Baytex Energy (BTE) 40-F 2007 FY Annual report (Canada)

Exhibit 99.2

Consolidated Financial Statements of

BAYTEX ENERGY TRUST

December 31, 2006

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Baytex Energy Trust is responsible for establishing and maintaining adequate internal control over financial reporting over the Trust. Under the supervision of our President and Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2006, 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.

Management’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006, 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, 2006.

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
President and Chief Executive Officer	Chief Financial Officer
Baytex Energy Ltd.	Baytex Energy Ltd.
March 22, 2007

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

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

We have audited management's assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Baytex Energy Trust and subsidiaries (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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, management's assessment that the Trust maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 of the Trust, and our report dated March 16, 2007, except as to Note 17 which is as of March 22, 2007, expressed an unqualified opinion on those financial statements and included an explanatory paragraph relating to the restatement of the consolidated financial statements, as discussed in Note 17, for the year ended December 31, 2005 and also included a separate report titled Comments by Independent Registered Chartered Accountants on Canada-United States of America Reporting Difference referring to a change in accounting principle.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants

Calgary, Canada

March 16, 2007, except as to internal control over financial reporting relating to Note 17, Differences between Canadian and United States Generally Accepted Accounting Principles which is as of March 22, 2007

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 of December 31, 2006 and 2005 and the related consolidated statements of operations and deficit and cash flows for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

With respect to the financial statements for the year ended December 31, 2006, we conducted our audit in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). With respect to the financial statements for the year ended December 31, 2005, we conducted our audit in accordance with Canadian generally accepted auditing standards. Those 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, such consolidated financial statements present fairly, in all material respects, the financial position of Baytex Energy Trust and subsidiaries as of December 31, 2006 and 2005 and the results of their operations and their cash flows for the years then ended in conformity with Canadian generally accepted accounting principles.

The consolidated financial statements for the year ended December 31, 2005 have been restated with respect to Note 17, 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 effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006, 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 16, 2007, except as to internal control over financial reporting relating to Note 17, Differences between Canadian and United States Generally Accepted Accounting Principles, which is as of March 22, 2007, expressed an unqualified opinion on management’s assessment of the effectiveness of the Trust’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting.

On March 16, 2007, we reported separately to the Unitholders of Baytex Energy Trust on our audit, conducted in accordance with Canadian generally accepted auditing standards, of the financial statements for the same period, prepared in accordance with Canadian generally accepted accounting principles but which did not include Note 17, Differences between Canadian and United States Generally Accepted Accounting Principles.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants

Calgary, Canada

March 16, 2007, except as to Note 17 which is as of March 22, 2007

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 consolidated financial statements, such as the change described in Note 17 to the financial statements. Our report to the Board of Directors of Baytex Energy Ltd. and Unitholders of Baytex Energy Trust, dated March 16, 2007, except as to Note 17 which is as of March 22, 2007, 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 change is properly accounted for and adequately disclosed in the financial statements.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants

Calgary, Canada

March 16, 2007, except as to Note 17 which is as of March 22, 2007

Baytex Energy Trust
Consolidated Balance Sheets
As at December 31,
(thousands)
	2006			2005
ASSETS
Current assets
Accounts receivable	$	64,716		$	73,869
Crude oil inventory		9,609			9,984
Financial derivative contracts (note 15)		3,448			5,183
		77,773			89,036
Deferred charges and other assets		4,475			9,038
Petroleum and natural gas properties (note 3)		959,626			969,738
Goodwill		37,755			37,755
	$	1,079,629		$	1,105,567
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	71,521		$	89,966
Distributions payable to unitholders		13,522			10,393
Bank loan (note 4)		127,495			123,588
Financial derivative contracts (note 15)		1,055			-
		213,593			223,947
Long-term debt (note 5)		209,691			209,799
Convertible debentures (note 6)		18,906			73,766
Asset retirement obligations (note 7 )		39,855			33,010
Deferred obligations (note 16)		2,391			4,558
Future income taxes (note 12)		118,858			159,745
		603,294			704,825
Non-controlling interest (note 9)		17,187			12,810
UNITHOLDERS’ EQUITY
Unitholders’ capital (note 8)		637,156			555,020
Conversion feature of debentures (note 6)		940			3,698
Contributed surplus		13,357			10,332
Deficit		(192,305	)		(181,118	)
		459,148			387,932
	$	1,079,629		$	1,105,567
Commitments and contingencies (note 16)
See accompanying notes to the consolidated financial statements.
On behalf of the Board
(signed) "Naveen Dargan"	(signed) "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 Deficit
Years Ended December 31,
(thousands, except per unit data)
		2006			2005
Revenue
Petroleum and natural gas sales	$	556,689		$	546,940
Royalties		(85,043	)		(81,898	)
Realized gain (loss) on financial derivatives		2,529			(48,462	)
Unrealized gain (loss) on financial derivatives		(2,790	)		14,696
		471,385			431,276
Expenses
Operating		112,406			110,648
Transportation		24,346			22,399
General and administrative		20,843			16,010
Unit based compensation (note 10)		7,460			5,346
Interest (note 5)		34,960			33,124
Foreign exchange gain		(108	)		(6,784	)
Depletion, depreciation and accretion		152,579			167,135
		352,486			347,878
Income before taxes and non-controlling interest		118,899			83,398
Taxes (recovery)(note 12)
Current		8,414			8,747
Future		(41,169	)		(7,074	)
		(32,755	)		1,673
Income before non-controlling interest		151,654			81,725
Non-controlling interest(note 9)		(4,585	)		(1,849	)
Net income		147,069			79,876
Deficit, beginning of year		(181,118	)		(139,453	)
Distributions to unitholders		(158,256	)		(121,541	)
Deficit, end of year	$	(192,305	)	$	(181,118	)
Net income per trust unit (note 11)
Basic	$	2.02		$	1.19
Diluted	$	1.91		$	1.15
See accompanying notes to the consolidated financial statements

Baytex Energy Trust
Consolidated Statements of Cash Flows
Years Ended December 31,
(thousands)		2006			2005
CASH PROVIDED BY (USED IN):
Operating activities
Net income	$	147,069		$	79,876
Items not affecting cash:
Unit based compensation (note 10)		7,460			5,346
Amortization of deferred charges		1,267			1,492
Unrealized foreign exchange gain		(108	)		(6,784	)
Depletion, depreciation, and accretion		152,579			167,135
Accretion on debentures (note 6)		189			321
Unrealized loss (gain) on financial derivatives (note 15)		2,790			(14,696	)
Future income tax recovery		(41,169	)		(7,074	)
Non-controlling interest (note 9)		4,585			1,849
		274,662			227,465
Change in non-cash working capital (note 13)		(9,058	)		(20,212	)
Asset retirement expenditures		(1,747	)		(1,637	)
Decrease in deferred charges and other assets		(1,875	)		(977	)
Cash flow from operating activities		261,982			204,639
Financing activities
Increase (decrease) in bank loan		3,907			(37,856	)
Issue of trust units (note 8)		8,509			2,916
Payments of distributions		(141,453	)		(114,221	)
Issuance of convertible debentures (note 6)		-			100,000
Convertible debentures issue costs (note 6)		-			(4,250	)
Cash flow from financing activities		(129,037	)		(53,411	)
Investing activities
Petroleum and natural gas property expenditures		(133,911	)		(201,478	)
Proceeds on disposal of petroleum and natural gas properties		828			49,029
Change in non-cash working capital (note 13)		138			1,221
Cash flow from investing activities		(132,945	)		(151,228	)
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, 2006 and 2005

(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 the 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, accounted for at cost, 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 pursuant to a long-term crude oil supply agreement, is valued at the lower of cost, using the weighted average cost method, 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 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.

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 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

Costs related to the exchange of the senior subordinated notes, issuance of the convertible debentures, and procurement of the long-term supply contract have been deferred and are amortized over the term of the instruments 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 except for products sold pursuant to the long-term crude oil supply contract where title transfer is at the refinery gate.

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. Financial derivative contracts used as hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective in order to qualify for accrual accounting. 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. 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 substantially 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 10. The exercise price of the rights granted under the Plan may be reduced in future periods in accordance with the terms of the Plan. The Trust uses the binomial-lattice model to calculate the estimated fair value of the outstanding rights.

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

Non-controlling Interest

The exchangeable shares of the 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 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 2006.

3.PETROLEUM AND NATURAL GAS PROPERTIES

	As at December 31
		2006			2005
Petroleum and natural gas properties	$	2,600,834		$	2,461,045
Accumulated depletion and depreciation		(1,641,208	)		(1,491,307	)
	$	959,626		$	969,738

In calculating the depletion and depreciation provision for 2006, $34.3million (2005 - $46.6 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 effective September 2, 2003.

The net book value of petroleum and natural gas properties are subject to a ceiling test, which was calculated at December 31, 2006 using the following benchmark reference prices for the years 2007 to 2011 adjusted for commodity differentials specific to the Trust (notes 15 & 16):

	2007	2008	2009	2010	2011
WTI crude oil (US$/bbl)	65.73	68.82	62.42	58.37	55.20
AECO natural gas ($/MMBtu)	7.72	8.59	7.74	7.55	7.72

The prices and costs subsequent to 2011 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.

4.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 16) 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. The credit facilities aggregating to $300 million are subject to semi-annual review and are secured by a floating charge over all of the Company’s assets. At December 31, 2006 a total of $127.5 million were drawn under the credit facilities (December 31, 2005 - $123.6 million).

5.LONG-TERM DEBT

	As at December 31
		2006		2005
10.5% senior subordinated notes (US$247)	$	288	$	288
9.625% senior subordinated notes (US$179,699)		209,403		209,511
	$	209,691	$	209,799

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. 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 15).

Interest Expense

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

		2006		2005
Bank loan and other	$	9,263	$	8,318
Amortization of deferred charges		1,267		1,492
Long-term debt and convertible debentures		24,430		23,314
Total interest	$	34,960	$	33,124

6.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. 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.

	Number of Debentures			Convertible Debentures			Conversion Feature of Debentures
Issued on June 6, 2005	100,000		$	95,200		$	4,800
Conversion	(22,848	)		(21,755	)		(1,102	)
Accretion	-			321			-
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

7.ASSET RETIREMENT OBLIGATIONS

	As at December 31,
		2006			2005
Balance, beginning of year	$	33,010		$	73,297
Liabilities incurred		1,199			406
Liabilities settled		(1,747	)		(1,637	)
Acquisition of liabilities		-			3,410
Disposition of liabilities		(122	)		(2,117	)
Accretion		2,678			5,762
Change in estimate(1)		4,837			(46,111	)
Balance, end of year	$	39,855		$	33,010

⁽¹⁾The change in estimate is partially due to the fluctuations in forecasted market prices of petroleum and natural gas which effect the projected economic life of the wells and facilities. This results in changes in the timing of wells and facilities being abandoned and reclaimed thus changing the discounted present value of asset retirement obligations. Other factors affecting the liability amount are change in status of wells and change in the estimated costs of abandonment and reclamations.

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 2058. The undiscounted amount of estimated cash flow required to settle the retirement obligations at December 31, 2006 is $236 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 5.0 percent for the year 2007, 4.0 percent for 2008, 3.0 percent for 2009 and 2.0 percent thereafter.

8.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, 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
Issued on conversion of debentures	3,901		54,799
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	-		4,434
Issued pursuant to distribution reinvestment program	654		13,674
Balance, December 31, 2006	75,122	$	637,156

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.

9.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, 2006 was 1.51072 trust units per exchangeable share (2005 - 1.37201 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.

	Number of Exchangeable Shares			Amount
Balance, December 31, 2004	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
Exchanged for trust units	(24	)		(208	)
Non-controlling interest in net income	-			4,585
Balance, December 31, 2006	1,573		$	17,187

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.

10.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 $7.5 million for the year ended December 31, 2006 ($5.3 million in 2005) 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 fair value of the unit rights issued. The following assumptions were used to arrive at the estimate of fair values:

	2006	2005
Expected annual right’s exercise price reduction	$2.16	$1.80
Expected volatility	23% - 28%	23%
Risk-free interest rate	3.54% - 4.45%	3.30% - 3.84%
Expected life of right (years)	Various (1)	5

⁽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, 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
Granted	2,443	$ 21.66
Exercised	(1,250)	$ 6.81
Cancelled	(246)	$ 11.54
Balance, December 31, 2006	6,313	$ 14.00

⁽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, 2006:

Range of Exercise Prices	Number Outstanding at December 31, 2006	Weighted Average Remaining Term	Weighted Average Exercise Price	Number Exercisable at December 31, 2006	Weighted Average Exercise Price
		(years)
$ 3.25 to $ 8.00	1,191	2.0	$ 5.14	1,033	$ 4.89
$ 8.01 to $12.00	930	3.1	$ 9.33	435	$ 8.94
$12.01 to $16.00	2,085	3.9	$13.31	552	$12.93
$16.01 to $20.00	270	4.6	$19.43	-	-
$20.01 to $24.05	1,837	4.8	$22.10	-	-
$ 3.25 to $24.05	6,313	3.7	$14.00	2,020	$ 7.96

11.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:

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
2005
Net income			Trust units		Net income per trust unit
Net income per basic unit	$	79,876	67,382	$	1.19
Dilutive effect of trust unit rights		-	1,438
Conversion of convertible debentures		3,168	2,981
Exchange of exchangeable shares		1,849	2,330
Net income per diluted unit	$	84,893	74,131	$	1.15

The dilutive effect of trust unit incentive rights above did not include 2.1 million trust unit rights (2005 - 3.9 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.

12.TAXES (RECOVERY)

The provision for (recovery of) taxes has been computed as follows:
		2006		2005
Income before income taxes and non-controlling interest	$	118,899		$ 83,398
Expected income taxes (recovery) at the statutory rate of 37.0% (2005 - 40.10%)	$	43,992		$ 33,443
Increase (decrease) in taxes resulting from:
Resource allowance		(11,236	)	(13,650)
Alberta royalty tax credit		(110	)	(130)
Net income of the Trust		(56,261	)	(29,415)
Non-taxable portion of foreign exchange gain		(20	)	(1,360)
Effect of change in tax rate		(26,175	)	2,734
Effect of change in opening tax pool balances		3,451		851
Effect of change in valuation allowance		1,597		(1,400)
Unit based compensation		2,760		2,143
Other		833		(290)
Current taxes		8,414		8,747
Provision for (recovery of) taxes	$	(32,755	)	$ 1,673

The components of future income taxes are as follows:
	As at December 31
		2006			2005
Future income tax liabilities:
Petroleum and natural gas properties	$	136,955		$	170,008
Other		10,019			13,304
Future income tax assets:
Asset retirement obligations		(11,987	)		(11,917	)
Reorganization costs		-			(7,212	)
Loss carry-forward (1)		(12,049	)		(4,438	)
Other		(4,080	)		-
Future income taxes	$	118,858		$	159,745

⁽¹⁾ $50million of the loss carry-forward to expire in 2014, $18 million to expire in 2015.

On October 31, 2006, the Federal Government announced its intention to tax the distributions of income trusts beginning in 2011 at the corporate tax rates. If this legislation is enacted, there could potentially be additional future income taxes to be recorded by the Trust. At this time an estimate of the financial effect of the announcement has not been made.

13.CASH FLOW INFORMATION

Change in Non-Cash Working Capital Items

		2006			2005
Current assets	$	9,525		$	(35,401	)
Current liabilities		(18,445	)		16,410
	$	(8,920	)	$	(18,991	)
Changes in non-cash working capital related to:
Operating activities	$	(9,058	)	$	(20,212	)
Investing activities		138			1,221
	$	(8,920	)	$	(18,991	)

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

		2006		2005
Interest	$	32,373	$	29,728
Current income taxes	$	7,636	$	8,536

14.FINANCIAL INSTRUMENTS AND CREDIT RISK

The Trust’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, accounts receivable, current liabilities, bank loan 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 loan 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, 2006, the trading value of the Company’s senior subordinated term notes was 106 percent in relation to par (2005 - 105 percent). The market value of the Trust’s convertible debentures at December 31, 2006 was 146 percent in relation to par (2005 - 118 percent).

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.

15.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, 2006, the Trust had the following derivative contracts:

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
Price collar	Calendar 2007	2,000 bbl/d	US$60.00 - $80.40	WTI
Price collar	Calendar 2007	1,000 bbl/d	US$60.00 - $80.60	WTI

FOREIGN CURRENCY
	Period	Amount	Floor	Cap
Collar	Calendar 2007	US$5,000,000 per month	CAD/US$1.0835	CAD/US$1.1600

INTEREST RATE
	Period	Principal	Rate
Swap 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, 2006, the Trust recorded a current asset of $3.4 million and a current liability of $1.1 million (2005 - a current asset of $5.2 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 2006 has been recorded as an unrealized loss on financial derivatives of $2.8 million (2005 - unrealized gain of $14.7 million) in the consolidated statement of operations. The Trust is applying hedge accounting to the interest rate swap and gains and losses are included in interest expense. At December 31, 2006, the mark-to-market value of the interest rate swap was a liability of $6.0 million (2005 - $5.4 million).

16.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, 2006, the Trust had the following natural gas physical sales contracts:

GAS
	Period	Volume	Price
Price collar	November 1, 2006 to March 31, 2007	5,000 GJ/d	$8.00 - $9.45
Price collar	November 1, 2006 to March 31, 2007	5,000 GJ/d	$8.00 - $9.50
Price collar	November 1, 2006 to March 31, 2007	5,000 GJ/d	$8.00 - $10.15
Price collar	April 1, 2007 to October 31, 2007	5,000 GJ/d	$6.65 - $9.15
Price collar	April 1, 2007 to October 31, 2007	5,000 GJ/d	$6.65 - $9.30

Subsequent to December 31, 2006, the Trust added the following natural gas physical sales contracts:

	Period	Volume	Price
Price collar	April 1, 2007 to October 31, 2007	2,500 GJ/d	$6.65 - $8.25
Price collar	April 1, 2007 to October 31, 2007	2,000 GJ/d	$6.65 - $8.30
Price collar	April 1, 2007 to October 31, 2007	2,500 GJ/d	$6.65 - $8.73

At December 31, 2006, 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	$	6,891	$	1,761	$	2,199	$	2,199	$	732	$	-
Transportation agreements		3,177		2,015		926		204		26		6
Total	$	10,068	$	3,776	$	3,125	$	2,403	$	758	$	6

OTHER

At December 31, 2006, there are outstanding letters of credit aggregating $7.3 million (2005 - $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.

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. As at December 31, 2006, an additional $0.5 million was paid for year one’s obligations 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.

17.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	Note		2006			2005
Net Income - Canadian GAAP		$	147,069		$	79,876
Increase (Decrease) Under U.S. GAAP
Unrealized gain/(loss) on derivative instruments	D		2,408			(1,240	)
Depletion, depreciation and accretion	A		8,795			14,751
Interest	D		(548	)		(8,286	)
Unit based compensation	C		(28,156	)		(16,581	)
Income tax expense	A,D,H		(13,426	)		(2,095	)
Non-controlling interest	B		4,585			1,849
Net Income before cumulative effect of change in accounting policy			120,727			68,274
Cumulative effect of change in accounting policy	C		1,544			-
Net Income - U. S. GAAP		$	122,271		$	68,274
Net income per trust unit before cumulative effect of change in accounting policy	J
Basic		$	1.60		$	0.98
Diluted		$	1.52		$	0.96
Cumulative effect of change in accounting policy	J
Basic		$	0.02		$	-
Diluted		$	0.02		$	-
Net income per trust	J
Basic		$	1.62		$	0.98
Diluted		$	1.54		$	0.96
Weighted average trust units	J
Basic			75,331			69,712
Diluted			80,438			74,131

Condensed Consolidated Statement of Operations - U.S. GAAP

For the years ended December 31	Note		2006			2005
Revenue
Petroleum and natural gas sales, net of royalties		$	471,646		$	465,042
Gain (loss) on financial derivatives	D		2,147			(35,006	)
			473,793			430,036
Expenses
Operating	C		116,303			110,648
Transportation			24,346			22,399
General and administrative	C		52,562			37,937
Interest	D		35,508			41,410
Foreign exchange gain			(108	)		(6,784	)
Depletion, depreciation and accretion	A		143,784			152,384
			372,395			357,994
Income (loss) before income taxes and cumulative effect of change in accounting policy			101,398			72,042
Current			8,414			8,747
Future	A,D,H		(27,743	)		(4,979	)
Income taxes (recovery)			(19,329	)		3,768
Net income before cumulative effect of change in accounting policy			120,727			68,274
Cumulative effect of change in accounting policy	C		1,544			-
Net Income and Comprehensive Income		$	122,271		$	68,274
Consolidated Statement of Accumulated Deficit						(Restated - Note H	)
Deficit, beginning of the year		$	(1,002,232	)	$	(598,457	)
Net Income			122,271			68,274
Distributions to Unit holders			(158,256	)		(121,541	)
Adjustment for fair value of Temporary Equity	B		(364,927	)		(350,508	)
Deficit, end of the year		$	(1,403,144	)	$	(1,002,232	)

Condensed Consolidated Balance Sheet

		2006						2005
As at December 31	Note		As Reported			U.S. GAAP			As Reported			U.S. GAAP
(Restated - Note H)
Assets
Current Assets	D	$	77,773		$	78,961		$	89,036		$	89,345
Petroleum and natural gas properties	F		2,600,834			2,585,196			2,461,045			2,446,201
Accumulated depletion and depreciation	A		(1,641,208	)		(1,779,999	)		(1,491,307	)		(1,638,893	)
Petroleum and natural gas properties			959,626			805,197			969,738			807,308
Deferred charges and other assets			4,475			4,475			9,038			9,038
Goodwill			37,755			37,755			37,755			37,755
		$	1,079,629		$	926,388		$	1,105,567		$	943,446
Liabilities and Unitholders’ Equity (Deficit)
Current Liabilities	D	$	213,593		$	219,589		$	223,947		$	230,924
Long Term Debt			209,691			209,691			209,799			209,799
Convertible Debentures	E		18,906			19,846			73,766			77,464
Deferred Obligations			2,391			2,391			4,558			4,558
Asset Retirement Obligation			39,855			39,855			33,010			33,010
Unit-Based Compensation Liability			-			40,723			-			-
Future/Deferred Income Taxes	A,D,H		118,858			70,775			159,745			98,518
			603,294			602,870			704,825			654,273
Non-controlling Interest	B		17,187			-			12,810			-
Temporary Equity			-			1,726,662			-			1,291,405
Unitholders’ Capital	B		637,156			-			555,020			-
Conversion Feature of Debentures	E		940			-			3,698			-
Contributed Surplus	B,C		13,357			-			10,332			-
Deficit			(192,305	)		(1,403,144	)		(181,118	)		(1,002,232	)
			459,148			(1,403,144	)		387,932			(1,002,232	)
		$	1,079,629		$	926,388		$	1,105,567		$	943,446

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

For the years ended December 31		2006			2005
Operating Activities
Net income	$	122,271		$	68,274
Unit based compensation		35,616			21,927
Amortization of deferred charges		1,267			1,492
Unrealized foreign exchange gain		(108	)		(6,784	)
Depletion, depreciation and accretion		143,784			152,384
Accretion on debentures		189			321
Unrealized (gain) loss on financial derivatives		930			(5,170	)
Future income taxes		(27,743	)		(4,979	)
Change in non-cash working capital		(9,058	)		(20,212	)
Asset retirement expenditures		(1,747	)		(1,637	)
Decrease in deferred charges and other assets		(1,875	)		(977	)
Cumulative effect of change in accounting policy		(1,544	)		-
Cash from Operating Activities	$	261,982		$	204,639
Cash Used in Investing Activities	$	(132,945	)	$	(151,228	)
Cash Used in Financing Activities	$	(129,037	)	$	(53,411	)

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 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.

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 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 $8.8 million less depletion record under U.S. GAAP for the year ended December 31, 2005 ($14.8 million less depletion - 2005).

(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 Emerging Issues Task Force (“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 $1,726.7 million as at December 31, 2006 and $1,265.1 million as at December 31, 2005 which represents the 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 Income (Deficit) are a charge of $364.9 million for 2006 and $350.5 million for 2005.

In compliance with EITF D-98, the Trust also re-classed to Temporary Equity $26.3 million in 2005 of Contributed Surplus relating to the intrinsic value of Trust Unit Rights outstanding at year-end. No amount has been reclassed in 2006 due to the adoption of Statement of Financial Accounting Standards 123R - “Share-Based Payments”.

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. Previously 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. 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 $28.2 million of additional compensation expense was recorded in 2006.

(D) Derivative Instruments and Hedging

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, 2006 , the Trust recorded an additional liability under U.S. GAAP of $6.0 million and an additional asset of $1.2 million (December 31, 2005 - additional asset of $0.3 million and an additional liability of $7.0 million) related to financial instruments not required to be measured at fair value for Canadian GAAP purpose.

Unrealized gain / (loss) on derivatives related to:

		2006			2005
Commodity Prices and Currency Swaps	$	(382	)	$	13,456
Interest Swaps (Interest)		(548	)		(8,286	)
	$	(930	)	$	5,170

(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. Under U.S. GAAP, the convertible debentures in their entirety are classified as debt. As a result $0.9 million has been reclassified to liabilities from equity.

(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 $16.6 million (2005 - $18.0 million) and a decrease in future tax liability of $6.3 million (2005 - $6.8 million).

(G) Other Comprehensive Income

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

(H) 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.

In 2005 and prior years, the Trust did not recognize the effect of changes in enacted tax rates on the difference between temporary differences under U.S. GAAP and those under Canadian GAAP. This has been corrected and the prior year amounts have been restated. As a result, opening retained earnings in 2005 decreased by $13.4 million and future tax liability has increased by the same amount. The restatement has no impact on 2005 net income or net income per trust unit.

(I) Consolidated Statement of Cash Flows

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

(J) Earnings Per Unit

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.

Recent Developments in U.S. Accounting

On January 1, 2007, the Trust will be required to adopt for U.S. GAAP purposes, FASB Interpretation No. 48 - “Accounting fro Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”. This Interpretation provides disclosure and recognition criteria for uncertain tax positions taken in a previously filed tax return or expected to be taken in a future tax returns. Guidance is also provided for the de-recognition of previously recognized tax benefits. The Trust is currently assessing the impact this Interpretation will have on its consolidated financial statements.

In September 2006, the FASB issued SFAS No 157 - Fair Value Measurements. This Statement defines fair value and establishes a framework for measuring fair value and expands disclosures about fair value. This Statement applies when other accounting pronouncements that require fair value measurements and does not require new fair value measurements. The Trust will be required to adopt this statement as of January 1, 2008. The Trust is assessing the impact this Statement will have on its consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159 - “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115”. Under this Statement an entity will be permitted to choose to measure many financial instruments and certain other items at fair value. The Statement would be effective for financial statements issued for fiscal years beginning after November 15, 2007. The Trust is assessing the impact this statement will have on its consolidated financial statements.

On January 1, 2007, the Trust will be required to adopt Emerging Issues Task Force Abstract No. 04-13 - “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. Under this abstract requires purchases and sales of inventory with the same counterparty in contemplation of one another be recorded on a net basis. Adoption of this Abstract will have no impact on net earnings of the Trust.

Recent developments in Canadian Accounting

Financial Instruments

Effective January 1, 2007, the Trust will be required to adopt the Canadian Institute of Chartered Accountants (“CICA”) Section 1530 “Comprehensive Income”, Section 3251 “Equity”, and Section 3855 “Financial Instruments - Recognition and Measurement”. It is also the Trust’s intention to early adopt Section 3862 “Financial Instruments - disclosure” and Section 3863 “Financial Instruments - presentation” in place of Section 3861 “Financial Instruments - disclosure and presentation”. Under the new standards a new financial statement, Consolidated Statement of Other Comprehensive Income, has been introduced that will provide for certain gains and losses, such as changes in fair value of hedging instruments, to be temporarily recorded outside the income statement. 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 costs. The standards also provide guidance on when gains and losses as a result of changes in fair values are to be recognized in the income statement. In addition, the requirements for hedge accounting have been clarified under the new standards. The Company is assessing the impact on its Consolidated Financial Statements.

A new location for recognizing certain gains and losses - other comprehensive income - has been introduced with the issuance 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.

Capital Disclosures

In December 2006, the CICA issued Section 1535 “Capital Disclosures”. Under the new standard, which is effective for fiscal years beginning on or after October 1, 2007, an entity is required to provide additional disclosure about its objectives, policies and process for managing capital. The Trust does not expect application of this new standard to have a material impact on its consolidated financial statements.

Accounting Changes

Effective January 1, 2007, the Trust will be required to adopt the CICA 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. The application of this new standard will not have a material impact on the Trust’s consolidated financial statements.