Baytex Energy (BTE) 40-F 2003 FY Annual report (Canada)

Exhibit 2

Consolidated Financial Statements of

BAYTEX ENERGY TRUST

December 31, 2003

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.

(signed) "Raymond T. Chan"	(signed) "Daniel G. Belot"
Raymond T. Chan, CA	Daniel G. Belot
President and Chief Executive Officer	Vice President, Finance and Chief Financial Officer
Baytex Energy Ltd.	Baytex Energy Ltd.
March 5, 2004

Auditors’ Report

To the Board of Directors of Baytex Energy Ltd.

We have audited the consolidated balance sheets of Baytex Energy Trust (the “Trust”) as at December 31, 2003 and 2002 and the consolidated statements of operations and accumulated deficit and of 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, 2003 and 2002 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

On March 5, 2004, 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 17, Differences Between Canadian and United States Generally Accepted Accounting Principles.

	(signed) “Deloitte & Touche LLP”
Calgary, Alberta, Canada	Chartered Accountants
March 5, 2004

COMMENT BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING

To the Board of Directors of Baytex Energy Ltd.

In the United States of America, reporting standards for auditors 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 financial statements.  As discussed in Note 3 to the consolidated financial statements of Baytex Energy Trust (the “Trust”), in 2003, the Trust adopted recommendations with respect to determining unit-based compensation to conform to new recommendations of Section 3870 of the Canadian Institute of Chartered Accountants and in 2002, the Trust changed its method for accounting for foreign currency translation to conform to new recommendations of Section 1650 of the Canadian Institute of Chartered Accountants. Our report to the board of directors of Baytex Energy Ltd. and the unitholders of the Trust dated March 5, 2004 is expressed in accordance with Canadian reporting standards, which do not require a reference to such changes in accounting principles in the auditors’ report when the changes are properly accounted for and adequately disclosed in the financial statements.

	(signed) “Deloitte & Touche LLP”
Calgary, Alberta, Canada	Chartered Accountants
March 5, 2004

Baytex Energy Trust

Consolidated Balance Sheets

As at December 31, 2003 and 2002

(thousands of Canadian dollars)

	2003			2002
Assets
Current assets
Cash and short-term investments	$	53,731		$	4,098
Accounts receivable	48,608			52,667
Crude oil inventory	5,900			—
	108,239			56,765
Deferred charges and other assets	7,764			8,679
Petroleum and natural gas properties (note 5)	843,133			932,316
	$	959,136		$	997,760
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	80,126		$	92,563
Distributions payable to unitholders	9,123			—
	89,249			92,563
Long-term debt (note 7)	232,562			326,977
Deferred credits (note 8)	—			12,181
Provision for future site restoration costs	23,483			21,950
Future income taxes (note 12)	174,385			184,402
	519,679			638,073
Commitments and contingencies (note 16)
Unitholders’ Equity
Unitholders’ capital (note 9)	446,594			398,176
Exchangeable shares (note 9)	26,372			—
Contributed surplus (note 10)	224			—
Accumulated distributions	(33,382		)	—
Accumulated deficit	(351		)	(38,489		)
	439,457			359,687
	$	959,136		$	997,760

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 Accumulated Deficit

Years Ended December 31, 2003 and 2002

(thousands of Canadian dollars, except per unit data)

	2003			2002
Revenue
Petroleum and natural gas sales	$	351,404		$	365,860
Royalties	(67,175		)	(58,922		)
	284,229			306,938
Expenses
Operating	86,034			75,228
General and administrative	8,927			6,743
Unit based compensation (note 10)	739			—
Interest (note 7)	23,548			25,217
Costs on redemption and exchange of notes (note 7)	44,771			—
Foreign exchange gain (note 7)	(52,101		)	(2,691		)
Depletion and depreciation	116,317			106,834
Site restoration costs	2,973			2,799
Reorganization costs (note 4)	18,851			—
	250,059			214,130
Income before income taxes	34,170			92,808
Income taxes (recovery) (note 12)
Current	9,663			9,716
Future	(13,631		)	37,956
	(3,968		)	47,672
Net income	38,138			45,136
Deficit, beginning of year, as previously reported	(38,489		)	(75,954		)
Accounting policy change for foreign exchange (note 3)	—			(7,671		)
Deficit, beginning of year, as restated	(38,489		)	(83,625		)
Accumulated deficit, end of year	$	(351	)	$	(38,489	)
Net income per trust unit (note 11)
Basic	$	0.69		$	0.86
Diluted	$	0.67		$	0.85

See accompanying notes to the consolidated financial statements.

Baytex Energy Trust

Consolidated Statements of Cash Flows

Years Ended December 31, 2003 and 2002

(thousands of Canadian dollars)

	2003			2002
Cash provided by (used in):
Operating activities
Net income	$	38,138		$	45,136
Items not affecting cash:
Unit based compensation (note 10)	739			—
Amortization of deferred charges	1,027			1,052
Costs on redemption and exchange of notes (note 7)	44,771			—
Foreign exchange gain	(52,101		)	(2,691		)
Depletion and depreciation	116,317			106,834
Site restoration costs	2,973			2,799
Future income taxes (recovery)	(13,631		)	37,956
Cash flow from operations	138,233			191,086
Change in non-cash working capital (note 13)	(8,060		)	1,272
(Increase) decrease in deferred charges and other assets	211			(1,057		)
Decrease in deferred credits	(2,213		)	(18,694		)
	128,171			172,607
Financing activities
Redemption of senior secured notes (note 7)	(89,950		)	—
Decrease in bank loan and other debt	—			(76,254		)
Increase in deferred charges and other assets	(7,425		)	—
Increase in deferred credits	—			12,181
Issue of trust units (note 9)	61,525			—
Payment of distributions	(24,259		)	—
Issue of common shares (note 9)	37,049			3,497
Repurchase of common shares	—			(55		)
	(23,060		)	(60,631		)
Investing activities
Petroleum and natural gas property expenditures	(186,756		)	(182,048		)
Disposal of petroleum and natural gas properties	137,493			55,580
Properties held for sale	—			(46,895		)
Change in non-cash working capital (note 13)	(6,215		)	65,485
	(55,478		)	(107,878		)
Change in cash and short-term investments during the year	49,633			4,098
Cash and short-term investments, beginning of year	4,098			—
Cash and short-term investments, end of year	$	53,731		$	4,098

See accompanying notes to the consolidated financial statements.

Baytex Energy Trust

Notes to the Consolidated Financial Statements

Years Ended December 31, 2003 and 2002

(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, Baytex Energy Ltd. (the “Company”) and Crew Energy Inc. (“Crew”).  Under the Plan of Arrangement, the Company transferred to Crew a portion of the producing and exploratory oil and natural gas assets.  For each common share of the Company, shareholders received either one unit of the Trust and one-third of a common share of Crew, or one exchangeable share exchangeable initially into one trust unit and one-third of a common share of Crew.  The Trust is an open-ended investment trust created pursuant to a trust indenture.  Subsequent to the Plan of Arrangement, the Company is a wholly owned subsidiary of the Trust.

Prior to the Plan of Arrangement, the consolidated financial statements included the accounts of the Company and its subsidiaries and partnership.  After giving effect to the Plan of Arrangement, the consolidated financial statements have been prepared on a continuity of interests basis which recognizes the Trust as the successor to the Company.  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 wholly owned 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.

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 gross proved petroleum and natural gas reserves.  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”).  Under this test, an estimate is made of the ultimate recoverable amount from future net revenues using proved reserves plus the net costs of major development projects and unproved properties, less future removal and site restoration costs, overhead, financing costs and income taxes, using period end prices and costs.  If the net carrying costs exceed the ultimate recoverable amount, additional depletion and depreciation is provided.

Provision for Future Site Restoration Costs

Estimates are made of the future site restoration costs relating to the Trust’s petroleum and natural gas properties at the end of their economic life, based on year end values, in accordance with current legislative requirements and industry practice.  Annual charges are provided on a unit of production method.  Actual expenditures incurred are applied against the provision for future site restoration costs.

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.

Financial Instruments

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 derivative financial instruments for trading or speculative purposes.  Gains and losses on derivative contracts are recognized in income based on the underlying financial instrument or the future petroleum and natural gas production in same period that the transactions are settled.  The fair values of derivative instruments are not recorded in the consolidated balance sheet.

Gains and losses related to derivative financial instruments that have been closed prior to the end of the term are deferred and recognized in the consolidated statement of operations over the original term of the instrument.

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.

Flow-through Shares

The Company had financed a portion of its exploration and development activities through the issue of flow-through shares.  Under the terms of the flow-through share agreements, the tax attributes of the related expenditure are renounced to the subscribers.  Accordingly, the carrying value of the expenditures incurred and the shares issued are recorded net of tax benefits renounced to the subscribers. The Company records the gross carrying value of the expenditures and records a future tax liability for the tax benefits renounced to subscribers.

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.  Therefore, it is not possible to determine a fair value for the rights granted under the Plan using a traditional option pricing model and compensation expense has been determined based on the intrinsic value of the rights at the date of exercise or at the date of the consolidated financial statements for unexercised rights.

Compensation expense associated with rights granted under the plan is recognized in earnings over the vesting period of the plan with a corresponding increase or decrease in contributed surplus.  Changes in the intrinsic value of unexercised rights after the vesting period are recognized in income in the period of change with a corresponding increase or decrease in contributed surplus.  The exercise of trust unit rights are recorded as an increase in trust units with a corresponding reduction in contributed surplus.

This method of determining compensation expense may result in large fluctuations, even recoveries, in compensation expense due to changes in the underlying trust unit price. Recoveries of compensation expense will only be recognized to the extent of previously recorded cumulative compensation expense associated with rights outstanding at the date of the financial statements.

Per-unit Amounts

Basic net income per unit is computed by dividing net income by the weighted average number of trust units, including exchangeable shares, outstanding during the year.  Diluted per unit amounts reflect the potential dilution that could occur if trust unit rights were exercised.  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 are assumed to be used to purchase trust units at the average market price during the period.

3.             CHANGES IN ACCOUNTING POLICIES

Unit-based Compensation Plan

The Trust has elected to prospectively adopt amendments to CICA Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments” pursuant to the transitional provisions contained therein.  Under this amended standard, the Trust must account for compensation expense based on the fair value of rights granted under its unit-based compensation plan.  As the Trust is unable to determine the fair value of the rights granted, compensation expense has been determined based on the intrinsic value of the rights at the exercise date or at the date of the consolidated financial statements for unexercised rights.  Compensation expense of $0.22 million was recorded as non cash general and administrative expense for all trust unit rights granted during 2003, with a corresponding amount recorded as contributed surplus.

The adoption of these amendments also impacted the stock options outstanding prior to the Plan of Arrangement.  Compensation expense of $0.52 million was recorded as non-cash general and administrative expense for all stock options granted on or after January 1, 2003, with a corresponding amount recorded as contributed surplus.  For stock options granted prior to January 1, 2003, the pro forma earnings impact of related stock-based compensation expense is disclosed (see Note 10).

Foreign Currency

Effective January 1, 2002, the Company retroactively adopted the CICA amended accounting standard with respect to accounting for foreign currency translation.  As a result of the amendments, all exchange gains and losses on long-term monetary items that do not qualify for hedge accounting are recognized in income.  Previously, these exchange gains and losses were deferred and amortized over the remaining life of the monetary item.  The impact of the amended standard on the year ended December 31, 2002 was to increase net income by $1.8 million.  The effect of this change on the December 31, 2001 Consolidated Balance Sheet is an elimination of the unrealized foreign exchange loss of $13.7 million, a decrease in future income taxes of $6.0 million, and an increase in the deficit of $7.7 million.

4.             TRANSFER OF ASSETS AND LIABILITIES PURSUANT TO PLAN OF ARRANGEMENT

Under the Plan of Arrangement (note 1), the Company transferred to Crew a portion of the Company’s producing and exploratory petroleum and natural gas assets.  As this was a related party transaction, assets and liabilities were transferred at carrying value as follows:

Petroleum and natural gas assets and equipment	$	21,244
Future income tax asset	3,278
Total assets transferred	24,522
Provision for future site restoration	(559		)
Net assets transferred and reduction in share capital (note 9)	$	23,963

Reorganization costs of $18.9 million were expensed in the consolidated statements of operations as a result of the Plan of Arrangement.

5.             PETROLEUM AND NATURAL GAS PROPERTIES

	As at December 31,
	2003			2002
Petroleum and natural gas properties	$	2,016,382		$	1,989,246
Accumulated depletion and depreciation	(1,173,249		)	(1,056,930		)
	$	843,133		$	932,316

During 2003, $4.4 million (2002 - $6.7 million) of corporate expenses relating to exploration and development activities were capitalized.  No corporate expenses have been capitalized since the inception of operations as a trust effective September 2, 2003.  In calculating the depletion and depreciation provision for 2003, $51.1 million (2002 - $80.3 million) of costs relating to undeveloped properties and materials and supplies of $4.0 million (2002- $5.5 million) were excluded from costs subject to depletion and depreciation.

6.             BANK CREDIT FACILITIES

On September 3, 2003, the Company entered into a new credit agreement with a syndicate of chartered banks.  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 facilities aggregating $165 million are subject to semi-annual review beginning in November 2003 and are secured by a floating charge over all of the Company’s assets.  At December 31, 2003, there were no amounts outstanding under the bank credit facilities.

7.             LONG-TERM DEBT

	As at December 31,
	2003		2002
Senior secured notes (2002 US$57,000,000)	$	—	$	90,037
10.5% senior subordinated notes (2003 - US$247,000; 2002 - US$150,000,000)	319		236,940
9.625% senior subordinated notes (2003 -US$179,699,000)	232,243		—
	$	232,562	$	326,977

Senior Secured Notes

On November 13, 1998, the Company issued US$57 million of senior secured notes, bearing interest at 7.23 percent payable quarterly with principal repayable on November 13, 2004.  In May 2003, the Company redeemed the outstanding senior secured notes for a total cash payment of $90 million, resulting in a cost of $4.7 million on the redemption.  Foreign exchange gains were included in income until the redemption of the notes.

Senior Subordinated Notes

On February 12, 2001, the Company issued US$150 million of senior subordinated notes (“Old 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.

On July 9, 2003, the Company completed an exchange offer related to its Old Notes.  The Company issued US$179.7 million of 9.625 percent senior subordinated notes due July 15, 2010 (“New Notes”) in exchange for US$149.8 million of the Old Notes and incurred a non-cash loss of $40.0 million on the completion of this transaction, which was recognized in income.  The New Notes are unsecured and are subordinate to the Company’s bank credit facilities.

Interest Expense

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

	2003		2002
Bank loan	$	675	$	760
Amortization of deferred charges	1,027		1,052
Long-term debt	21,846		23,405
Total interest	$	23,548	$	25,217

8.             DEFERRED CREDITS

	As at December 31,
	2003		2002
Deferred interest swap settlement	$	—	$	12,181

In August 2002, the Company terminated all outstanding interest rate swap agreements for total proceeds of $14.1 million.  This amount was deferred and was being amortized as a reduction of interest expense over the original terms of the agreements.  The amortization was terminated when the senior secured notes were redeemed and when the exchange offer related to the Old Notes was concluded (note 7).  The residual balance was included in the cost on redemption and exchange of notes.

9.             UNITHOLDERS’ CAPITAL AND EXCHANGEABLE SHARES

Trust Units

The Trust is authorized to issue an unlimited number of trust units.  Pursuant to the Plan of Arrangement, 53,304,858 trust units and 4,732,326 exchangeable shares were issued on September 2, 2003 on the exchange of the common shares of the Company.

On December 12, 2003, the Trust issued 6,500,000 trust units at $10.00 per unit for gross proceeds of $65 million pursuant to a prospectus.

Trust Units

	Number of units	Amount
Issued September 2, 2003 pursuant to Plan of Arrangement	53,305	$	377,419
Issued on conversion of Exchangeable Shares	1,016	7,135
Unit-based compensation	—	515
Issued for cash, net of expenses	6,500	61,525
Balance December 31, 2003	60,821	$	446,594

Exchangeable Shares

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 of the five-day trading period ending on the record date.  The exchange ratio at December 31, 2003 was 1.04530 trust units per exchangeable share.  Cash distributions are not paid on the exchangeable shares.  The exchangeable shares are not publicly traded.

Exchangeable Shares

	Number of shares		Amount
Issued September 2, 2003 pursuant to Plan of Arrangement	4,732		$	33,507
Exchanged for trust units	(1,007	)	(7,135		)
Balance December 31, 2003	3,725		$	26,372

Under the Plan of Arrangement, shareholders of the Company received one unit of the Trust or one exchangeable share and one-third of a share of Crew for each common share held.

Common shares of Baytex Energy Ltd.

	Number of shares		Amount
Balance December 31, 2001	52,008		$	394,734
Exercise of stock options	820		3,497
Normal course issuer bid	(9	)	(55		)
Balance December 31, 2002	52,819		398,176
Flow-through shares issued	103		810
Future tax related to flow-through shares	—		(336		)
Exercise of stock options (note 10)	5,115		36,239
Transfer of assets under Plan of Arrangement (note 4)	—		(23,963		)
Balance September 2, 2003 prior to Plan of Arrangement	58,037		410,926
Trust units issued	(53,305	)	(377,419		)
Exchangeable shares issued	(4,732	)	(33,507		)
Balance December 31, 2003	—		$	—

Flow-through shares

In accordance with the terms of flow-through share offerings entered into by the Company and pursuant to certain provisions of the Income Tax Act (Canada), the Company fulfilled its commitment to renounce for income tax purposes exploration expenditures of $0.8 million in 2003 to the subscribers of the flow-through shares.

10.          TRUST UNIT RIGHTS AND STOCK OPTIONS

Effective September 2, 2003, the Trust established a Trust Unit Rights Incentive Plan to replace the stock option plan of the Company.  A total of 5,800,000 Trust Unit Rights are reserved for issue under the Plan.   Trust Unit Rights are granted at the market price of the trust units at the time of the grant, vest over three years and have a term of five years.

The Trust Unit Rights Incentive Plan allows for the exercise price of the rights to be reduced in future periods by a portion of the future distributions provided a certain threshold return on assets is met.  The Trust has determined that the amount of the reduction cannot be reasonably estimated, as it is dependent upon a number of factors including, but not limited to, future trust unit prices, production of oil and natural gas, determination of amounts to be withheld from future distributions to fund capital expenditures, and the purchase and sale of oil and natural gas assets.  Therefore, it is not possible to determine a fair value for the rights granted under the plan.

Compensation expense is therefore determined based on the amount that the market price of the trust unit exceeds the exercise price for rights issued as at the date of the consolidated financial statements and is recognized in income over the vesting period of the plan.  The adoption of the amendments related to accounting for unit-based compensation results in compensation expense for year ended December 31, 2003 was $0.22 million (note 3).

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

	Number of Rights		Weighted averageexercise price (1)
Initial grant September 9, 2003	2,593		$	10.23
Granted	380		$	9.60
Cancelled	(118	)	$	10.23
Balance December 31, 2003	2,855		$	10.15

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

The following table summarizes information about the unit rights outstanding at December 31, 2003:

	Number Outstanding at December 31, 2003	Weighted Average Remaining Term	Weighted Average Exercise Price		Number Exercisable at December 31, 2003	Weighted Average Exercise Price
		(years)
Balance December 31, 2003	2,855	4.7	$	10.15	—	—

The Company had a stock option plan prior to the Plan of Arrangement.  The outstanding stock options of the Company were exercised or cancelled as follows:

	Number of options		Weighted average exercise price
Balance December 31, 2002	5,126		$	6.98
Granted	121		$	9.28
Exercised	(5,115	)	$	7.07
Cancelled	(132	)	$	5.44
Balance December 31, 2003	—		—

The adoption of the amendments related to accounting for unit-based compensation also impacted the accounting for stock options granted by the Company to employees before the implementation of the Plan of Arrangement.  Compensation expense of $0.52 million was recorded as non-cash general and administrative expense for all stock options granted by the Company on or after January 1, 2003, with a corresponding amount recorded as trust units on exercise of the options, with expenses in the first and second quarters increased by $0.32 million and $0.20 million, respectively.  Accordingly, quarterly net income in such quarters previously reported as $32.9 million and $41.8 million would be revised to $32.6 million and $41.6 million, respectively.  There were no changes to the expenses or the net loss of the third quarter of 2003.

Compensation expense for options granted during 2003 was based on the estimated fair values at the time of the grant and the expense was recognized over the vesting period of the option.  For options granted prior to January 1, 2003, the pro forma earnings impact of related stock-based compensation expense is as follows:

	Year Ended December 31
	2003			2002
Net income as reported	$	38,138		$	45,136
Stock-based compensation expense	(5,522		)	(612		)
Pro forma	$	32,616		$	44,524
Net income per unit
Basic as reported	$	0.69		$	0.86
Pro forma	$	0.59		$	0.85
Diluted as reported	$	0.67		$	0.85
Pro forma	$	0.58		$	0.83

The weighted average fair market value of options granted during the year ended December 31, 2003 was $4.21 per option (2002 - $3.65 per option).  The fair value of the stock options granted was estimated on the grant date based on the Black-Scholes option-pricing model using the following assumptions: risk free interest rate of 4.5 percent; expected life of four years; and expected volatility of 52 percent.

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 exchangeable shares outstanding at year-end, converted at the year-end exchange ratio, have been included in the calculation of the weighted average number of trust units outstanding:

	2003	2002
Weighted average number of units (shares) outstanding	53,995	52,298
Trust units issuable on conversion of exchangeable shares	1,535	—
Weighted average number of units (shares) outstanding, basic	55,530	52,298
Dilutive effect of trust unit incentive rights (stock options)	990	939
Weighted average number of units (shares) outstanding, diluted	56,520	53,237

The dilutive effect of trust unit incentive rights above did not include 2.7 million trust unit rights (2002- 2.8 million stock options) because the respective exercise prices exceeded the average market price of the trust units during the year.

12.          INCOME TAXES (RECOVERY)

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

	2003			2002
Income before income taxes	$	34,170		$	92,808
Expected income taxes at the statutory rate of 42.5% (2002 - 44.0%)	$	14,526		$	40,743
Increase (decrease) in taxes resulting from:
Crown royalties	21,451			21,153
Resource allowance	(18,334		)	(26,308		)
Alberta royalty tax credit	(213		)	(219		)
Net income of the Trust	(14,191		)	—
Non-taxable portion of foreign exchange gain	(11,074		)	—
Rate change	(6,216		)	(138		)
Non-cash general and administrative	314			—
Other	106			2,725
Large corporation tax and provincial capital tax	9,663			9,716
Provision for (recovery of) income taxes	$	(3,968	)	$	47,672

The components of future income taxes are as follows:

	As at December 31,
	2003			2002
Future income tax liabilities:
Capital assets	$	200,526		$	202,429
Other	2,560			—
Future income tax assets:
Provision for future site restoration	(8,907		)	(9,638		)
Reorganization costs	(19,794		)	(2,833		)
Loss carry-forward	—			(323		)
Other	—			(5233		)
Future income taxes	$	174,385		$	184,402

13.          CASH FLOW INFORMATION

Increase (Decrease) in Non-Cash Working Capital Items

	2003			2002
Current assets	$	(1,840	)	$	38,528
Current liabilities	(12,435		)	28,229
	$	(14,275	)	$	66,757

	2003			2002
Changes in non cash working capital related to:
Operating activities	$	(8,060	)	$	1,272
Investing activities	(6,215		)	65,485
	$	(14,275	)	$	66,757

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

	2003		2002
Interest	$	24,449	$	25,482
Current income taxes (refund)	$	12,557	$	(3,298	)

14.          FINANCIAL INSTRUMENTS

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 long-term borrowings approximate their carrying amounts due to the short-term maturity of these instruments.  At December 31, 2003, the trading value of the Company’s senior subordinated term notes was 105 percent in relation to par (2002- 105 percent).

15.          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.  In 2003, petroleum and natural gas sales were reduced by $33.8 million (2002 - $8.3 million) due to derivative contracts.

At December 31, 2003, the Trust had derivative contracts for the following:

	Period	Volume	Price	Index
Oil
Price collar	Calendar 2004	5,000 bbls/d	US$24.00 – $28.60	WTI
Price collar	Calendar 2004	1,500 bbls/d	US$24.00 – $29.05	WTI
Price collar	Calendar 2004	1,500 bbls/d	US$24.00 – $29.08	WTI
Price collar	Calendar 2004	1,000 bbls/d	US$24.00 – $29.38	WTI
Price collar	Calendar 2004	1,000 bbls/d	US$24.00 – $29.48	WTI
Price collar	Calendar 2004	2,000 bbls/d	US$24.00 – $30.55	WTI
Price collar	Calendar 2004	3,000 bbls/d	US$24.00 – $32.05	WTI

The fair value of the oil derivative contracts at December 31, 2003 is an unrecognized liability of $13.8 million.

	Period	Amount	Exchange Rate
			Floor	Cap
Foreign currency
Collar	Calendar 2004	US$3,000,000 per month	CAD/USD $1.3100	CAD/USD $1.3400
Collar	Calendar 2004	US$3,000,000 per month	CAD/USD $1.3280	CAD/USD $1.3560
Collar	Calendar 2004	US$3,000,000 per month	CAD/USD $1.3160	CAD/USD $1.3365
Collar	Calendar 2004	US$3,000,000 per month	CAD/USD $1.3400	CAD/USD $1.3665

The fair value of the foreign currency contracts at December 31, 2003 is an unrecognized asset of $3.7 million.

	Period	Principal	Rate
Interest rate swap
	November 2003 to July 2010	US$179,669,000	3-month LIBOR plus 5.2%

The fair value of the interest rate swap at December 31, 2003 is an unrecognized asset of $3.9 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.

For the period November 2003 to March 2004, the Trust has entered into natural gas physical sales contracts with third parties for a total of 9.5 mmcf per day for prices collared between $5.28 and $8.57 per mcf.  For the period April 2004 to October 2004, the Trust has entered into natural gas physical sales contracts with third parties for a total of 9.5 mmcf per day for prices collared between $4.75 and $6.75 per mcf.

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.

Under the Net Profits Interests Agreement between the Company and the Trust, the Company will establish in 2004 a reclamation fund to fund the payment of environmental and site restoration costs.

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

Reconciliation of consolidated financial statements to United States Generally Accepted Accounting Principles

The consolidated financial statements included in the Baytex Energy Trust 2003 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 carrying 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 or fair value of unproven properties (“ceiling test”).  Under Canadian GAAP, this ceiling test is calculated without application of a discount factor, but interest and general and administrative expenses are deducted.

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 amortization will differ in subsequent years resulting in U.S. to Canadian GAAP differences.

(b)           The Financial Accounting Standards Board (“FASB”) has issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”).  FAS 143 was adopted prospectively on January 1, 2003 and requires liability recognition for retirement obligations associated with tangible long-lived assets.  The initial measurement of the asset retirement obligation is required to be at fair value.  The asset retirement cost equal to the fair value of the retirement obligation is to be capitalized as part of the cost of the related long-lived asset and amortized to expense over the useful life of the asset.  The liability accretes until the expected settlement of the retirement obligation.

This change in accounting policy has been accounted for as a cumulative effect adjustment in the consolidated statement of operations as a loss of $7.1 million, net of income taxes of $5.6 million.

The change in the asset retirement obligation since January 1, 2003 is as follows:

Asset retirement obligation January 1, 2003	$	52,244
Increase in retirement obligations	4,010
Abandonment expenditures	(880		)
Property disposition	(3,335		)
Accretion	3,957
Asset retirement obligation December 31, 2003	$	55,996

Prior to January 1, 2003, under U.S. GAAP, the provision for future site restoration costs is recorded as a reduction of capital assets.  Under Canadian GAAP, effective January 1, 2004, the Trust will adopt new Canadian accounting standards for accounting for asset retirement obligations which are expected to eliminate this difference in future years.

(c)           FASB has issued Statement of Financial Accounting Standards No. 123, “Accounting for Stock-based Compensation” (“FAS 123”) which 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”), for all stock options issued by the Company to employees before the effective date of the Plan of Arrangement.  Since all stock options were granted with exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income at the time of the option grants. Had compensation cost for the Company’s stock options been determined based on the fair market value at the grant dates of the awards consistent with methodology prescribed by FAS 123, the net income (loss) and net income (loss) per unit for years ended December 31, 2003 and 2002 would have been the pro forma amounts indicated below:

	Year Ended December 31
	2003			2002
Net income (loss) as reported under U.S. GAAP	$	(9,392	)	$	22,889
Stock based compensation expense	(5,522		)	(612		)
Pro forma	$	(14,914	)	$	22,277
Net income (loss) per unit:
Basic as reported	$	(0.17	)	$	0.44
Pro forma	$	(0.27	)	$	0.43
Diluted as reported	$	(0.17	)	$	0.43
Pro forma	$	(0.27	)	$	0.42

The weighted average fair market value of stock options granted by the Company (before the effective date of the Plan of Arrangement) in 2003 was $4.21 per stock option (2002 - $3.65).  The fair value of the stock options granted was estimated on the grant date based on the Black-Scholes option-pricing model using the following assumptions: risk free interest rate of 4.5 percent; expected life of four years; and expected volatility of 52 percent.

APB 25 also requires recognition of compensation cost with respect to changes in intrinsic value for variable employee stock compensation plans.  As the stock options granted by the Company were modified as part of the Plan of Arrangement, and in prior years certain stock options were repriced, the modified stock options are subject to variable plan accounting, which results in an increase of compensation cost of $12.0 million for the year ended December 31, 2003 (2002 — reduction in compensation cost of $3.7 million) for U.S. GAAP purposes.

After the effective date of the Plan of Arrangement, the Trust established a Trust Unit Incentive Right Plan to replace the stock option plan of the Company.  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.  Accordingly, compensation expense is determined as the excess of the market price over the exercise 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 does not result in a difference between Canadian and U.S. GAAP.

(d)           The Company adopted the liability method of accounting for income taxes in 2000 retroactively without restatement.  The liability method of accounting for income taxes is similar to Statement of Financial Accounting Standards No. 109, which requires the use of the asset and liability method. The Canadian GAAP liability method requires the measurement of future income tax liabilities and assets using income tax rates that reflect enacted income tax rate reductions provided it is more likely than not that the Company will be eligible for such rate reductions in the period of reversal. U.S. GAAP allows recording of such reductions only when claimed.

(e)           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”, 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 earnings 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 aspects of the hedge. Those methods must be consistent with the entity’s approach to managing risk.  As hedge accounting was not applied to the financial derivative contracts, at December 31, 2003, the Trust’s financial derivative instruments would be recorded as a liability on the consolidated balance sheet at their fair value of $6.2 million (2002 – $14.3 million).  FAS 133 also requires that gain and losses on financial derivative instruments be included in the statement of operations when terminated prior to the completion of the contract.  As a result, $12.2 million realized on the termination of interest rate swap derivative contracts would be included as an increase of the net income for December 31, 2002.   The net loss under U.S. GAAP for the year ended December 31, 2001 was reduced by $18.7 million for the amount realized on renegotiation of financial derivative contracts

(f)            The income tax effect of the items noted in (a) through (e) for the year ended December 31, 2003 is a decrease in income taxes of $21.0 million (2002 – decrease of $15.9 million).

(g)           Prior to January 1, 2000, the Trust recorded the renouncement of tax deductions resulting from the issuance of flow through shares by reducing petroleum and natural gas properties and unitholders’ capital be the estimated cost of the tax deductions renounced.  U.S. GAAP requires that flow-though shares be recorded at their fair value without any adjustment for the renouncement of tax deductions and that the estimated costs for the tax deductions be recorded as a future income tax liability rather than a reduction of petroleum and natural gas properties.  Subsequent to January 1, 2000, no differences arose in the accounting treatment of flowthrough shares under Canadian GAAP and U.S. GAAP.

(h)           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.

Consolidated Statements of Operations

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

	Years Ended December 31
	2003			2002
Net income (loss) for the year – Canadian GAAP	$	38,138		$	45,136
Adjustments:
Depletion (a)	(41,386		)	(2,613		)
Accretion (b)	(3,957		)
Compensation expense (c)	(11,972		)	(1,873		)
Deferred revenue (e)	—			(18,694		)
Interest rate swaps (e)	(12,181		)	12,181
Financial derivative instruments (e)	8,109			(27,193		)
Income taxes (f)	21,006			15,945
Net income (loss) from continuing operations before cumulative effect of change in accounting policy for asset retirement obligations	(2,243		)	22,889
Cumulative effect of change in accounting policy for asset retirement obligations (b)	(7,149		)	—
Net income (loss) for the year – U.S. GAAP	$	(9,392	)	$	22,889
Net income (loss) from continuing operations before cumulative effect of change in accounting policy for asset retirement obligations per unit
Basic	$	(0.04	)	$	0.44
Diluted	$	(0.04	)	$	0.43
Net income (loss) per unit – U.S. GAAP
Basic	$	(0.17	)	$	0.44
Diluted	$	(0.17	)	$	0.43

Consolidated Balance Sheets

The application of U.S. GAAP would have the following effect on the consolidated balance sheets as reported:

		December 31, 2003
		As Reported			Increase (Decrease)			U.S. GAAP
Assets:
Capital assets	(a)	$	843,133		$	(161,477	)	$	697,220
	(b)				15,564
Liabilities:
Asset retirement obligations (b)		—			55,996			55,996
Provision for site restoration costs (b)		23,483			(23,483		)	—
Financial derivative instruments (e)		—			6,191			6,191
Future income taxes (f)		174,385			(70,961		)	103,424
Unitholders’ equity:
Unitholders’ capital (g)		446,594			13,942			460,536
Accumulated deficit – see below		(351		)	(135,030		)	(135,381		)

		December 31, 2002
		As Reported			Increase (Decrease)			U.S. GAAP
Assets:
Capital assets	(a)	$	932,316		$	(120,091	)	$	790,275
	(b)				(21,950		)
Liabilities:
Provision for site restoration costs (b)		21,950			(21,950		)	—
Financial derivative instruments (e)		—			14,300			14,300
Future income taxes (f)		184,402			(57,398		)	127,004
Deferred credits (e)		12,181			(12,181		)	—
Unitholders’ equity:
Unitholders’ capital		398,176			13,942			412,118
Accumulated deficit – see below		(38,489		)	(87,500		)	(125,989		)

	December 31,
	2003			2002
Accumulated deficit - Canadian GAAP	$	(351	)	$	(38,489	)
Adjustments to depletion (a)	(169,549		)	(128,163		)
Flow through share differences (g)	(13,942		)	(13,942		)
Accretion expense (b)	(3,957		)	—
Compensation expense (c)	(13,845		)	(1,873		)
Financial derivative instruments (e)	(6,191		)	(14,300		)
Deferred credits (e)	—			12,181
Adjustments to future income taxes (f)	79,603			58,597
Cumulative effect of change in accounting policy for asset retirement obligation (b)	(7,149		)	—
Accumulated deficit - U.S. GAAP	$	(135,381	)	$	(125,989	)

Consolidated Statements of Cash Flow

The application of U.S. GAAP would have the following effect on the operating activities of the consolidated statement of cash flow:

	Years Ended December 31
	2003			2002
Operating activities
Cash provided by (used in) operating activities – Canadian GAAP	$	128,171		$	172,607
Adjustments:
Depletion (a)	41,386			2,613
Accretion (b)	3,957
Compensation expense (c)	11,972			1,873
Deferred revenue (e)	—			18,694
Interest rate swaps (e)	(12,181		)	12,181
Financial derivative instruments (e)	(8,109		)	27,193
Income taxes (f)	(21,006		)	(15,945		)
Cash provided by (used in) operating activities – U.S. GAAP	$	144,190		$	219,216

Additional U.S. GAAP Disclosure

The Trust presents cash flow before changes in non-cash working capital and other items as a subtotal in the consolidated statement of cash flows.  This line item would not be presented in a cash flow statement prepared in accordance with U.S. GAAP.  This difference does not result in an adjustment to the financial results as reported under Canadian GAAP.

Recent Developments in U.S. Accounting

In May 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No.150 “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity”, which establishes standards for classification and measurement of certain financial instruments.  The adoption of this accounting standard did not have a material impact on the Trust.

In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities” (“FIN 46”).  FIN 46 provides criteria for identifying variable interest entities and for determining what entity, if any, should be included in consolidated financial statements.  In December 2003, the FASB issued FIN 46(R) to clarify some of the provisions of FIN 46 and to exempt certain entities from its requirements.  The

adoption on January 1, 2004 of this accounting standard is not anticipated to have a material impact on the Trust.

In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 104 “Revenue Recognition” (“SAB 104”), which will rescind accounting guidance contained in Staff Accounting Bulletin No. 101 related to multiple element revenue arrangements.  The changes noted in SAB 104 are not anticipated to have a material impact on the Trust’s financial position, results of operations or cash flows.