Baytex Energy (BTE) 40-F 2005 FY Annual report (Canada)

Exhibit 99.2

Consolidated Financial Statements of

BAYTEX ENERGY TRUST

December 31, 2005

Management’s Report

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 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 auditors 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.

/s/ Raymond T. Chan	/s/ W. Derek Aylesworth
Raymond T. Chan, CA	W. Derek Aylesworth, CA
President and Chief Executive Officer	Chief Financial Officer
Baytex Energy Ltd.	Baytex Energy Ltd.
March 7, 2006

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 consolidated balance sheets of Baytex Energy Trust (the “Trust”) as at December 31, 2005 and 2004 and the consolidated statements of operations and accumulated income (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the management of the Trust. 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. Those standards require that we plan and perform an audit to obtain reasonable assurance 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 consolidated financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2005 and 2004 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.

On March 7, 2006, we reported separately to the Unitholders of Baytex Energy Trust on the consolidated financial statements for the same period, prepared in accordance with Canadian generally accepted accounting principles but which excluded Note 19, Differences Between Canadian and United States Generally Accepted Accounting Principles.

	(signed) “Deloitte & Touche LLP”
Calgary, Alberta, Canada	Independent Registered Chartered Accountants

March 7, 2006

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

The standards of the Public Company Accounting Oversight Board  (United States) require the addition of an explanatory paragraph (following the opinion paragraph) when there has been a restatement of the financial statements as described in Notes 3 and 19 to the financial statements that have a material effect on the Trust’s consolidated financial statements. Our report to the Unitholders, dated March 7, 2006 is expressed in accordance with Canadian reporting standards which do not require a reference to such conditions and events in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

	(signed) “Deloitte & Touche LLP”
Calgary, Alberta, Canada	Independent Registered Chartered Accountants

March 7, 2006

Baytex Energy Trust

Consolidated Balance Sheets

As at December 31, 2005 and 2004

(thousands)

	2005			2004
				(restated – note 3)
ASSETS
Current assets
Accounts receivable	$	73,869		$	41,154
Crude oil inventory	9,984			7,299
Financial derivative contracts (note 17)	5,183			—
	89,036			48,453
Deferred charges and other assets	9,038			6,491
Petroleum and natural gas properties (note 5)	969,738			1,009,933
Goodwill (note 4)	37,755			39,259
	$	1,105,567		$	1,104,136
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	89,966		$	72,976
Distributions payable to unitholders	10,393			9,981
Bank loan (note 6)	123,588			161,444
Financial derivative contracts (note 17)	—			9,513
	223,947			253,914
Long-term debt (note 7)	209,799			216,583
Convertible debentures (note 8)	73,766			—
Asset retirement obligation (note 9)	33,010			73,297
Deferred obligations (note 18)	4,558			—
Future income taxes (note 14)	159,745			164,909
	704,825			708,703
Non-controlling interest (note 11)	12,810			12,936
UNITHOLDERS’ EQUITY
Unitholders’ capital (note 10)	555,020			515,663
Conversion feature of debentures (note 8)	3,698			—
Contributed surplus	10,332			6,287
Accumulated distributions	(267,986		)	(146,445		)
Accumulated income	86,868			6,992
	387,932			382,497
	$	1,105,567		$	1,104,136

Commitments and contingencies (note 18)

See accompanying notes to the consolidated financial statements.

On behalf of the Board

/s/ Naveen Dargan	/s/ W. A. Blake Cassidy
Naveen Dargan	W. A. Blake Cassidy
Director	Director
Baytex Energy Ltd.	Baytex Energy Ltd.

Baytex Energy Trust

Consolidated Statements of Operations and Accumulated Income (Deficit)

Years Ended December 31, 2005 and 2004

(thousands, except per unit data)

	2005			2004
				(restated — note 3)
Revenue
Petroleum and natural gas sales	$	546,940		$	420,400
Royalties	(81,898		)	(65,988		)
Realized loss on financial derivatives	(48,462		)	(78,124		)
Unrealized gain on financial derivatives	14,696			597
	431,276			276,885
Expenses
Operating	110,648			89,078
Transportation	22,399			18,714
General and administrative	16,010			15,243
Unit based compensation (note 12)	5,346			4,646
Interest (note 7)	33,124			19,412
Foreign exchange gain (note 7)	(6,784		)	(15,979		)
Depletion, depreciation and accretion	167,135			160,808
	347,878			291,922
Income (loss) before income taxes and non-controlling interest	83,398			(15,037		)
Income taxes (recovery) (note 14)
Current	8,747			9,000
Future	(7,074		)	(41,237		)
	1,673			(32,237		)
Income before non-controlling interest	81,725			17,200
Non-controlling interest (note 11)	(1,849		)	(436		)
Net income	79,876			16,764
Accumulated income (deficit), beginning of year, as previously reported	5,694			(8,069		)
Accounting policy change for Unit based compensation (note 3)	1,298			(1,703		)
Accumulated income (deficit), beginning of year, as restated	6,992			(9,772		)
Accumulated income, end of year	$	86,868		$	6,992
Net income per trust unit (note 13)
Basic	$	1.19		$	0.27
Diluted	$	1.15		$	0.26

See accompanying notes to the consolidated financial statements.

Baytex Energy Trust

Consolidated Statements of Cash Flows

Years Ended December 31, 2005 and 2004

(thousands)

	2005			2004
				(restated – note 3)
CASH PROVIDED BY (USED IN):
Operating activities
Net income	$	79,876		$	16,764
Items not affecting cash:
Unit based compensation (note 12)	5,346			4,646
Amortization of deferred charges	1,492			11,171
Unrealized foreign exchange gain	(6,784		)	(15,979		)
Depletion, depreciation and accretion	167,135			160,808
Accretion on debentures (note 8)	321			—
Unrealized gain on financial derivatives (note 17)	(14,696		)	(597		)
Future income taxes (recovery)	(7,074		)	(41,237		)
Non-controlling interest (note 11)	1,849			436
	227,465			136,012
Change in non-cash working capital (note 15)	(20,212		)	3,589
Asset retirement expenditures	(1,637		)	(2,739		)
Decrease in deferred charges and other assets	(977		)	212
	204,639			137,074
Financing activities
Issuance of convertible debentures (note 8)	100,000			—
Convertible debentures issue costs (note 8)	(4,250		)	—
Increase (decrease) in bank loan	(37,856		)	161,444
Issue of trust units (note 10)	2,916			44,505
Payments of distributions	(114,221		)	(112,074		)
	(53,411		)	93,875
Investing activities
Petroleum and natural gas property expenditures	(201,478		)	(184,065		)
Corporate acquisition (note 4)	—			(111,042		)
Proceeds on disposal of petroleum and natural gas properties	49,029			14,441
Change in non-cash working capital (note 15)	1,221			(4,014		)
	(151,228		)	(284,680		)
Change in cash and short-term investments during the year	—			(53,731		)
Cash and short-term investments, beginning of year	—			53,731
Cash and short-term investments, end of year	$	—		$	—

See accompanying notes to the consolidated financial statements.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2005 and 2004

(all tabular amounts in thousands, except per unit amounts)

1.BASIS OF PRESENTATION

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

2.SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The consolidated financial statements include the accounts of the Trust and its subsidiaries from the respective dates of acquisition of the subsidiary companies.  Inter-company transactions and balances are eliminated upon consolidation.

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 revenues 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 reserve 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 Short-term Investments

Cash and short-term investments include monies on deposit and short-term investments, accounted for at cost, which have an initial maturity date of not more that 90 days.

Crude Oil Inventory

Crude oil inventory, consisting of production in transit in pipelines at the balance sheet date pursuant to a long-term crude oil supply agreement, is valued at the lower of cost or net realizable value.

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 in one Canadian cost centre 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 to be 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 for accounting purposes 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 reporting entity.  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 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. Issue costs will be amortized over the term of the debentures, and the debt portion will accrete up to the principal balance at maturity. The accretion, amortization of issue costs and the interest paid are expensed as interest expense in the consolidated statements of operations. 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 Obligation

The Trust recognizes a liability at discounted fair value for the future abandonment and reclamation costs associated with the petroleum and natural gas properties.  The fair 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 operations.  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.  Differences between the actual costs incurred and the fair value of the liability recorded are recognized in income in the period the actual costs are incurred.

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

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.

Deferred Charges and Other Assets

Financing costs related to the exchange of the senior subordinated notes have been deferred and are amortized over the term of the notes on a straight-line basis.

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 at the wellhead for crude oil.

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 policies included the permitted use of derivative financial instruments, including swaps and collars, used to manage these fluctuations.  All transactions of this nature entered into by the Trust are related to an underlying financial instrument or to future petroleum and natural gas production.  The Trust does not use financial derivatives for trading or speculative purposes.  Financial derivative contracts used as hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective in order to continue accrual accounting for positions hedged with financial derivative contracts.  Financial derivative contracts that do not qualify for hedge accounting are recognized in the balance sheet and measured at fair value, with changes in fair value reported separately in the statement of operations as income or expense.

Future Income Taxes

The Trust is a unit trust for income tax purposes, and is taxable on taxable income not allocated to the unitholders.  From inception on September 2, 2003, the Trust has allocated all of its taxable income to the unitholders, and accordingly, no provision for income taxes is required at the Trust level.

The Company is subject to corporate income taxes and follows the liability method of accounting for income taxes.  Income taxes are accounted for under the liability method of tax allocation, which determines future income taxes based on the differences between assets and liabilities reported for financial accounting purposes and those reported for tax purposes.  Future income taxes are calculated using tax rates anticipated to apply in periods that temporary differences are expected to reverse.

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 Black-Scholes option-pricing 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 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 consolidated balance sheet.  As the exchangeable shares are converted to Trust units, the exchange is accounted for as a step-acquisition where Unitholders’ capital was 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 or exchangeable shares were converted or convertible debentures were fully 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 period.

3.CHANGE IN ACCOUNTING POLICY

Unit-Based Compensation

Until July 1, 2005, the Trust accounted for unit based compensation based on the intrinsic value of the grants at each reporting date.  Effective July 1, 2005, on a prospective basis, the Trust began valuing unit rights using the fair value based method.  In the fourth quarter of 2005, the trust determined that the fair value methodology should have been applied to all grants since CICA 3870 was adopted, and the financial statements of prior periods have been restated accordingly.

As a result of retroactively adopting the fair value method of estimating compensation expense, net income for the comparative year ended December 31, 2004 was increased by $3.0 million, net of non-controlling interest of $0.09 million. The opening 2004 accumulated deficit was increased by $1.7 million, net of non-controlling interest of $0.1 million.  There was also a decrease in unitholders’ capital of $0.07 million during 2004 relating to the transfer of value from contributed surplus on exercise of unit option rights. There was no impact on cash flow as a result of adopting this policy (note 12).

4.Corporate Acquisition

Effective September 22, 2004, the Company acquired all of the issued and outstanding shares of a private oil and gas company with operations in Alberta.  The transaction was 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. Subsequent to the acquisition, the private company was amalgamated with the Company.

Petroleum and natural gas properties	$	109,777
Goodwill	37,755
Working capital	2,951
Capital lease obligation	(777		)
Asset retirement obligation	(8,435		)
Future income taxes	(30,229		)
Total net assets acquired	$	111,042
Financed by:
Cash	$	110,822
Costs associated with acquisition	220
Total purchase price	$	111,042

Goodwill of $37.8 million was determined based on the excess of the total consideration paid less the fair value assigned to the identifiable assets and liabilities including the future income tax liability.

5.PETROLEUM AND NATURAL GAS PROPERTIES

	As at December 31,
	2005			2004
Petroleum and natural gas properties	$	2,461,045		$	2,342,514
Accumulated depletion and depreciation	(1,491,307		)	(1,332,581		)
	$	969,738		$	1,009,933

In calculating the depletion and depreciation provision for 2005, $46.6million (2004 - $61.7 million) of costs relating to undeveloped properties and materials 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 effective September 2, 2003.

The petroleum and natural gas properties are subject to a ceiling test, which was calculated at December 31, 2005 using the following benchmark reference prices for the years 2006 to 2010 adjusted for commodity differentials specific to the Trust (note 18):

	2006	2007	2008	2009	2010
WTI (US$/bbl)	60.81	61.61	54.60	50.19	47.76
AECO (CDN$/mmbtu)	11.58	10.84	8.95	7.87	7.57

The prices and costs subsequent to 2010 have been adjusted for inflation at an annual rate of 1.5 percent.  Based on the ceiling test calculation, the Trust’s estimated undiscounted future net cash flows associated with the proved reserves plus the cost less impairment of unproved properties exceeded the book value of the petroleum and natural gas properties.

6. BANK 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 under the credit facilities or letters of credit (note 18) 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.  The facilities aggregating $250 million are subject to semi-annual review and are secured by a floating charge over all of the Company’s assets.  At December 31, 2005 a total of $123.6 million had been drawn under the credit facilities.

7.LONG-TERM DEBT

	As at December 31,
	2005		2004
10.5% senior subordinated notes (US$247,000)	$	288	$	297
9.625% senior subordinated notes (US$179,699,000)	209,511		216,286
	$	209,799	$	216,583

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.  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.

Interest Expense

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

	2005		2004
Bank loan	$	8,318	$	2,256
Amortization of deferred charges	1,492		1,060
Long-term debt	23,314		16,096
Total interest	$	33,124	$	19,412

8.CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES

On June 6, 2005 the Trust issued $100 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. Issue costs are being amortized over the term of the debentures, and the debt portion will accrete up to the principal balance at maturity. The accretion, amortization of issue costs and the interest paid are expensed as interest expense in the consolidated statements of operations. 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.

Debentures issued on June 6, 2005	$	100,000
Fair value of conversion feature	(4,800		)
Conversion of Debentures and amortization of discount	(21,434		)
Debentures outstanding December 31, 2005	$	73,766

9.ASSET RETIREMENT OBLIGATIONS

	As at December 31,
	2005			2004
Balance, beginning of the year	$	73,297		$	55,996
Liabilities incurred	406			4,623
Liabilities settled	(1,637		)	(2,739		)
Acquisition of liabilities	3,410			12,797
Disposition of liabilities	(2,117		)	(1,722		)
Accretion	5,762			4,342
Change in estimate(1)	(46,111		)	—
Balance, end of the year	$	33,010		$	73,297

(1) The change in estimate was primarily due to the significant increase in recent and forecasted market price of petroleum and natural gas. Consequentially, the projected economic life of the wells and facilities are extended, resulting in wells and facilities being abandoned and reclaimed further out in the future and thus a lower present value of asset retirement obligations.

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 with the majority of costs incurred between 2044 and 2057. The undiscounted amount of estimated cash flow required to settle the retirement obligations at December 31, 2005 is $218 million.  Estimated cash flow has been discounted at a credit-adjusted risk free rate of 8.0 percent and an inflation rate of 2.5 percent for the years 2006 to 2008, and 1.5 percent thereafter.

10.UNITHOLDERS’ CAPITAL

Trust Units

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

Trust Units	Number of units	Amount
		(restated - note 3)
Balance December 31, 2003	60,821	$	449,403
Issued on conversion of Exchangeable Shares	1,994	21,222
Issued on exercise of trust unit rights	113	1,005
Transfer from contributed surplus on exercise of trust unit rights (restated - note 3)	—	402
Issued pursuant to distribution reinvestment program	10	131
Issued for cash, net of expenses	3,600	43,500
Balance December 31, 2004	66,538	515,663
Issued on conversion of Debentures	1,549	22,859
Issued on conversion of Exchangeable Shares	363	5,373
Issued on exercise of trust unit rights	369	2,916
Transfer from contributed surplus on exercise of trust unit rights	—	1,301
Issued pursuant to distribution reinvestment program	464	6,908
Balance December 31, 2005	69,283	$	555,020

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.  The Trust can also acquire trust units to be issued under the DRIP at prevailing market rates.

On December 20, 2004, the Trust issued 3,600,000 trust units at $12.80 per unit for gross proceeds of $46.1 million pursuant to a prospectus.

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 adjusted 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, 2005 was 1.37201 trust units per exchangeable share (2004 - 1.21472 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.

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.

Non-controlling Interest	Number of Exchangeable Shares		Amount
Balance December 31, 2003 (restated – note 3)	3,725		$	25,590
Exchanged for trust units	(1,849	)	(13,090		)
Non-controlling interest in net income	—		436
Balance December 31, 2004 (restated – note 3)	1,876		12,936
Exchanged for trust units	(279	)	(1,975		)
Non-controlling interest in net income	—		1,849
Balance December 31, 2005	1,597		$	12,810

As the exchangeable shares are converted to Trust units, the exchange is accounted for as a step-acquisition where Unitholders’ capital was 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.

The Trust recorded compensation expense of $5.3 million for the year ended December 31, 2005 ($4.6 million in 2004) (note 3).

The Trust used the Black-Scholes option-pricing model to calculate the estimated fair value of the outstanding rights. The following assumptions were used to arrive at the estimate of fair values:

	2005			2004
Expected annual right’s exercise price reduction	$	1.80		$	1.80
Expected volatility	23		%	30		%
Risk-free interest rate	3.30% - 3.84		%	3.59% - 4.31		%
Expected life of option (years)	5			5

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

	Number of rights		Weighted average exercise price (1)
Balance, December 31, 2003	2,855		$	10.15
Granted	1,297		$	11.77
Exercised	(113	)	$	8.87
Cancelled	(502	)	$	9.54
Balance, December 31, 2004	3,537		$	9.60
Granted	2,451		$	15.01
Exercised	(369	)	$	7.90
Cancelled	(253	)	$	9.83
Balance, December 31, 2005	5,366		$	10.88

(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, 2005:

Range of Exercise Prices					Number Outstanding at December 31, 2005	Weighted Average Remaining Term	Weighted Average Exercise Price		Number Exercisable at December 31, 2005	Weighted Average Exercise Price
						(years)
$	5.41	to	$	8.50	1,959	2.7	$	6.60	1,136	$	6.57
$	8.51	to	$	11.50	1,028	3.8	$	10.45	323	$	10.45
$	11.51	to	$	14.50	472	4.4	$	12.57	—	—
$	14.51	to	$	17.68	1,907	4.8	$	15.08	—	—
$	5.41	to	$	17.68	5,366	3.8	$	10.88	1,459	$	7.43

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:

	2005	2004
Weighted average number of units outstanding, basic	67,382	62,574
Trust units issuable on conversion of exchangeable shares	2,330	2,635
Dilutive effect of trust unit incentive rights	1,438	473
Trust units issuable on conversion of convertible debentures	2,981	—
Weighted average number of units outstanding, diluted	74,131	65,682

The dilutive effect of trust unit incentive rights above did not include 3.9 million trust unit rights (2004 – 3.1 million) because the respective exercise prices exceeded the average market price of the trust units during the year and the amount of compensation expense attributed to future services was not yet recognized.

14.INCOME TAXES (RECOVERY)

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

	2005			2004 (1)
				(restated – note 3)
Income (loss) before income taxes and non-controlling interest	$	83,398		$	(15,037	)
Expected income taxes (recovery) at the statutory rate of 40.10% (2004 – 40.57%)	33,443			(6,101		)
Increase (decrease) in taxes resulting from:
Resource allowance	(13,650		)	(9,663		)
Alberta royalty tax credit	(130		)	(203		)
Net income of the Trust	(29,415		)	(30,097		)
Non-taxable portion of foreign exchange gain	(1,360		)	(3,241		)
Effect of change in tax rate	2,734			(7,438		)
Effect of change in opening tax pool balances	851			8,711
Effect of change in valuation allowance	(1,400		)	5,194
Unit based compensation	2,143			1,696
Other	(290		)	(95		)
Large corporation tax and provincial capital tax	8,747			9,000
Provision for (recovery of) income taxes	$	1,673		$	(32,237	)

(1) Certain comparative figures have been reclassified to conform to the current year’s presentation.

The components of future income taxes are as follows:

	As at December 31
	2005			2004
Future income tax liabilities:
Capital assets	$	170,008		$	193,584
Other	13,304			12,853
Future income tax assets:
Asset retirement obligation	(11,917		)	(26,072		)
Reorganization costs	(7,212		)	(12,206		)
Loss carry-forward	(4,438		)	(3,250		)
Future income taxes	$	159,745		$	164,909

15.CASH FLOW INFORMATION

Increase (Decrease) in Non-Cash Working Capital Items

	2005			2004
Current assets	$	(35,401	)	$	(6,055	)
Current liabilities	16,410			5,630
	$	(18,991	)	$	(425	)
Changes in non cash working capital related to:
Operating activities	$	(20,212	)	$	3,589
Investing activities	1,221			(4,014		)
	$	(18,991	)	$	(425	)

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

	2005		2004
Interest	$	29,728	$	21,096
Current income taxes	$	8,536	$	17,485

16.FINANCIAL INSTRUMENTS AND CREDIT RISK

The Trust’s financial instruments recognized in the balance sheet consist of cash and short-term investments, accounts receivable, current liabilities and long-term borrowings.  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 values of financial instruments other than bank debt and long-term borrowings approximate their book amounts due to the short-term maturity of these instruments.  The fair value of the bank debt approximates its book value as it is at a market rate of interest.  At December 31, 2005, the trading value of the Company’s senior subordinated term notes was 105 percent in relation to par (2004 - - 105 percent). The market value of the Trust’s convertible debentures at December 31, 2005 was 118 percent in relation to par.

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.

The Trust is exposed to interest rate risk as a result of its floating rate debts.

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.

At December 31, 2005, the Trust had derivative contracts for the following:

OIL

	Period	Volume	Price	Index
Price collar	Calendar 2006	2,000 bbl/d	US$55.00 – $80.85	WTI
Price collar	Calendar 2006	2,000 bbl/d	US$55.00 – $84.18	WTI
Price collar	Calendar 2006	2,000 bbl/d	US$55.00 – $85.30	WTI
Price collar	Calendar 2006	1,000 bbl/d	US$55.00 – $87.10	WTI
Price collar	Calendar 2006	1,000 bbl/d	US$55.00 – $87.35	WTI

FOREIGN CURRENCY

	Period	Amount	Floor	Cap
collar	Calendar 2006	US$3,000,000 per month	CAD$/US $1.1700	CAD$/US $1.2065

INTEREST RATE SWAP

Period	Principal	Rate
November 2003 to July 2010	US$179,699,000	3-month LIBOR plus 5.2%

Under the CICA guideline for hedge accounting, the Trust’s financial derivative contracts for oil collars and foreign currency exchange do not qualify as effective accounting hedges.  Accordingly, these contracts have been accounted for based on the fair value method.  At December 31, 2005, the Trust recorded an asset of $5.2 million (2004 – a liability of $9.5 million) on the mark-to-market value of the outstanding non-hedging financial derivatives.  The change in the mark-to-market value of the non-hedging financial derivatives during 2005 has been recorded as an unrealized gain on non-hedging financial derivatives of $14.7 million (2004 - $0.6 million) in the consolidated statement of operations.  The Trust is applying hedge accounting to the interest rate swap and gains and losses are netted against interest expense.

In 2006, the Company entered into derivative contracts for the following:

OIL

	Period	Volume	Price	Index
Price collar	Calendar 2007	2,000 bbl/d	US$55.00 – $83.60	WTI
Price collar	Calendar 2007	3,000 bbl/d	US$55.00 – $83.75	WTI

FOREIGN CURRENCY

	Period	Amount	Floor	Cap
collar	February 1, 2006 to December 31, 2006	US$4,000,000 per month	CAD/US$1.1500	CAD/US$1.1835
collar	January 9, 2006 to December 31, 2006	US$3,000,000 per month	CAD/US$1.1500	CAD/US$1.1780

18.COMMITMENTS AND CONTINGENCIES

In October 2002, the Trust entered into a long-term crude oil supply contract with a third party that requires the delivery of up to 20,000 barrels per day of Lloydminster Blend crude oil at a price fixed at 71% of NYMEX WTI oil price.  The contract is for an initial term of five years commencing January 1, 2003.  The contract volumes increased from 9,000 barrels per day in January 2003 to 20,000 barrels per day in October 2003 and thereafter.

At December 31, 2005, the Trust had entered into natural gas physical sales contracts with third parties as follow:

GAS	Period	Volume	Price
Fixed price	January 1, 2006 to February 28, 2006	3,000 GJ/d	CAD$10.00
Fixed price	January 1, 2006 to March 31, 2006	5,000 GJ/d	CAD$10.07
Fixed price	January 1, 2006 to March 31, 2006	5,000 GJ/d	CAD$10.20
Fixed price	January 1, 2006 to March 31, 2006	2,000 GJ/d	CAD$10.63
Fixed price	March 1, 2006 to March 31, 2006	3,000 GJ/d	CAD$11.53
Fixed price	April 1, 2006 to October 31, 2006	5,000 GJ/d	CAD$8.40
Fixed price	April 1, 2006 to October 31, 2006	2,000 GJ/d	CAD$9.01
Price collar	January 1, 2006 to October 31, 2006	5,000 GJ/d	CAD$7.50 - $13.40
Price collar	April 1, 2006 to October 31, 2006	2,000 GJ/d	CAD$7.80 - $10.55
Price collar	April 1, 2006 to October 31, 2006	3,000 GJ/d	CAD$9.50 – $12.60

At December 31, 2005 the Trust had operating lease and transportation obligations as detailed below:

	Payments Due
($ thousands)	Total	Within 1 year	1-3 years	4-5 years
Operating leases	8,117	1,621	5,834	662
Transportation agreements	3,446	2,052	1,394	—
Total	11,563	3,673	7,228	662

At December 31, 2005, there are outstanding letters of credit aggregating $7.1 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 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.

19.DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

Reconciliation of Financial Statements to United States Generally Accepted Accounting Principles

The consolidated financial statements included in the Trust 2005 Annual Report have been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”), which in most respects, conform to generally accepted accounting principles in the United States of America (“U.S. GAAP”). The significant differences in those principles, as they apply to the Trust, are as follows:

(a)           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.

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 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.

As a result of applying the U.S. GAAP ceiling test in prior years, the Trust recorded additional depletion of $340.7 million before income tax. Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, 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 Guideline. 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 $14.8 million (2004 - $0.5 million) less depletion recorded under U.S. GAAP.

(b)           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 Emerging Issues Task Force (“EITF”) D-98, and 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 $1,265.1 million for 2005 and $ 878.8 million for 2004 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 Income (Deficit). The adjustments to Accumulated Income (Deficit) are a charge of $386.3 million for 2005 and $176.6 million for 2004. As a result, the Accumulated Income (Deficit) year-end balance is reduced by $868.1 million in 2005 and $481.8 million in 2004.

In compliance with EITF D-98, the Trust also reclassed to Temporary Equity of $26.3 million in 2005 and $7.4 million in 2004 of Contributed Surplus relating to the intrinsic value of Trust Unit Rights outstanding at year-end. As a result, the Trust has retroactively restated contributed surplus on its consolidated balance sheet in 2004.

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 balance sheet date would be included in Temporary Equity on the consolidated balance sheet.

(c)           The Trust has a Trust Units Rights Incentive Plan established in 2003. As the execrise 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. Accordingly, compensation expense is determined as the excess of the market price over the exercised price at the end of each reporting period and is recognized in income over the vesting period of the rights. The accounting for compensation expense for the unit rights plan results in a difference between Canadian and U.S. GAAP, as the Trust uses the fair value method to account for its unit compensation expense under Canadian GAAP.

The Company had a stock option plan which was terminated in 2003. Until the termination of the stock option plan, the accounting for the stock option plan was done in accordance with FASB Statement of Financial Accounting Standards No. 123, “Accounting for Stock-based Compensation” (“FAS 123”). FAS 123 establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. As permitted by the FAS 123, the Trust elected to follow the intrinsic value method of accounting for stock-based compensation arrangements, as provided for in Accounting Principles Board Opinion 25 (“APB 25”).

APB 25 also requires recognition of compensation cost with respect to changes in intrinsic value for variable employee stock compensation plans. As a result of the modifications to the terms of employee stock options, the modified options were subject to variable plan accounting, which resulted in a year-to-date cumulative charge of $13.8 million to accumulated income at December 31, 2003 for U.S. GAAP purposes.

(d)           On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative instruments and Hedging Activities” (FAS 133), as modified by Statement No. 138 “Accounting for Certain Derivative Instruments and Certain Hedging Activities”. The statement, as amended, establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value, and that change in the fair value be recognized currently in income unless specific hedge accounting criteria are met. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity’s approach to managing risk. At December 31, 2005, the Trust’s financial instruments that do not meet the specific hedge accounting under U.S. GAAP has resulted in the recording on the balance sheet, at their fair value, an asset of $5.7 million (2004 – $2.9 million) and a liability of $1.6 million (2004 – nil).

Upon adoption of AcG-13, deferred credits for derivative instruments of $10.1 million were recognized representing the fair market value of derivative financial instruments in place as of January 1, 2004. The deferred charges are amortized over the life of the derivative financial instruments for Canadian GAAP and were equal to the aggregate of U.S. GAAP gains and losses incurred on these instruments, prior to January 1, 2004. During 2004, $10.1 million of the deferred charges was amortized to income under AcG-13. Because this amount was expensed in previous periods for U.S. GAAP, the amount has been reversed in the year ended December 31, 2004 for U.S. GAAP.

(e)           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 believes that it has no other comprehensive income; accordingly comprehensive income is equivalent to net income.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2005 and 2004

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

Consolidated Statements of Operations

The application of U.S. GAAP would have the following effect on net income as reported:

	Years Ended December 31
	2005			2004
				(restated - note 3)
Net income for the year – Canadian GAAP	$	79,876		$	16,764
Adjustments:
Depletion (a)	14,751			527
Non-controlling interest (b)	2,223			436
Compensation expense (c)	(16,581		)	(3,090		)
Interest rate swaps (d)	2,570			(1,061		)
Financial derivative instruments (d)	(1,240		)	10,110
Income taxes	(6,449		)	(3,886		)
Net income for the year – U.S. GAAP	$	75,150		$	19,800
Net income per unit – U.S. GAAP
Basic	$	1.08		$	0.30
Diluted	$	1.06		$	0.30

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2005 and 2004

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

Consolidated Balance Sheets

The application of U.S. GAAP would have the following effect on the Consolidated Balance Sheets as reported:

	December 31, 2005
	Canadian GAAP		Increase
	as Reported		(Decrease)			U.S. GAAP
Assets:
Capital assets (a)	$	969,738	$	(116,594	)	$	853,144
Financial derivative instruments (d)	—		5,737			5,737
Liabilities:
Financial derivative instruments (d)	—		1,550			1,550
Future income taxes	159,745		(53,224		)	106,521
Non-controlling interest (b)	12,810		(12,810		)	—
Temporary equity (b)	—		1,291,405			1,291,405
Unitholders’ equity:
Unitholders’ capital (b)	555,020		(555,020		)	—
Contributed Surplus (b)	10,332		(10,332		)	—
Accumulated income (deficit) – see below	86,868		(978,316		)	(891,448		)

	December 31, 2004 (restated (b))
	Canadian GAAP		Increase
	as Reported		(Decrease)			U.S. GAAP
	(restated - note 3)
Assets:
Capital assets (a)	$	1,009,933	$	(136,654	)	$	873,279
Financial derivative instruments (d)	—		2,858			2,858
Liabilities:
Future income taxes	164,909		(61,583		)	103,326
Non-controlling interest (b)	12,936		(12,936		)	—
Temporary equity (b)	—		886,288			886,288
Unitholders’ equity:
Unitholders’ capital (b)	515,663		(515,663		)	—
Contributed Surplus (b)	6,287		(6,287		)	—
Accumulated income (deficit) – see below	6,992		(587,284		)	(580,292		)

	December 31,
	2005			2004
				(restated (b))
Accumulated income (deficit) - Canadian GAAP	$	86,868		$	6,992
Adjustments to depletion (a)	(147,586		)	(162,337		)
Compensation expense (c)	(31,699		)	(15,117		)
Financial derivative instruments (d)	4,188			2,858
Non-controlling interest (b)	1,876			(347		)
Change in redemption value of trust units (b)	(868,115		)	(481,810		)
Adjustments to future income taxes	64,745			71,194
Cumulative effect of change in accounting policy for asset retirement obligation (c)	(1,725		)	(1,725		)
Accumulated deficit - U.S. GAAP	$	(891,448	)	$	(580,292	)

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2005 and 2004

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

Consolidated Statements of Cash Flow

The application of U.S. GAAP would not have an effect on the operating activities of the consolidated statements of cash flow:

Recent Developments in U.S. Accounting

In February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement No. 155, “Accounting for Certain Hybrid Financial Instruments”. This is an amendment of FASB Statements No. 133, “Accounting for Derivative Instruments and Hedging Activities”, and Statement 140, “Accounting for Transfers and Servicing of financial Assets and Extinguishments of Liabilities”. This Statement permits fair value re-measurement for hybrid financial instruments that contain embedded derivatives and further clarifies the definition of embedded derivatives. Statement 155 eliminates the prohibition in Statement 140 on a qualifying special-purpose entity from holding a derivative financial instrument. The Trust has accounted for its convertible debentures in compliance to all applicable derivative accounting guidelines.

In May 2005, the FASB issued Statement No. 154, “Accounting Changes and Error Corrections”. This Statement replaces APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including the cumulative effect of changing to the new accounting principle in net income of the period of the change. This Statement requires retrospective application to prior periods’ financial statements unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Trust has adopted this standard in the preparation of its consolidated financial statements.

In December 2004, the FASB Issued SFAS No. 123R, “Share Based Payments”, which addresses the issue of measuring compensation cost associated with Share Based Payment plans. This statement requires that all such plans, for public entities, be measured at fair value using an option pricing model whereas previously certain plans could be measured using either a fair value method or an intrinsic value method. The revision is intended to increase the consistency and comparability of financial results by only allowing one method of application. This revised standard is effective for the first interim or annual period beginning on or after June 15, 2005 for awards granted on or after the effective date.

Statement 123R also requires liability classified awards to be re-measured to fair value at each balance sheet date until the award is settled. On August 31, 2005, Statement 123R-1 was issued to defer the requirement that a freestanding financial instrument originally subject to 123R becomes subject to the recognition and measurement requirements of other applicable generally accepted accounting principles when the rights conveyed by the instrument to the holder are no longer dependent on the holder being an employee of the entity. On October 18, 2005, Statement 123R-2 was issued to provide further guidance on the application of grant date as defined in FAS 123R. The Trust is currently assessing the impact of FAS 123R on its consolidated financial statements.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets” which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions”. SFAS No. 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The standard would be effective for financial statements issued for fiscal years beginning after June 15, 2005. The Trust does not expect the adoption of this standard to have any material effect on its consolidated financial statements.

Recent Developments in Canadian Accounting

Financial Instruments        In January, 2005 the CICA issued three new standards relating to the reporting of financial instruments in financial statements. These standards introduce new requirements for the recognition and measurement of financial instruments and comprehensive income. Section 3855, “Financial Instruments – Recognition and Measurement” requires that all financial instruments, including derivatives, are to be included on a company’s balance sheet and measured, either at their fair values or, in limited circumstances when fair value may not be considered most relevant, at cost or amortized cost. The standard also provides guidance on when gains and losses as a result of changes in fair values are to be recognized in the income statement.

The issuance of the new Section 3855 will result in amendments to Section 3860 “Financial Instruments – Disclosure and Presentation” to make the scope and definitions consistent with that of the new Section 3855, including expanding the scope to include certain commodity-based contracts, and to update certain disclosures in light of the introduction of Section 3855. Other Handbook Sections have also been amended for conformity with the new standards.

Section 3865 “Hedges”, extends the existing requirements for hedge accounting currently under AcG -13. This new section allows for the optional treatment of accounting for financial instruments that are designated as either fair value hedges, cash flow hedges or hedges of a net investment in a self-sustaining foreign operation. For a fair value hedge, the gain or loss on a derivative hedging item, or the gain or loss on a non-derivative hedging item attributable to the hedged risk, is recognized in net income in the period of change together with the offsetting loss or gain on the hedged item attributable to the hedged risk. The carrying amount of the hedged item is adjusted for the hedged risk. For a cash flow hedge, the effective portion of the hedging item’s gain or loss is initially reported in other comprehensive income and subsequently reclassified to net income when the hedged item affects net income. For a hedge of a net investment in a self-sustaining foreign operation the same accounting is followed as for a cash flow hedge.

A new location for recognizing certain gains and losses – other comprehensive income – has been introduced with the issued of Section 1530, “Comprehensive Income”. An integral part of the accounting standards on recognition and measurement of financial instruments is the ability to present certain gains and losses outside net income, in other Comprehensive Income. This standard requires that a company should present comprehensive income and its components in a financial statement displayed with the same prominence as other financial statements that constitute a complete set of financial statements, in both annual and interim financial statements. Exchange gains and losses arising from the translation of the financial statements of a self-sustaining foreign operation, previously recognized in a separate component of shareholders’ equity, in accordance with Section 1650, “Foreign Currency Translation”, will now be recognized in a separate component of other comprehensive income.

These three new Handbook Sections are effective date for annual and interim periods in fiscal years beginning on or after October 1, 2006. The Trust is evaluating the impact the adoption of these new standards will have on its consolidated financial statements.

Non-Monetary Transactions  In June 2005, The CICA issued Section 3831 “Non-Monetary Transactions”, which replaces the culmination of earnings test with a commercial substance test as the criteria for fair value measurement. In addition, fair value measurement is clarified. The Company does not expect application of this new standard to have a material impact on its consolidated financial statements.