	$  916,651	$  1,407,150	$  1,291,626
Liabilities and Unitholders’ Equity
Current liabilities	D	$     415,702	$     390,344	$     395,522	$     395,522
Long-term debt	D	217,273	220,362	173,854	177,805
Convertible debentures	E	10,195	10,398	16,150	16,620
Deferred obligations		74	74	113	113
Asset retirement obligations		49,351	49,351	45,113	45,113
Share-based payment liability	C	-	21,825	-	35,909
Future tax liability	A,D,H,I	192,411	-	153,943	123,737
		885,006	692,354	784,695	794,819
Non-controlling interest	B	-	-	21,235	-
Temporary equity		-	1,431,090	-	1,656,208
Unitholders’ capital	B	1,129,909	-	821,624	-
Conversion feature of debentures	E	498	-	796	-
Contributed surplus	B,C	21,234	-	18,527	-
Deficit		(224,314)	(1,206,793)	(239,727)	(1,159,401)
		927,327	(1,206,793)	601,220	(1,159,401)
		$  1,812,333	$    916,651	$  1,407,150	$  1,291,626

31

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Condensed Consolidated Statement of Cash Flows – U.S. GAAP

For the years ended December 31	2008			2007
Operating activities
Net income (loss)	$	(272,475	)	$	159,361
Unit-based compensation		9,018			4,837
Amortization of deferred charges		845			1,385
Unrealized foreign exchange loss (gain)		42,434			(32,574	)
Depletion, depreciation and accretion		918,770			153,199
Unrealized (gain) loss on financial derivatives		(119,917	)		32,488
Future tax (recovery)		(144,852	)		(32,666	)
Change in non-cash working capital		38,896			5,140
Asset retirement expenditures		(1,443	)		(2,442	)
Decrease in deferred charges and other assets		(39	)		(2,278	)
Cash from operating activities	$	471,237		$	286,450
Cash (used in) financing activities	$	(217,462	)	$	116,865
Cash (used in) from investing activities	$	(253,775	)	$	(403,315	)

Notes:

(A) Full Cost Accounting

The full cost method of accounting for crude oil and natural gas operations under Canadian GAAP and U.S. GAAP differs in the following respects.  Under U.S. GAAP, the book value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at 10 percent, (based on prices and costs at the balance sheet date) plus the lower of cost and fair value of unproven properties including the cost of properties not being amortized.  The cost of properties not being amortized consists of the cost of acquiring and evaluating undeveloped land.

Under Canadian GAAP the first stage of this “ceiling test” is a recovery test which compares the undiscounted future cash flow from proved reserves at forecast prices plus the cost less impairment of unproved properties to the net book value of the petroleum and natural gas assets to determine if the petroleum and natural gas assets are impaired.  An impairment loss exists when the book value of the petroleum and natural gas assets exceeds such undiscounted cash flows.  The second stage determines the amount of the impairment loss to be recorded.  The impairment is measured as the amount by which the net book value of the petroleum and natural gas assets exceed the future discounted cash flow from proved plus probable reserves at forecast prices.

In computing its consolidated net income for U.S. GAAP purposes in prior years, the Trust recorded additional depletion as a result of the ceiling test.  These charges were not required under the Canadian GAAP ceiling tests.  As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes and therefore the charge for depletion, depreciation and accretion will differ in subsequent years.

At December 31, 2008, the Trust’s capitalized costs of oil and gas properties exceeded the full cost ceiling resulting in a non-cash U.S. GAAP write-down of $799.1 million charged to depletion, depreciation and accretion (2007 – nil). As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes.

32

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

Under Canadian GAAP, depletion is calculated by reference to proved reserves estimated using forecast prices.  Under U.S. GAAP, depletion charges are calculated by reference to proved reserves estimated using constant prices.  The difference in proved reserves has resulted in $104.3 million less depletion recorded under U.S. GAAP for the year ended December 31, 2008 ($36.1 million less depletion – 2007).

(B) Temporary Equity

The Trust Units contain a redemption feature which is required for the Trust to retain its mutual fund trust status for Canadian income tax purposes.  The redemption feature of the trust units entitles the holder to redeem the Trust Units.  However, the restrictions on redemption are not substantive enough to be accounted for as a component of permanent Unitholders’ Equity under U.S. GAAP, in accordance with EITF D-98, “Classification and Measurement of Redeemable Securities”, the trust units must be presented as Temporary Equity and recorded on the consolidated balance sheets at their redemption value.

In applying EITF D-98 the Trust has recorded Temporary Equity in the amount of $1,431.1 million as at December 31, 2008 and $1,656.2 million as at December 31, 2007 which represents the estimated redemption value of the Trust Units and the exchangeable shares (which are convertible into trust units) at the balance sheet date.  The difference between the Trust’s Temporary Equity under U.S. GAAP and Unitholders’ Capital under Canadian GAAP is applied to Accumulated Deficit.  The adjustments to Accumulated Deficit are credits of $469.6 million for 2008 and $258.4 million for 2007.

Under Canadian GAAP, the exchangeable shares of the Trust are presented as a non-controlling interest on the consolidated balance sheet.  Net income under Canadian GAAP has been reduced by an amount equivalent to the non-controlling interest proportionate share of the Trust’s consolidated net income with a corresponding increase to the non-controlling interest on the consolidated balance sheet.

Under U.S. GAAP, the consolidated balance sheet would not include an amount for non-controlling interest and income would not be reduced.  Instead, under U.S. GAAP, the estimated redemption amount of the exchangeable shares at the balance sheet date would be included in Temporary Equity on the consolidated balance sheet.

On May 30, 2008, the Trust announced that Baytex Energy Ltd. had elected to redeem all of its exchangeable shares outstanding on August 29, 2008. In connection with this redemption, Baytex ExchangeCo Ltd. exercised its overriding “redemption call right” to purchase such exchangeable shares from holders of record. Each exchangeable share had been exchanged for units of the Trust in accordance with the exchange ratio in effect at August 28, 2008.  As at December 31, 2008, there were no exchangeable shares outstanding.

(C) Unit-Based Compensation

The Trust has a Trust Units Rights Incentive Plan established in 2003.  As the exercise price of the unit rights granted under the plan is subject to downward revisions from time to time, the unit rights plan is a variable compensation plan under U.S. GAAP.  Effective January 1, 2006, the Trust adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payments”, (SFAS 123R) for purposes of the U.S. – Canadian GAAP reconciliation using modified prospective application.  Under this standard, the Trust must account for compensation expense based on the fair value of rights granted under its unit-based compensation plan.  The fair value of the unit rights has been determined using a binomial-lattice model.  Under SFAS 123R the Trust’s share-based compensation plan is classified as a liability and the unit rights are fair valued at each reporting date.  Compensation expense for the unit rights plan is recognized in income until settlement date based on the reporting date fair value and the portion of the vesting period that has transpired. The accounting for compensation expense for the unit rights plan results in a difference between Canadian and U.S. GAAP, as the Trust classifies the unit rights plan as equity awards and uses the grant date fair value method to account for its unit compensation expense under Canadian GAAP. Under U.S. GAAP compensation expense was increased by $1.2 million in 2008 ($3.1 million reduction to compensation expense in 2007).

33

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

(D)  Derivative Instruments and Hedging

On January 1, 2007, under Canadian GAAP, the Trust adopted CICA Handbook Section 1530 “Comprehensive Income”, Section 3251 “Equity”, Section 3855 “Financial Instruments – Recognition and Measurement”, Section 3861 “Financial Instruments – Disclosure and Presentation”, and Section 3865 “Hedges”.  These standards were adopted retrospectively and the comparative consolidated financial statements have not been restated. Transitional amounts were recorded in deficit.

Prior to the adoption of the above standards, the Trust applied hedge accounting to its interest rate swap and as such did not record a financial asset or liability relating to the hedging instrument (the swap). Upon adoption of these standards, the Trust chose to discontinue hedge accounting on its interest rate swap and recorded a financial liability on the balance sheet January 1, 2007 with the a corresponding deferred adjustment being recorded as a reduction in the US$ notes.  Changes in the fair value of the swap are recorded in net income.  The deferred loss will be amortized for Canadian GAAP over the life of the notes. Under U.S. GAAP hedge accounting was never applied to the interest rate swap and the U.S. dollar notes and as such the U.S. notes are increased for the remaining deferred adjustment of $3.9 million and interest expense decreased by $0.9 million for the current year accretion of the deferred adjustment ($2.0 million in 2007). The interest rate swap was terminated November 29, 2007. As at December 31, 2008 and December 31, 2007 no additional liability was recorded under U.S. GAAP.

Under Section 3855, physical commodity contracts which are entered into and continue to be held for the purposes of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements are excluded from the requirements of Section 3855 provided the price is not based on a variable that is not closely related to the asset being purchased sold or used and they are documented as such.  Upon the adoption of Section 3855 on January 1, 2007, the Canadian-U.S. GAAP difference has been eliminated and no additional financial asset or liability has been recognized for U.S. GAAP at December 31, 2008 or December 31, 2007.

(E)       Convertible Debentures

Under Canadian GAAP, the Trust’s convertible debentures are classified as debt with a portion, representing the value associated with the conversion feature, being allocated to equity. In addition, under Canadian GAAP a non-cash interest expense representing the effective yield of the debt component is recorded in the consolidated statements of income with a corresponding credit to the convertible debenture liability balance to accrete the balance to the principal due on maturity.

Under U.S. GAAP, the convertible debentures in their entirety are classified as debt.  The non-cash interest expense recorded under Canadian GAAP would not be recorded under U.S. GAAP.  As a result $0.5 million has been reclassified to liabilities from equity ($0.8 million in 2007) and $0.1 million of non-cash interest expense has been reversed ($0.3 million in 2007).

(F)      Step Acquisition on Exchange of Exchangeable shares

Under Canadian GAAP, when the exchangeable shares are exchanged for Trust Units, the transaction is treated as a step acquisition whereby petroleum and natural gas properties are increased by the difference between the fair value of the exchangeable shares and their carrying value, tax effected.  The offset is credited to future tax liability and Trust units.  Under U.S. GAAP the exchangeable shares are considered to be a component of temporary equity and therefore no business combination is considered to have occurred. The cumulative effect of the reversal of the step acquisition is a reduction in petroleum and natural gas properties of $84.4 million (2007 – $14.8 million) and a decrease in future tax liability of $22.1 million (2007 - $5.8 million).

(G) Other Comprehensive Income

Statement of Financial Accounting Standards No. 130 "Comprehensive Income" requires the reporting of comprehensive income in addition to net income. Comprehensive income includes net income plus other comprehensive income. Management has concluded that Baytex has no other comprehensive income; accordingly comprehensive income is equivalent to net income.

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Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

(H)  Deferred Charges

On January 1, 2007 under Canadian GAAP, the Trust adopted Section 3855.  Under this standard, the Trust elected to expense all financial instrument transaction costs immediately.  Transactions costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial asset or financial liability.  Under U.S. GAAP, transaction costs continue to be deferred and amortized over the life of the related asset or liability.  Under U.S. GAAP there is an asset of $2.1 million on the balance sheet as at December 31, 2008 (2007 - $3.0 million).  Additional amortization expense of $0.8 million has been recognized in net income ($1.4 million in 2007).

(I)  Income Taxes

Under U.S. GAAP, enacted tax rates are used to calculate current and future taxes; whereas Canadian GAAP uses substantively enacted tax rates. The future income tax adjustments included in the Reconciliation of Net Income under Canadian GAAP to U.S. GAAP and the Condensed Consolidated Balance Sheet include the effect of such rate differences, if any, as well as the tax effect of the other reconciling items noted.

On January 1, 2007, the Trust adopted for U.S. GAAP purposes, FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”.  The Trust has applied the same guidance in assessing its uncertain tax positions under Canadian GAAP.

Baytex and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions.  The Trust has substantially concluded all Canadian federal and provincial income tax matters for the years through 2004.  Substantially all U.S. federal income tax matters remain open.

(J) Consolidated Statement of Cash Flows

Under U.S. GAAP, separate subtotals within cash flow from operating activities are not presented.

(K) Earnings Per Share

Under Canadian GAAP, basic net income per unit is calculated based on net income after non-controlling interest divided by weighted average units and diluted net income per unit is calculated based on net income before non-controlling interest divided by dilutive units.  Under U.S. GAAP, since the exchangeable shares are classified in the same manner as the trust units, basic net income per unit is calculated based on net income divided by weighted average units and the unit equivalent of the outstanding exchangeable shares.

(L) Business Combinations

Under SFAS 141, “Business Combinations”, supplemental pro forma disclosure is required for significant business combinations occurring during the year.  On June 4, 2008 the Trust completed a business combination as well as on June 26, 2007.  The following unaudited pro forma information provides an indication of what the Trust’s results of operations might have been under U.S. GAAP had the business combination taken place on January 1, of each of the following years:

(unaudited)	2008 Pro Forma			2007 Pro Forma
Oil and gas sales		1,196,599			837,807
Net (loss) income		(281,457	)		158,014
Net (loss) income per trust unit:
Basic	$	(2.96	)	$	1.71
Diluted	$	(2.96	)	$	1.66

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Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

(M) Additional Disclosures

i.  The components of accounts receivable are as follows:

As at December 31	2008			2007
Oil & gas sales and accrual		62,926			83,907
Joint venture		23,755			15,946
Prepaids and deposits		3,280			2,809
Other		-			2,714
Less:  allowance for doubtful accounts		(2,410	)		(200	)
		87,551			105,176

i.  The components of accounts payable are as follows:

As at December 31	2008		2007
Contractors and vendors		76,629		59,601
Accrued liabilities		87,650		44,717
		164,279		104,318

Recent Developments in U.S. Accounting

In February 2007, FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities – Including Amendment of FASB Statement No. 115”, which allows an entity to choose to measure many financial instruments and certain other items at fair value for fiscal years beginning on or after November 15, 2007.  The Company has not been materially impacted by SFAS No. 159.

As of January 1, 2008, the Trust adopted, for U.S. GAAP purposes, SFAS 157, “Fair Value Measurements”.  SFAS 157 provides a common definition of fair value, establishes a framework for measuring fair value under U.S. GAAP and expands disclosures about fair value measurements.  This standard applies when other accounting pronouncements require fair value measurements and does not require new fair value measurements.  The adoption of this standard did not have a material impact on consolidated financial statements of the Trust.

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. This standard became effective November 15, 2008 following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section, 411 “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles”. The statement is intended to improve financial reporting by identifying a consistent hierarchy for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. GAAP.   The adoption of this standard did not have a material impact on the consolidated financial statements of the Trust.

The Trust has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have a significant impact on the Trust:

· As of January 1, 2009, the Trust will be required to adopt, for U.S. GAAP purposes, SFAS 141(R), “Business Combinations”, which replaces SFAS 141.  This revised standard requires assets and liabilities acquired in a business combination, contingent consideration, and certain acquired contingencies to be measured at their fair values as of the date of acquisition.  In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination.  The adoption of this standard will impact the Trust’s U.S. GAAP accounting treatment of business combinations entered into after January 1, 2009.

36

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2008 and 2007

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

· As of January 1, 2009, the Trust will be required to adopt, for U.S. GAAP purposes, SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51”.  This standard requires a noncontrolling interest in a subsidiary to be classified as a separate component of equity.  The standard also changes the way the U.S. GAAP Consolidated Statement of Earnings is presented by requiring net earnings to include the amounts attributable to both the parent and the noncontrolling interest and to disclose these respective amounts.  The adoption of this standard should not have a material impact on the consolidated financial statements of the Trust.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 40-F for the year ended December 31, 2009. Adoption of the new rules may impact results of future ceiling tests for the Trust as the pricing may result in significant difference in future net revenue from reserves.

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