Baytex Energy 40F 2008 Annual report | BTE Filing

Consolidated Financial Statements of & #160; Exhibit 99.2

BAYTEX ENERGY TRUST

December 31, 2007

2MANAGEMENT’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, 2007, 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, 2007 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, 2007.

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) "Raymond T. Chan"		(signed) "W. Derek Aylesworth"
Raymond T. Chan, CA		W. Derek Aylesworth, CA
Chief Executive Officer		Chief Financial Officer
Baytex Energy Ltd.		Baytex Energy Ltd.
March 17, 2008

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, 2007, 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. 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, 2007, 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, 2007 of the Trust and our report dated March 17, 2008 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 17, 2008

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, 2007 and 2006, and the related consolidated statements of income, comprehensive income, deficit and consolidated statements of 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 at December 31, 2007 and 2006, 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 17, 2008, 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, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 17, 2008 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants

Calgary, Canada

March 17, 2008

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 17, 2008, 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 17, 2008


Baytex Energy Trust
Consolidated Balance Sheets
As at December 31,	2007			2006
(thousands of Canadian dollars)
ASSETS
Current assets
Accounts receivable	$	105,176		$	64,716
Crude oil inventory		5,997			9,609
Financial derivative contracts (note 17)		-			3,448
Future income tax asset (note 14)		11,525			-
		122,698			77,773
Deferred charges and other assets		-			4,475
Petroleum and natural gas properties (note 5)		1,246,697			959,626
Goodwill		37,755			37,755
	$	1,407,150		$	1,079,629

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	104,318		$	71,521
Distributions payable to unitholders		15,217			13,522
Bank loan (note 6)		241,748			127,495
Financial derivative contracts (note 17)		34,239			1,055
		395,522			213,593

Long-term debt (note 7)		173,854			209,691
Convertible debentures (note 8)		16,150			18,906
Asset retirement obligations (note 9 )		45,113			39,855
Deferred obligations (note 18)		113			2,391
Future income taxes (note 14)		153,943			118,858
		784,695			603,294
Non-controlling interest (note 11)		21,235			17,187
UNITHOLDERS’ EQUITY
Unitholders’ capital (note 10)		821,624			637,156
Conversion feature of debentures (note 8)		796			940
Contributed surplus (note 12)		18,527			13,357
Deficit		(239,727	)		(192,305	)
		601,220			459,148
	$	1,407,150		$	1,079,629

Commitments and contingencies (note 18)
See accompanying notes to the consolidated financial statements.

On behalf of the Board



Naveen Dargan	Dale O. Shwed
*Director, Baytex Energy Ltd.*	*Director, Baytex Energy Ltd.*

Baytex Energy Trust
Consolidated Statements of Income and Comprehensive Income
Years Ended December 31,	2007			2006
(thousands of Canadian dollars, except per unit data)
Revenue
Petroleum and natural gas sales	$	618,927		$	556,689
Royalties		(102,805	)		(85,043	)
Loss on financial derivatives (note 17)		(34,484	)		(261	)
		481,638			471,385
Expenses
Operating		134,696			112,406
Transportation		28,796			24,346
General and administrative		23,565			20,843
Unit based compensation (note 12)		7,986			7,460
Interest (note 7)		35,242			34,973
Foreign exchange gain (note 15)		(32,494	)		(121	)
Depletion, depreciation and accretion		189,512			152,579
		387,303			352,486
Income before taxes and non-controlling interest		94,335			118,899
Taxes (recovery) (note 14)
Current		6,713			8,414
Future		(49,369	)		(41,169	)
		(42,656	)		(32,755	)

Income before non-controlling interest		136,991			151,654

Non-controlling interest (note 11)		(4,131	)		(4,585	)
Net income / Comprehensive income	$	132,860		$	147,069

Baytex Energy Trust
Consolidated Statements of Deficit
Years Ended December 31,	2007			2006
(thousands of Canadian dollars, except per unit data)

Deficit, beginning of year, as previously reported	$	(192,305	)	$	(181,118	)
Cumulative effect of change in accounting policy (note 3)		(6,215	)		-
Deficit, beginning of year, restated		(198,520	)		(181,118	)
Net income		132,860			147,069
Distributions to unitholders		(174,067	)		(158,256	)
Deficit, end of year	$	(239,727	)	$	(192,305	)

Net income per trust unit (note 13)
Basic	$	1.66		$	2.02
Diluted	$	1.60		$	1.91

See accompanying notes to the consolidated financial statements

Baytex Energy Trust
Consolidated Statements of Cash Flows
Years Ended December 31,	2007			2006
(thousands of Canadian dollars)

CASH PROVIDED BY (USED IN):
Operating activities
Net income	$	132,860		$	147,069
Items not affecting cash:
Unit based compensation (note 12)		7,986			7,460
Amortization of deferred charges		-			1,267
Unrealized foreign exchange gain (note 15)		(32,574	)		(108	)
Depletion, depreciation, and accretion		189,512			152,579
Accretion on debentures and notes (notes 7 & 8)		2,164			189
Unrealized loss on financial derivatives (note 17)		31,320			2,790
Future income tax recovery		(49,369	)		(41,169	)
Non-controlling interest (note 11)		4,131			4,585
		286,030			274,662
Change in non-cash working capital (note 15)		5,140			(9,058	)
Asset retirement expenditures		(2,442	)		(1,747	)
Decrease in deferred charges and other assets		(2,278	)		(1,875	)
		286,450			261,982

Financing activities
Increase in bank loan		114,253			3,907
Issue of trust units, net of issuance costs (note 10)		147,221			8,509
Payments of distributions		(144,609	)		(141,453	)
		116,865			(129,037	)

Investing activities
Petroleum and natural gas property expenditures		(148,719	)		(132,381	)
Corporate acquisition (note 4 )		(243,273	)		-
Acquisition of working capital (note 4)		(13,229	)		-
Acquisition of petroleum and natural gas properties		(2,877	)		(1,530	)
Proceeds on disposal of petroleum and natural gas properties		723			828
Change in non-cash working capital (note 15)		4,060			138
		(403,315	)		(132,945	)

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.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

(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.

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.

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.

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 that 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.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

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 (the “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 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.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

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 for natural gas and crude oil except for products sold pursuant to a long-term crude oil supply contract where title transfer is at the refinery gate.

Financial Instruments

The Trust adopted the CICA Handbook Section 3855 Financial Instruments – Recognition and Measurement on January 1, 2007 (see note 3). Financial instruments are measured at fair value on initial recognition of the instrument. Measurement in subsequent periods depends on whether the financial instrument has been classified as ‘held-for–trading”, “available-for-sale”, “held-to-maturity”, “loans and receivables’, or “other financial liabilities’ as defined by the accounting standard.

Financial assets and financial liabilities “held-for-trading” are measured at fair value with changes in those fair values recognized in net earnings. Financial assets “available-for-sale” are measured at fair value, with changes in those fair values recognized in Other Comprehensive Income (“OCI”). Financial assets “held-to-maturity”, “loans and receivables” and “other financial liabilities” are measured at amortized cost using the effective interest method of amortization.

Cash and cash equivalents are designated as “held-for-trading” and are measured at fair value. Accounts receivable are designated as “loans and receivables”. Accounts payable and accrued liabilities, distributions payable to unitholders, bank loan, long-term debt, deferred obligations and convertible debentures are designated as “other financial liabilities”. The Trust expenses all financial instrument transaction costs immediately.

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 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 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.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

Non-controlling Interest

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’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

Financial Instruments and Hedging Activities

Effective January 1, 2007, the Trust adopted the provisions of the Canadian Institute of Chartered Accountants (“CICA”) section 3855 “Financial Instruments – Recognition and Measurement”, section 3865 “Hedges”, section 1530 “Comprehensive Income”, section 3861 “Financial Instruments – Disclosure and Presentation” and section 3251 “Equity". The Trust has adopted these standards retrospectively and the comparative consolidated financial statements have not been restated. Transitional amounts have been recorded in deficit.

Financial Instruments

A. Classification

All financial instruments must initially be recognized at fair value on the balance sheet. All financial instruments must be classified into one of the following categories: “held for trading financial assets and liabilities”, “loans and receivables”, “held to maturity investments”, “available for sale financial assets” and “other financial liabilities”. Subsequent measurement of the financial instruments is based on their classification.

The Trust has made the following classifications:

·	Cash and cash equivalents are classified as held for trading and are measured at fair value, which approximates carrying value due to the short-term nature of these instruments. A gain or loss arising from a change in the fair value is recognized in net income in the current period.

Accounts receivable are classified as loans and receivables and are initially measured at fair value and subsequently measured at amortized cost using the effective interest rate method. A gain or loss arising from a change in the fair value or the derecognition or impairment of assets is recognized in net income in the period.

Accounts payable and accrued liabilities, distributions payable to unitholders, bank loan, long term debt and deferred obligations have been classified as other financial liabilities and are initially recognized at fair value. Upon issuance, the Trust’s convertible debentures are classified into equity and financial liability components on the balance sheet at their fair value. The financial liability is classified as other financial liabilities. The above instruments are subsequently measured at amortized cost using the effective interest method. A gain or loss is recognized in net income in the period when the financial liability is derecognized or impaired and through the amortization process.

·	All derivative instruments have been classified as held for trading and are measured at fair value. A gain or loss arising from a change in the fair value is recognized in net income in the current period.

The Trust has elected to account for its physical commodity contracts which are entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts rather than as non-financial derivatives. Prior to the adoption of the new standards, physical receipt and delivery contracts did not fall within the scope of the definition of a financial instrument and were accounted for as executory contracts.

B. Transaction Costs

The Trust has elected to expense all financial instrument transaction costs immediately.

C. Effective Interest Method

The Trust uses the effective interest method of amortization for the discount on its convertible debentures and the deferred adjustment on the long-term notes.

D. Embedded Derivatives

Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract if all of the following are met: (1) their economic characteristics and risks are not closely related to the host contract; (2) a separate instrument with similar terms as the embedded derivative would meet the definition of a derivative; and (3) the hybrid instrument is not measured at fair value. The Company has selected January 1, 2007 as its transition date for accounting for any potential embedded derivatives.

Hedge Accounting

On January 1, 2007, the Trust chose to discontinue hedge accounting on its interest rate swap. Effective January 1, 2007 a financial liability was recorded on the balance sheet. Changes in the fair value of the swap were recorded in net income.

Comprehensive Income

Comprehensive income consists of net earnings and other comprehensive income (“OCI”). OCI includes gains and losses on derivatives designated as cash flow hedges, gains and losses arising from changes in fair value of available for sale assets and unrealized gains and losses on translating financial statements of self sustaining foreign operations, all net of tax. Accumulated other comprehensive income is a new equity category comprised of cumulative OCI. The Trust has not engaged in any transactions giving rise to OCI as of December 31, 2007.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

Transitional Adjustment

The impact of adopting these standards as at January 1, 2007 is as follows:

	As at December 31, 2006			Adjustment Upon Adoption of New Standards			As at January 1, 2007
Assets
Deferred charges	$	4,475		$	(4,475	)	$	-

Liabilities
Financial derivative contracts		1,055			5,976			7,031
Long term debt		209,691			(5,976	)		203,715
Future income taxes		118,858			(1,265	)		117,593
					(1,265	)

Unitholders’ Equity
Unitholders’ capital		637,156			3,005			640,161
Deficit		(192,305	)		(6,215	)		(198,520	)
					(3,210	)
				$	(4,475	)

Accounting Changes

Effective January 1, 2007, the Trust adopted the recommendation of CICA revised section 1506 “Accounting Changes”. The new standard provides clarification on the criteria for changes in accounting policies as well as the accounting treatment and disclosure of changes in accounting policies, changes in estimates and corrections of errors.

Future Accounting Changes

On December 1, 2006, the CICA issued three new accounting standards:

Handbook Section 1535, Capital Disclosures, Section 3862, Financial instruments - Disclosures, and Section 3863, Financial instruments - Presentation. These new standards will be effective on January 1, 2008.

Section 1535 specifies the disclosure of an entity's objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and if it has not complied, the consequences of such non-compliance. This Section is expected to have minimal impact on the Trust's financial statements.

Sections 3862 and 3863 specify a revised and enhanced disclosure on financial instruments. Increased disclosure will be required on the nature and extent of risks arising from financial instruments and how the entity manages those risks.

In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets, which replaces Sections 3062, Goodwill and Other Intangible Assets and 3450, Research and Development Costs. This section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets by profit-oriented enterprises subsequent to their initial measurement. The new standard will be effective on January 1, 2009. The Trust does not expect the adoption of this new Section to have a material impact on its consolidated financial statements.

In January 2006, the CICA Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards (“IFRSs”). In March 2007, the AcSB released an “Implementation Plan for Incorporating IFRSs into Canadian GAAP”, which assumes a convergence date of January 1, 2011. Following a progress review on February 13, 2008, the AcSB has confirmed this changeover date. The Trust continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.

4. CORPORATE ACQUISITION

On June 26, 2007, Baytex acquired all the issued and outstanding shares of a private company which has 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 acquisition on June 26, 2007. Subsequent to the acquisition, the private company 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
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

Amendments may be made to the purchase equation as the cost estimates and balance are finalized.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

5. PETROLEUM AND NATURAL GAS PROPERTIES

	As at December 31
	2007			2006

Petroleum and natural gas properties	$	3,074,014		$	2,600,834
Accumulated depletion and depreciation		(1,827,317	)		(1,641,208	)
	$	1,246,697		$	959,626

In calculating the depletion and depreciation provision for 2007, $65.0 million (2006 - $34.3 million) of costs relating to undeveloped properties were excluded from costs subject to depletion and depreciation. No general and administrative expenses have been capitalized since the inception of operations as a trust.

The net book value of petroleum and natural gas properties are subject to a ceiling test, which was calculated at December 31, 2007 using the following benchmark reference prices for the years 2008 to 2012 adjusted for commodity differentials specific to the Trust (notes 17 & 18):

	2008	2009	2010	2011	2012
WTI crude oil (US$/bbl)	89.61	86.01	84.65	82.77	82.26
AECO natural gas ($/MMBtu)	6.51	7.22	7.69	7.70	7.61

The prices and costs subsequent to 2012 have been adjusted for estimated inflation at an estimated annual rate of 2.0 percent. Based on the ceiling test calculation, the Trust’s estimated undiscounted future net cash flows associated with proved reserves plus the cost less impairment of unproved properties exceeded the net book value of the petroleum and natural gas properties.

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 18) 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. On June 26, 2007 the credit facility was amended, increasing the aggregate amount to $370 million from $300 million. The credit facilities are subject to semi-annual review and are secured by a floating charge over all of the Company’s assets. At December 31, 2007 a total of $241.7 million were drawn under the credit facilities (December 31, 2006 - $127.5 million).

7. LONG-TERM DEBT

	As at December 31
	2007			2006
10.5% senior subordinated notes (US$247)	$	244		$	288
9.625% senior subordinated notes (US$179,699)		177,561			209,403
		177,805			209,691
Discontinued fair value hedge		(3,951	)		-
	$	173,854		$	209,691

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

Senior Subordinated Notes

The Company has US$247,000 senior subordinated notes bearing interest at 10.5 percent payable semi-annually with principal repayable on February 15, 2011. These notes are unsecured and are subordinate to the Company’s bank credit facilities.

US$179.7 million of 9.625 percent senior subordinated notes due July 15, 2010 are unsecured and are subordinate to the Company’s bank credit facilities. After July 15 of 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): 2007 at 104.813 percent, 2008 at 102.406 percent, 2009 and thereafter at 100 percent. These notes are carried at amortized cost net of a discontinued fair value hedge of $6.0 million recorded on adoption of Section 3865 (note 3). The notes will accrete up to the principal balance at maturity using the effective interest method. $2.0 million of accretion expense has been recorded for 2007. The effective interest rate is 10.666%. The Company entered into an interest rate swap contract converting the fixed rate to a floating rate reset quarterly at the three-month LIBOR rate plus 5.2 percent until the maturity of these notes (note 17). On November 29, 2007 the Company unwound the interest rate swap contract. A gain on termination of $2.0 million has been recorded reducing interest expense.

Interest Expense

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

	2007		2006
Bank loan and miscellaneous financing	$	13,376	$	9,276
Amortization of deferred charges		-		1,267
Convertible debentures		1,295		2,614
Long-term debt		20,571		21,816
Total interest	$	35,242	$	34,973

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

8. CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES

On June 6, 2005 the Trust issued $100 million principal amount of 6.5 percent 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 7.57% 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.

	Number of Debentures			Convertible Debentures			Conversion Feature of Debentures
Balance, December 31, 2005		77,152		$	73,766		$	3,698
Conversion		(57,533	)		(55,049	)		(2,758	)
Accretion		-			189			-
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

9. ASSET RETIREMENT OBLIGATIONS

	As at December 31,
	2007			2006
Balance, beginning of year	$	39,855		$	33,010
Liabilities incurred		2,180			1,199
Liabilities settled		(2,442	)		(1,747	)
Acquisition of liabilities		2,239			-
Disposition of liabilities		(585	)		(122	)
Accretion		3,404			2,678
Change in estimate⁽¹⁾		462			4,837
Balance, end of year	$	45,113		$	39,855

⁽¹⁾ The 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 52 years. The undiscounted amount of estimated cash flow required to settle the retirement obligations at December 31, 2007 is $268 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.

10. UNITHOLDERS’ CAPITAL

Trust Units

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

Trust Units	Number of units		Amount
Balance, December 31, 2005		69,283	$	555,020
Issued on conversion of debentures		3,901		54,798
Issued on conversion of exchangeable shares		34		720
Issued on exercise of trust unit rights		1,250		8,509
Transfer from contributed surplus on exercise of trust unit rights		-		4,435
Issued pursuant to distribution reinvestment program		654		13,674
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 program		1,464		27,763
Cumulative effect of change in accounting policy (Note 3 )		-		3,005
Balance, December 31, 2007		84,540	$	821,624

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 cash 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 calculated monthly based on the cash distribution paid divided by the weighted average trust unit price for the five-day trading period ending on the record date. The exchange ratio at December 31, 2007 was 1.67915 trust units per exchangeable share (2006 – 1.51072 trust units per exchangeable share). 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.

	Number of Exchangeable Shares			Amount
Balance, December 31, 2005		1,597		$	12,810
Exchanged for trust units		(24	)		(208	)
Non-controlling interest in net income		-			4,585
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

As the exchangeable shares are converted to trust units, the exchange is accounted for as a step-acquisition whereby 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.

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% 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 units will result in an increase in the available number of trust units issuable under the plan, and any exercises of incentive 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 $8.0 million for the year ended December 31, 2007 ($7.5 million in 2006) related to the rights granted under the plan.

Effective January 1, 2006, the Trust has commenced using the binomial-lattice model to calculate the estimated weighted average fair value of $3.87 per unit for rights issued during 2007 ($4.34 per unit in 2006) . The following assumptions were used to arrive at the estimate of fair values:

	2007			2006
Expected annual right’s exercise price reduction	$	2.16		$	2.16
Expected volatility		28	%		23%-28	%
Risk-free interest rate		3.77%-4.50	%		3.54%-4.45	%
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.

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

	Number of rights			Weighted average exercise price ⁽¹⁾
Balance, December 31, 2005		5,366		$	10.88
Granted		2,443		$	21.66
Exercised		(1,250	)	$	6.81
Cancelled		(246	)	$	11.54
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

⁽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, 2007:

Range of Exercise Prices		Number Outstanding at December 31, 2007		Weighted Average Remaining Term		Weighted Average Exercise Price		Number Exercisable at December 31, 2007		Weighted Average Exercise Price
				(years)
$	1.09 to $ 4.50		551		0.7	$	2.27		551	$	2.27
$	4.51 to $ 8.00		771		1.9	$	6.19		745	$	6.15
$	8.01 to $11.50		1,495		2.8	$	10.23		923	$	10.31
$	11.51 to $15.00		450		3.0	$	12.86		169	$	12.56
$	15.01 to $18.50		477		4.1	$	17.77		78	$	17.73
$	18.51 to $21.89		3,918		4.3	$	19.61		551	$	19.94
$	1.09 to $21.89		7,662		3.4	$	14.67		3,017	$	9.89

The following table summarizes the changes in contributed surplus:


Balance, December 31, 2005	$	10,332
Compensation expense		7,460
Transfer from contributed surplus on exercise of trust unit rights ⁽¹⁾		(4,435	)
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

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

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

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:

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

2006	Net income		Trust units		Net income per trust unit
Net income per basic unit	$	147,069		72,947	$	2.02
Dilutive effect of trust unit rights		-		2,592
Conversion of convertible debentures		1,647		2,515
Exchange of exchangeable shares		4,585		2,384
Net income per diluted unit	$	153,301		80,438	$	1.91

The dilutive effect of trust unit incentive rights for the year ended December 31, 2007 did not include 4.1 million trust unit rights (2006 – 2.1 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. INCOME TAXES (RECOVERY)

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

	2007			2006
Income before income taxes and non-controlling interest	$	94,335		$	118,899
Expected income taxes at the statutory rate of 34.02% (2006 – 37.00%)		32,094			43,992
Increase (decrease) in taxes resulting from:
Resource allowance		-			(11,236	)
Alberta royalty tax credit		-			(110	)
Net income of the Trust		(62,615	)		(56,261	)
Non-taxable portion of foreign exchange gain		(5,424	)		(20	)
Effect of change in tax rate		(15,806	)		(26,218	)
Effect of change in opening tax pool balances		(834	)		3,451
Effect of change in valuation allowance		2,075			1,597
Unit based compensation		2,717			2,760
Other		(1,576	)		876
Recovery of taxes		(49,369	)		(41,169	)
Current taxes		6,713			8,414
Total tax	$	(42,656	)	$	(32,755	)

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 legislation becoming enacted an additional future tax recovery of $0.5 million has been recorded.

The net future income tax liability is comprised of the following:
	As at December 31
	2007			2006
Future income tax liabilities:
Petroleum and natural gas properties	$	155,921		$	136,955
Other		18,271			10,019
Future income tax assets:
Asset retirement obligations		(11,796	)		(11,987	)
Loss carry-forward ⁽¹⁾		(8,058	)		(12,049	)
Other		(11,920	)		(4,080	)
Net future income tax liability		142,418			118,858
Current portion of net future income tax asset		(11,525	)		-
Long-term portion of net future income tax liability	$	153,943		$	118,858

⁽¹⁾$41million of the loss carry-forward to expire in 2014, $18 million to expire in 2015 and $3 million in 2016.

15. SUPPLEMENTAL INFORMATION

Change in Non-Cash Working Capital Items

	2007			2006
Current assets	$	(23,619	)	$	9,525
Current liabilities		32,819			(18,445	)
	$	9,200		$	(8,920	)
Changes in non-cash working capital related to:
Operating activities	$	5,140		$	(9,058	)
Investing activities		4,060			138
	$	9,200		$	(8,920	)

Supplemental Cash Flow Information

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

	2007		2006
Interest	$	32,321	$	32,373
Current income taxes	$	9,436	$	7,636

Foreign Exchange Gains

	2007			2006
Unrealized foreign exchange gain	$	32,574		$	108
Realized foreign exchange gain (loss)		(80	)		13
Total foreign exchange gain	$	32,494		$	121

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

16. FINANCIAL INSTRUMENTS

The Trust’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, accounts receivable, current liabilities, financial derivatives and long-term borrowings. 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 estimated fair values of the financial instruments have been determined based on the Trust’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction. The fair value of the bank debt approximates its book value as it is at a market rate of interest. At December 31, 2007, the trading value of the Company’s senior subordinated term notes was 102 percent in relation to par (2006 - 106 percent). The market value of the Trust’s convertible debentures at December 31, 2007 was 125 percent in relation to par (2006 - 146 percent).

(a) Credit Risk

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. The book value of the accounts receivable reflects management’s assessment of the associated credit risks.

(b) Interest Rate Risk

The Trust is exposed to movements in interest rates. Debt is comprised of both variable rate bank facilities and fixed rate senior notes. The Trust manages interest by utilizing appropriate interest rate swaps and fixed rate notes.

The Trust is exposed to fluctuations in foreign currency as a result of its U.S. dollar denominated notes and crude oil sales based on U.S. dollar indices. These two factors function somewhat as a natural hedge. From time to time, we may also enter into agreements to fix the exchange rate of Canadian to United States dollar in order to lessen the impact of currency rate fluctuations.

(d) Commodity Risk

Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control. We manage the risk associated with changes in commodity prices by utilizing price swaps for oil and price collars for natural gas.

17. FINANCIAL DERIVATIVE CONTRACTS

The nature of the Trust’s operations results in exposure to fluctuations in commodity prices, exchange rates and interest rates. The Trust monitors and, when appropriate, utilizes derivative contracts to manage its exposure to these risks. The Trust is exposed to credit-related losses in the event of non-performance by counter-parties to these contracts.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

At December 31, 2007, the Trust had the following derivative contracts:

OIL
	Period	Volume	Price	Index
Price collar	Calendar 2008	2,000 bbl/d	US$60.00 – $80.25	WTI
Price collar	Calendar 2008	2,000 bbl/d	US$65.00 – $77.05	WTI
Price collar	Calendar 2008	2,000 bbl/d	US$65.00 – $80.10	WTI

FOREIGN CURRENCY
		Period	Amount	Strike Price
Swap	January 1, 2008 to June 30, 2008		US$10,000,000 per month	CAD/US$0.9935

This contract is extendable on similar terms on June 30, 2008, at the option of the counterparty, for a further six months to the end of 2008.

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


	2007			2006
Realized gain (loss) on financial derivatives	$	(3,164	)	$	2,529
Unrealized loss on financial derivatives		(31,320	)		(2,790	)
Loss on financial derivatives	$	(34,484	)	$	(261	)

18. COMMITMENTS AND CONTINGENCIES

In 2007, the Trust entered into long-term crude oil supply contracts with third parties that require the delivery of 15,340 barrels per day of crude oil in 2008 and 10,340 in 2009. The details of these contracts are:


HEAVY OIL	Period	Volume	Price
Price Swap – WCS Blend	Calendar 2008	13,340 bbl/d	WTI x 67.1% (weighted average)
Price Swap – LLB Blend	Calendar 2008	2,000 bbl/d	WTI less US$24.55
Price Swap – WCS Blend	Calendar 2009	10,340 bbl/d	WTI x 67.0% (weighted average)

At December 31, 2007, the Trust had the following natural gas physical sales contracts:


GAS	Period	Volume	Price
Price collar	January 1 to March 31, 2008	2,500 GJ/d	$	6.65 - $8.60
Price collar	January 1 to March 31, 2008	2,500 GJ/d	$	6.65 - $9.00
Price collar	January 1 to March 31, 2008	2,500 GJ/d	$	6.65 - $8.05
Price collar	Calendar 2008	5,000 GJ/d	$	6.15 - $7.00
Price collar	Calendar 2008	5,000 GJ/d	$	6.15 - $7.46

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

Subsequent to December 31, 2007, the Trust added the following natural gas physical sales contracts:


GAS	Period	Volume	Price
Price collar	April 1, 2008 to October 31, 2008	5,000 GJ/d	$	6.15 - $7.50
Price collar	April 1, 2008 to October 31, 2008	2,500 GJ/d	$	6.15 - $9.35

At December 31, 2007, the Trust had operating lease and transportation obligations as summarized below:

OPERATING LEASES AND TRANSPORTATION AGREEMENTS
			Payments Due
	Total		1 year		2 years		3 years		4 years		5 years
Operating leases	$	5,983	$	2,459	$	2,435	$	883	$	124	$	82
Transportation agreements		22,364		6,537		5,708		5,213		4,825		81
Total	$	28,347	$	8,996	$	8,143	$	6,096	$	4,949	$	163

OTHER

At December 31, 2007, there are outstanding letters of credit aggregating $4.9 million (2006 - $7.3 million) issued as security for performance under certain contracts.

The Company has future contractual processing obligations with respect to assets acquired. The fair value ($7.8 million) of the original obligation is being drawn down over the life of the obligations which continue until October 2008. The fair value of the remaining obligation at December 31, 2007 was $2.4 million, all of which was included in current liabilities.

In connection with a purchase of properties, 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, 2007, an additional $0.7 million was paid for year two’s obligations ($0.5 million was paid for year one) under the agreement and has 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.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

(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		2007			2006
Net Income – Canadian GAAP	Note	$	132,860		$	147,069
Increase (Decrease) Under U.S. GAAP
Unrealized gain/(loss) on derivative instruments	D		(1,168	)		2,408
Depletion, depreciation and accretion	A, H		34,741			8,795
Interest	D		2,351			(548	)
Unit based compensation	C		3,149			(28,156	)
Income tax expense	A,D,H,I		(16,703	)		(13,426	)
Non-controlling interest	B		4,131			4,585
Net Income before cumulative effect of a change in accounting policy			159,361			120,727
Cumulative effect of a change in accounting policy	C		-			1,544
Net Income – U. S. GAAP		$	159,361		$	122,271


Net income per trust unit before cumulative effect of change in accounting policy	K
Basic		$	1.93		$	1.60
Diluted		$	1.86		$	1.52

Cumulative effect of change in accounting policy	K
Basic		$	-		$	0.02
Diluted		$	-		$	0.02

Net income per trust unit	K
Basic		$	1.93		$	1.62
Diluted		$	1.86		$	1.54

Weighted average trust units	K
Basic			82,659			75,331
Diluted			85,975			80,438

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

(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		2007			2006
	Note
Revenue
Petroleum and natural gas sales, net of royalties		$	516,122		$	471,646
Gain (loss) on financial derivatives	D		(35,652	)		2,147
			480,470			473,793

Expenses
Operating	C		135,700			116,303
Transportation			28,796			24,346
General and administrative	C		27,398			52,562
Interest	D		32,891			35,521
Foreign exchange gain			(32,494	)		(121	)
Depletion, depreciation and accretion	A,H		154,771			143,784
			347,062			372,395
Income before income taxes and cumulative effect of change in accounting policy			133,408			101,398
Current			6,713			8,414
Future	A,D,H,I		(32,666	)		(27,743	)
Income tax recovery			(25,953	)		(19,329	)

Cumulative effect of change in accounting policy	C		-			1,544
Net Income / Comprehensive Income		$	159,361		$	122,271



Consolidated Statement of Accumulated Deficit
For the years ended December 31		2007			2006
	Note
Deficit, beginning of the year		$	(1,403,144	)	$	(1,002,232	)
Net Income			159,361			122,271
Distributions to Unit holders			(174,067	)		(158,256	)
Adjustment for fair value of Temporary Equity	B		258,449			(364,927	)
Deficit, end of the year		$	(1,159,401	)	$	(1,403,144	)

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

Condensed Consolidated Balance Sheet

As at December 31		2007						2006
		As Reported			US GAAP			As Reported			US GAAP
	Note
Assets
Current Assets	D,I	$	122,698		$	122,674		$	77,773		$	78,961
Petroleum and natural gas properties	F		3,074,014			3,058,163			2,600,834			2,585,196
Accumulated depletion and depreciation	A		(1,827,317	)		(1,929,982	)		(1,641,208	)		(1,779,999	)
Petroleum and natural gas properties			1,246,697			1,128,181			959,626			805,197
Deferred charges and other assets	K		-			3,016			4,475			4,475
Goodwill			37,755			37,755			37,755			37,755
		$	1,407,150		$	1,291,626		$	1,079,629		$	926,388

Liabilities and Unitholders’ Equity
Current Liabilities	D	$	395,522		$	395,522		$	213,593		$	219,589
Long Term Debt	D		173,854			177,805			209,691			209,691
Convertible Debentures	E		16,150			16,620			18,906			19,846
Deferred Obligations			113			113			2,391			2,391
Asset Retirement Obligation			45,113			45,113			39,855			39,855
Share-Based Payment Liability			-			35,909			-			40,723
Future Income Taxes	A,D,H,I		153,943			123,737			118,858			70,775
			784,695			794,819			603,294			602,870

Non-controlling Interest	B		21,235			-			17,187			-
Temporary Equity			-			1,656,208			-			1,726,662

Unitholders’ Capital	B		821,624			-			637,156			-
Conversion Feature of Debentures	E		796			-			940			-
Contributed Surplus	B,C		18,527			-			13,357			-
Deficit			(239,727	)		(1,159,401	)		(192,305	)		(1,403,144	)
			601,220			(1,159,401	)		459,148			(1,403,144	)
		$	1,407,150		$	1,291,626		$	1,079,629		$	926,388

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

(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	2007			2006

Operating Activities
Net income	$	159,361		$	122,271
Unit based compensation		4,837			35,616
Amortization of deferred charges		1,385			1,267
Unrealized foreign exchange gain		(32,574	)		(108	)
Depletion, depreciation and accretion		153,199			143,973
Unrealized (gain) loss on financial derivatives		32,488			930
Future income taxes		(32,666	)		(27,743	)
Change in non-cash working capital		5,140			(9,058	)
Asset retirement expenditures		(2,442	)		(1,747	)
Decrease in deferred charges and other assets		(2,278	)		(1,875	)
Cumulative effect of change in accounting policy		-			(1,544	)
Cash from Operations	$	286,450			261,982

Cash Used in Investing Activities	$	(403,315	)	$	(132,945	)

Cash (Used) From Financing Activities	$	116,865		$	(129,037	)

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 earnings 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.

Effective January 1, 2004, the Trust adopted changes to the Canadian Institute of Chartered Accountants (“CICA”) Full Cost Accounting Guidelines. Under Canadian GAAP, depletion is calculated by reference to proved reserves estimated using forecast prices and costs. Under U.S. GAAP, depletion charges are calculated by reference to proved reserves estimated using constant prices and costs. The difference in proved reserves has resulted in $36.1 million less depletion record under U.S. GAAP for the year ended December 31, 2007 ($8.8 million less depletion – 2006).

(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 carried on the consolidated balance sheets at their redemption value.

In applying EITF D-98 the Trust has recorded Temporary Equity in the amount of $1,656.2 million as at December 31, 2007 and $1,726.7 million as at December 31, 2006 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 a credit of $258.4 million for 2007 and a charge of $364.9 million for 2006.

Under Canadian GAAP, the exchangeable shares of the Company 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.

(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. Prior to 2006 the unit rights had been classified as equity awards and as such a cumulative adjustment for a change in accounting policy has been made to net income for $1.5 million in 2006. 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 reduced by $3.1 million in 2007 ($28.2 million of additional compensation expense was recorded in 2006).

(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”(“3855”) 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 discontinued fair value hedge recorded as a reduction in the US$ notes. Changes in the fair value of the swap are recorded in net income. The discontinued fair value hedge will be amortized for Canadian GAAP purposes 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 discontinued fair value hedge balance of $3.9 million and interest expense decreased by $2.0 million for the current year accretion of the discontinued fair value hedge. The interest rate swap was terminated November 29, 2007. As at December 31, 2007 no additional liability was recorded under U.S. GAAP (December 31, 2006 – additional liability of $6.0 million)

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 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.

In prior years, under U.S. GAAP, physical commodity contracts where considered to be derivative instruments under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133) as no documentation was in place identifying that the assets constitutes normal purchases or normal sales of the Trust. With the adoption of Section 3855 under Canadian GAAP the Canadian-U.S. GAAP difference has been eliminated an no additional financial asset or liability has been recognized for US GAAP at December 31, 2007 (December 31, 2006 – additional asset of $1.2 million). An unrealized loss on derivative contracts of $1.2 million has been recognized for U.S. GAAP due to the recognition of a financial asset and financial liability on physical commodity contracts in prior years.

(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, undere 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 $0.8 million has been reclassified to liabilities from equity and $326 of non-cash interest expense has been reversed.

(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 component of temporary equity and therefore no business combination is considered to have occurred. The cumulative effect of the reversal of the step acquisitions is a reduction in petroleum and natural gas properties of $14.8 million (2006 – $16.6 million) and a decrease in future tax liability of $5.8 million (2006 - $6.3 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.

(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 an asset of $3.0 million has been recorded on the balance sheet as at December 31, 2007. Additional amortization expense has been recognized in net income for $1.4 million.

(I) Future Income Taxes

Under U.S. GAAP, enacted tax rates are used to calculate 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” (“FIN 48”). The methodology used for Canadian GAAP financial reporting did not result in a significant difference from the application of FIN 48.

(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.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2007 and 2006

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

(L) Business Combinations

Under SFAS 141, “Business Combinations”, supplemental pro forma disclosure is required for significant business combinations occurring during the year. On June 26, 2007 the Trust completed a business combination. 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)	2007 Pro Forma		2006 Pro Forma
Oil and gas sales	$	667,043	$	627,380
Net income	$	160,192	$	118,208
Net income per trust unit:
Basic	$	1.86	$	1.44
Diluted	$	1.80	$	1.37

(L) Additional Disclosures

i. The components of accounts receivable are as follows:

As at December 31	2007			2006
Oil & Gas Sales and Accrual	$	83,907		$	52,948
Joint Venture		15,946			8,560
Prepaids and deposits		2,809			1,965
Other		2,714			1,562
Less: Allowance for Doubtful Accounts		(200	)		(319	)
	$	105,176		$	64,716

ii. The components of accounts payable are as follows:

As at December 31	2007		2006
Contractors and Vendors	$	59,601	$	39,414
Accrued Liabilities		44,717		32,107
	$	104,318	$	71,521

Recent Developments in U.S. Accounting

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, 2008, the Trust will be required to adopt, 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 should not have a material impact on

the Consolidated Financial Statements.

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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	7th grade Avg

Baytex Energy (BTE) 40-F2008 FY Annual report (Canada)

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