Harvest Energy Trust (HTE) 6-K Notice of Special Meeting of Harvest Securityholders

AUDITORS’ REPORT

To the Unitholders of Harvest Energy Trust

We have audited the amended consolidated balance sheets of Harvest Energy Trust as at December 31, 2004 and 2003 and the amended consolidated statements of income and accumulated income and cash flows for the years then ended. These amended financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these amended financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. These standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free from 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.

In our opinion, these amended consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2004 and 2003 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

((signed))
KPMG LLP
Chartered Accountants
Calgary, Canada
March 24, 2005, except for Notes 2j, 2l, 3, 11, 12, 13, 14, 15, 16, 20, 21 which are at December 20, 2005

AMENDED CONSOLIDATED BALANCE SHEETS

As at December 31

	(Restated, Note 3)			(Restated, Note 3)
(thousands of Canadian dollars)	2004			2003
Assets
Current assets
Accounts receivable	$	44,028		$	19,168
Current portion of derivative contracts [Note 16]		8,861			—
Prepaid expenses and deposits		3,014			12,131
		55,903			31,299
Deferred charges [Note 16]		25,540			1,989
Long term portion of derivative contracts[Note 16]		3,710			—
Capital assets [Notes 4 and 5]		918,397			210,543
Future income tax [Note 15]		—			12,609
Goodwill[Note 4]		43,832			—
	$	1,047,382		$	256,440
Liabilities and Unitholders’ Equity
Current liabilities
Accounts payable and accrued liabilities[Note 6]	$	76,251		$	18,083
Cash distribution payable		8,358			3,422
Current portion of derivative contracts[Note 16]		27,927			—
Bank debt[Note 8]		75,519			63,349
		188,055			84,854
Deferred gains[Note 16]		2,177			—
Convertible debentures[Notes 3 and 14]		25,750			—
Senior notes[Note 9]		300,500			—
Equity bridge notes[Notes 3, 10 and 17]		—			25,000
Asset retirement obligation[Notes 3 and 7]		90,085			42,009
Future income tax[Note 15]		34,671			—
		641,238			151,863
Non-controlling interest[Notes 3 and 13]		6,895			—
Unitholders’ equity
Unitholders’ capital[Note 11]		465,524			117,407
Equity component of convertible debentures[Notes 3 and 14]		116			—
Accumulated income		30,719			19,478
Contributed surplus		—			239
Accumulated distributions		(97,110	)		(32,547	)
		399,249			104,577
	$	1,047,382		$	256,440

Commitments, contingencies and guarantees [Note 19].
See accompanying notes to these amended consolidated financial statements.

Approved by the Board of Directors:

((signed))
John A. Brussa
Director

((signed))
Verne G. Johnson
Director

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AMENDED CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED INCOME
For the Years Ended December 31
	(Restated, Note 3)			(Restated, Note 3)
(thousands of Canadian dollars, except per Trust Unit amounts)	2004			2003
Revenue
Oil and natural gas sales	$	331,331		$	119,351
Royalty expense, net		(54,236	)		(16,412	)
		277,095			102,939
Expenses
Operating		73,442			36,045
General and administrative		8,621			4,101
Unit right compensation expense		11,359			239
Interest on short term debt[Note 3]		10,515			6,452
Interest on long term debt[Note 3]		11,183			—
Depletion, depreciation and accretion		102,776			35,727
Foreign exchange gain		(7,111	)		(4,374	)
Gains and losses on derivative contracts		63,701			18,924
		274,486			97,114
Income before taxes and non-controlling interest		2,609			5,825
Taxes
Large corporations tax		1,505			157
Future income tax recovery[Note 15]		(10,362	)		(8,978	)
		(8,857	)		(8,821	)
Net income before non-controlling interest	$	11,466		$	14,646
Non-controlling interest[Notes 3 and 13)		225			—
Net income for the year		11,241			14,646
Accumulated income, beginning of year		19,478			5,136
Retroactive application of change in accounting policy[Note 3]		—			(304	)
Accumulated income, end of year	$	30,719		$	19,478
Net income per trust unit, basic[Note 11]	$	0.45		$	1.16
Net income per trust unit, diluted[Note 11]	$	0.43		$	1.13

See accompanying notes to these amended consolidated financial statements.

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AMENDED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
	(Restated, Note 3)			(Restated, Note 3)
(thousands of Canadian dollars, except per Trust Unit amounts)	2004			2003
Cash provided by (used in)
Operating Activities
Net income for the year	$	11,241		$	14,646
Items not requiring cash
Depletion, depreciation and accretion		102,776			35,727
Unrealized foreign exchange (gain) loss		(5,537	)		1,432
Amortization of deferred finance charges		4,533			2,556
Unrealized loss on derivative contracts[Note 16]		11,274			—
Non-cash interest expense		25
Future tax recovery		(10,362	)		(8,978	)
Non-controlling interest		225
Non-cash unit right compensation expense		9,535			239
		123,710			45,622
Settlement of asset retirement obligations		(929	)		(577	)
Change in non-cash working capital		(11,103	)		(12,290	)
		111,678			32,755
Financing Activities
Issue of trust units, net of issue costs		164,743			61,691
Issue of bridge note payable		—			25,000
Repayment of bridge notes		—			(25,000	)
Issue of equity bridge notes[Notes 10 and 17]		30,000			33,500
Repayment of equity bridge notes[Notes 10 and 17]		(55,000	)		(8,500	)
Issuance of convertible debentures[Note 14]		160,000			—
Issue costs for convertible debentures		(7,201	)		—
Issue of senior notes		311,951			—
Repayment of bank debt, net		(44,661	)		15,263
Repayment of promissory note payable		—			(850	)
Financing costs		(13,770	)		(2,334	)
Cash distributions		(47,074	)		(18,488	)
Change in non-cash working capital		5,097			2,889
		504,085			83,171
Investing Activities
Additions to capital assets		(42,662	)		(27,209	)
Acquisition of Storm Energy Ltd.		(75,783	)		—
Property acquisitions		(513,865	)		(93,549	)
Change in non-cash working capital		16,547			329
		(615,763	)		(120,429	)
Decrease in cash and short-term investments		—			(4,503	)
Cash and short term investments, beginning of year		—			4,503
Cash and short term investments, end of year	$	—		$	—
Cash interest payments	$	5,521		$	2,866
Cash tax payments	$	2,298		$	157
Cash distributions declared per trust unit	$	2.40		$	2.40

See accompanying notes to these amended consolidated financial statements.

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NOTES TO AMENDED CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004 and 2003
(tabular amounts in thousands of Canadian dollars, except Trust Unit, and per Trust Unit amounts)

1.	Structure of the Trust
	Harvest Energy Trust (the “Trust”) is an open-ended, unincorporated investment trust formed under the laws of Alberta. Pursuant to its trust indenture and an administration agreement, the Trust is managed by its wholly owned subsidiary, Harvest Operations Corp. (“Harvest Operations”). The Trust acquires and holds net profit interests in oil and natural gas properties in Alberta, Saskatchewan and British Columbia held by Harvest Operations and other operating subsidiaries of the Trust. All properties under the Trust are operated by Harvest Operations.
	The beneficiaries of the Trust are the holders of Trust Units. The Trust makes monthly distributions of its distributable cash to Unitholders of record on the last business day of each calendar month.

2.

Significant Accounting Policies

These consolidated financial statements of Harvest Energy Trust have been prepared by management in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). These principles differ in certain respects from accounting principles generally accepted in the United States of America (“U.S. GAAP”) and to the extent that they affect the Trust, these differences are described in Note 20. Certain comparative figures have been reclassified to conform to the current period’s presentation.

(a)	��	Consolidation
		These consolidated financial statements include the accounts of the Trust, its wholly-owned subsidiaries and its 60% interest in a partnership with a third party. All inter-entity transactions and balances have been eliminated upon consolidation. The Trust’s proportionate interest in the partnership has been included in the consolidated financial statements.
(b)		Use of Estimates
		The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenues and expenses during the period. Specifically, amounts recorded for depletion, depreciation and accretion expense, asset retirement obligations and amounts used in the impairment tests for goodwill and capital assets are based on estimates of oil and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates are subject to measurement uncertainty. In the opinion of management, these consolidated financial statements have been prepared within reasonable limits of materiality.
(c)		Revenue Recognition
		Revenues associated with the sale of crude oil, natural gas and natural gas liquids are recognized when title passes to customers.
(d)		Joint Venture Accounting
		The subsidiaries of the Trust conduct substantially all of their oil and natural gas production activities through joint ventures and the consolidated financial statements reflect only their proportionate interest in such activities.
(e)		Capital Assets
		Oil and Natural Gas Activities
		The Trust follows the full cost method of accounting for its oil and natural gas activities. All costs of acquiring oil and natural gas properties and related development costs, including overhead charges directly related to these activities, are capitalized and accumulated in one cost centre. Maintenance and repairs are charged against income. Renewals and enhancements that extend the economic life of the capital assets are capitalized.
		Gains and losses are not recognized on disposition of oil and natural gas properties unless that disposition would alter the rate of depletion by 20% or more.
		Provision for depletion and depreciation of oil and natural gas assets is calculated on the unit-of-production method, based on proved reserves net of royalties as estimated by independent petroleum engineers. The basis used for the calculation of the provision is the capitalized costs of oil and natural gas assets plus the estimated future

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	development costs of proved undeveloped reserves. Reserves are converted to equivalent units on the basis of six thousand cubic feet of natural gas to one barrel of oil.
	The Trust places a limit on the aggregate carrying value of capital assets associated with oil and natural gas activities, which may be amortized against revenues of future periods. Impairment is recognized if the carrying amount of the capital assets exceeds the sum of the undiscounted cash flows expected to result from the Trust’s proved reserves. Cash flows are calculated based on third-party quoted forward prices, adjusted for the Trust’s contract prices and quality differentials.
	Upon recognition of impairment, the Trust would then measure the amount of impairment by comparing the carrying amounts of the capital assets to an amount equal to the estimated net present value of future cash flows from Proved plus Probable reserves. The Trust’s risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess carrying value above the net present value of the Trust’s future cash flows would be a permanent impairment and reflected in net income for the relevant period.
	The cost of unproved properties is excluded from the impairment test calculation described above and subject to a separate impairment test.
	Office Furniture and Equipment Depreciation and amortization of office furniture and equipment is provided for at rates ranging from 20% to 50% per annum.
(f)	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. The goodwill balance is assessed for impairment annually at year-end, or more frequently if events or changes in circumstances occur that more likely than not reduce the fair value of the acquired business below its carrying amount. The test for impairment is carried out by comparing the carrying amount of the reporting entity to its fair value. If the fair value of the Trust’s equity is less than the book value, impairment is measured by allocating the fair value of the consolidated Trust to its identifiable assets and liabilities at their fair values. The excess of this allocation is the fair value of goodwill. Any excess of the book value of goodwill over this implied fair value is the impairment amount. Impairment is charged to income in the period in which it occurs. Goodwill is stated at cost less impairment and is not amortized.
(g)	Asset Retirement Obligation
	The Trust records the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and normal use of the assets. The Trust uses a credit-adjusted risk free discount rate to estimate this fair value. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted and depreciated using the unit of production method over estimated net proved reserves. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.
(h)	Income Taxes
	The Trust and its Trust subsidiaries are taxable entities under the Income Tax Act (Canada) and are taxable only on income that is not distributed or distributable to their Unitholders. As both the Trust and its Trust subsidiaries distribute all of their taxable income to their respective Unitholders pursuant to the requirements of the Income Tax Act (Canada), neither the Trust nor its Trust subsidiaries make provisions for future income taxes.
	Harvest Operations and the corporate subsidiaries of the Trust follow the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in its financial statements and its respective tax base, using enacted or substantively enacted income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs.
(i)	Unit-based Compensation
	The Trust determines compensation expense for the Trust Unit incentive plan and the Unit award incentive plan [Note 12] by estimating the intrinsic value of the rights at each period end and recognizing the amount in income over the vesting period. After the rights have vested, further changes in the intrinsic value are recognized in income in the period of change.

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	The intrinsic value is the difference between market value of the Units and the exercise price of the right. The intrinsic value is used to determine compensation expense as participants in the plan have the option to either purchase the Units at the exercise price or to receive a cash payment equal to the excess of the market value over the exercise price. As the expense is determined based on the period end price, large fluctuations, even recoveries, in compensation expense may occur. As the Unit rights are exercised, cash payments are reflected against the liability previously recorded and any Unit issuances are reflected as increases to Unitholders’ capital.
	Under the terms of the plan, the exercise price of rights granted may be reduced in future periods based on the distributions made to Trust Unitholders. The Trust previously used the fair value method of accounting for the Trust Unit incentive plan.
(j)	Non-controlling interest
	Non-controlling interest represents the exchangeable shares issued by a subsidiary of the Trust to third parties which are ultimately only exchangeable for units of the Trust. These exchangeable shares were issued as partial consideration for the acquisition of Storm Energy Ltd. for the year ended December 31, 2004. Non-controlling interest on the consolidated balance sheet is recognized based on the fair value of the exchangeable shares on issuance together with a portion of the Trust’s accumulated earnings or loss attributable to the non-controlling interest subsequent to their issuance. Net income or loss is reduced for the portion of earnings attributable to the non-controlling interest. As the exchangeable shares are converted to Trust Units, the non-controlling interest on the consolidated balance sheet is reduced on a pro-rata basis together with a corresponding increase in Unitholders’ capital.
(k)	Deferred Financing Charges
	Deferred financing charges relate to costs incurred on the issuance of debt and are amortized on a straight-line basis over the term of the debt, and are included in interest expense.
(l)	Financial Instruments

(i)	Derivative financial instruments
	Derivative financial instruments are utilized by the Trust in the management of its commodity price, foreign currency and interest rate exposures. The Trust uses a variety of derivative instruments to manage these exposures including, swaps, options and collars. The Trust may elect to use hedge accounting when there is a high degree of correlation between the price movements in the derivative financial instruments and the items designated as being hedged. The Trust documents all relationships between instruments and hedged items as well as its risk management objective and strategy for undertaking various hedge transactions. Gains and losses are recognized on the derivative financial instruments in the same period in which the gains and losses on the hedged item are recognized. If the price movements in the derivative instrument and the hedged item cease to be highly correlated, hedge accounting is terminated and the fair value of the derivative financial instrument at such time is recognized on the balance sheet as a deferred charge and recognized in income in the period in which the underlying hedged transaction is recognized. Future changes in the market value of the derivative financial instrument are then recognized in income as t they occur. At December 31, 2004, the Trust has not designated any of its outstanding derivative instruments as hedges.
	For derivative transactions where hedge accounting is not applied, the Trust applies a fair value method to accounting by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instruments in income as an unrealized gain or loss on derivative contracts. Any realized gains or losses on derivative contracts that are not designated hedges are recognized in income in the period they occur.
(ii)	Convertible debentures
	The Trust presents its convertible debentures in their debt and equity component parts, where applicable, as follows:
	The debt component represents the total discounted present value of the semi-annual interest obligations to be satisfied by cash and the principal payment due at maturity, using the rate of interest that would have been applicable to a non-convertible debt instrument of comparable term and risk at the date of issue. Typically, this results in a lower accounting value assigned to the debt component of the convertible debentures compared to the principal amount due at maturity. The debt component amount presented on the balance sheet increased over the term of the relevant debenture to the full face value of the outstanding debentures. The difference is

6

	reflected as increased interest expense with the result that adjusted interest expense reflects the effective yield of the debt component of the convertible debentures.
	The equity component of the convertible debentures is presented under “Unitholders’ Equity” in the consolidated balance sheets. The equity component represents the value ascribed to the conversion right granted to the holder, which remains a fixed amount over the term of the debentures. Upon conversion of the debentures into units by the holders, a proportionate amount is transferred to Unitholders’ capital.
(iii)	Equity bridge notes
	Equity bridge notes are classified as debt. If the equity bridge notes are settled with Trust Units, the debt amount is reclassified to equity.

(m)	Foreign Currency Translation
	Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses are translated at the monthly average rate of exchange. Translation gains and losses are included in income in the period in which they arise.

3.	Changes in Accounting Policy
	The Trust’s financial statements as at and for the year ended December 31, 2004 and its comparative period have been amended to reflect the retroactive adoption of CICA handbook section 3860 and EIC — 151. The following tables reflect a summary of the changes triggered by the adoption of all accounting policy changes in both 2004 and 2003.

Impact of Changes in Accounting Policy — 2004

	As reported		Change upon			Change upon			As restated
	December 31,		adoption of CICA			adoption of			December 31,
Balance sheet	2004		Section 3860(Cii)			EIC -151(d)			2004
Deferred charges	$	24,507	$	1,033		$	—		$	25,540
Convertible debentures — debt		—		25,750			—			25,750
Non-controlling interest		—		—			6,895			6,895
Unitholders’ capital		465,131		335			58			465,524
Exchangeable shares		6,728		—			(6,728	)		—
Convertible debentures-equity		24,696		(24,580	)		—			116
Accumulated income		31,416		(472	)		(225	)		30,719

	Year ended
Income statement	December 31, 2004
Interest on long-term debt — as reported	$	5,488
Add: interest on convertible debentures(cii)		5,248
Add: amortization of deferred financing costs(cii)		447
Interest on long-term debt — as restated	$	11,183

	Year ended
Income statement	December 31, 2004
Interest on short-term debt — as reported	$	9,445
Add: interest on equity bridge notes(cii)		1,070
Interest on short-term debt — as restated	$	10,515

	Year ended
Income statement	December 31, 2004
Non-controlling interest — as reported	$	—
Add: non-controlling interest(d)		225
Non-controlling interest — as restated	$	225

7

	Year ended
Net income	December 31, 2004
Net income — as reported	$	18,231
Less: amortization of deferred financing costs(cii)		(447	)
Less: interest on equity bridge notes(cii)		(1,070	)
Less: interest on convertible debentures(cii)		(5,248	)
Less: non-controlling interest(d)		(225	)
Net income — as restated	$	11,241

	Year ended
Income (loss) per unit	December 31, 2004
Basic as reported	$	(0.47	)
Basic as restated		(0.45	)
Diluted as reported		(0.45	)
Diluted as restated		(0.43	)

Impact of Changes in Accounting Policy — 2003

	As reported		Change upon			Change upon			As restated
	December 31,		adoption of CICA			adoption of CICA			December 31,
Balance sheet	2003(b)		3110			3860(cii)			2003
Capital assets	$	175,377	$	35,166					$	210,543
Asset retirement obligation		—		42,009						42,009
Site restoration provision		4,321		(4,321	)					—
Equity bridge notes — debt		—		—			25,000			25,000
Future income tax asset		11,525		1,024						12,609
Equity bridge notes — equity		25,000		—			(25,000	)		—
Accumulated income		20,976		(1,498	)					19,478

	Year ended
Income statement	December 31, 2003
Depletion and depreciation — as reported	$	29,362
Add: accretion expense(b)		1,845
Add: depletion and depreciation on asset retirement costs(b)		4,520
Depletion, depreciation and accretion — as restated	$	35,727

	Year ended
Income statement	December 31, 2003
Site restoration and reclamation — as reported	$	4,355
Less: site restoration and reclamation(b)		(4,355	)
Site restoration and reclamation — as restated	$	—

	Year ended
Income statement	December 31, 2003
Future tax recovery — as reported	$	(8,162	)
Add: impact of asset retirement obligation and cost(b)		(816	)
Future tax recovery— as restated	$	(8,978	)

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	Year ended
Income statement	December 31, 2003
Interest on short-term debt — as reported	$	2,975
Add: amortization of deferred financing charges(1)		2,607
Add: interest on equity bridge notes(cii)		870
Interest on short-term debt — as reported	$	6,452

⁽¹⁾ Previously classified as finance charges

	Year ended
Net income	December 31, 2003
Net income — as reported	$	16,710
Add: site restoration and reclamation(b)		4,355
Add: future tax recovery(b)		816
Less: accretion(b)		(1,845	)
Less: depletion and depreciation(b)		(4,520	)
Less: interest on equity bridge notes(cii)		(870	)
Net income — as restated	$	14,646

(a)	Full Cost Accounting Guideline
	Effective January 1, 2004, the Trust adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Accounting Guideline 16 “Oil and Gas Accounting — Full Cost”. The changes under the new guideline include modifications to the ceiling test and depletion and depreciation calculations. There were no changes to previously reported net income, capital assets or any other financial statement amounts as a result of the implementation of this guideline.
(b)	Asset Retirement Obligations
	Effective January 1, 2004, the Trust adopted CICA Handbook Section 3110 “Asset Retirement Obligations” in accounting for its asset retirement obligations.
	The effect of this change in accounting policy has been recorded retroactively with restatement of prior periods, as presented for comparative purposes.
	Previously, the Trust recognized a provision for future site reclamation and abandonment costs calculated on the unit-of-production method over the life of the capital assets based on the estimated proved reserves and the estimated future liability.
(c)	Financial Instruments

(i)	Hedging relationships
	Effective January 1, 2004, the Trust implemented CICA Accounting Guideline 13 “Hedging Relationships” (“AcG-13”). This guideline addresses the identification, designation and effectiveness of financial contracts for the purpose of applying hedge accounting. Under this guideline, financial derivative contracts must be designated to the underlying revenue or expense stream that they are intended to hedge, and tested to ensure they remain sufficiently effective. For transactions that do not qualify as designated hedges, the Trust applies a fair value method of accounting by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income.
	Upon the prospective implementation of this new accounting policy, the Trust recorded a liability and a corresponding asset of $5.5 million related to the fair value of the derivative financial instruments that did not qualify for hedge accounting. This amount has been fully recognized in income for the year ended December 31, 2004.

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(ii)		Financial instruments — Disclosure and Presentation
		On January 1, 2005, the Trust retroactively adopted the amendment to the Canadian Institute of Chartered Accountants (“CICA”) handbook section 3860 “Financial Instruments — Disclosure and Presentation” (“Section 3860”). These changes require that fixed-amount contractual obligations that can be settled by issuing a variable number of equity instruments be classified as liabilities. The convertible debentures and the equity bridge notes previously issued by the Trust have characteristics that meet the noted criteria.
		Convertible debentures
		The convertible debentures may be redeemed, at the option of the Trust on or after a predetermined date, and may, at the option of the Trust be redeemed through the issuance of units. The number of units issued varies depending on the weighted average market price of the units for the preceding 20 consecutive trading days, five days prior to the settlement date.
		The convertible debentures also have an option that allows the holder to convert the debentures into a fixed number of units. In accordance with CICA handbook section 3860, the convertible debentures have been reclassified from equity to long term debt with a portion, representing the value of the equity conversion feature, remaining in equity.
		Equity bridge notes
		Under the terms of the equity bridge notes, the interest and principal may have, at the option of the Trust, been repaid in Trust Units. The number of Trust Units issued would have been dependent on the market value of the units at the time of issue. At December 31, 2004 (2003 — $25 million) there were no equity bridge notes payable. For the year ended December 31, 2004 $1.1 million (2003 — $870,000), interest payments were made related to these notes. In accordance with the amended CICA handbook section 3860, these notes would have been classified as debt rather than equity. The interest associated with these notes has been reflected in these consolidated financial statements as a direct charge to income rather than to equity as it was previously classified.
(d)	Exchangeable shares
	On January 19, 2005, the CICA issued EIC-151“Exchangeable Securities Issued by Subsidiaries of Income Trusts”(“EIC-151”) that states that equity interest held by third parties in subsidiaries of an income trust should be reflected as either non-controlling interest or debt in the consolidated balance sheet unless they meet certain criteria. EIC-151 requires that the shares be non-transferable in order to be classified as equity. The exchangeable shares issued by Harvest Operations Corp. (the “Corporation”) are transferable and, in accordance with EIC-151, have been reclassified to non-controlling interest on the consolidated balance sheets. In addition, a provision for non-controlling interest is reflected in the consolidated statements of income.

4.	Corporate Acquisitions
	On June 30, 2004, the Trust completed a Plan of Arrangement with Storm Energy Ltd. (“Storm”). Under this plan, the Trust acquired certain oil and natural gas producing properties for total consideration of approximately $192.2 million. This amount consisted of the issuance of 2,720,837 Trust Units [Note 11] and the issuance of 600,587 exchangeable shares each at $14.77 [Note 13], $75 million in cash, the assumption of approximately $67.3 million in debt and working capital deficiency and acquisition costs of $0.8 million.
	This transaction has been accounted for using the purchase price method. The following summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition.

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Allocation of purchase price:	Amount
Working capital deficiency	$	(10,488	)
Bank debt		(56,831	)
Capital assets		213,455
Derivative contract		863
Goodwill		43,832
Asset retirement obligation		(8,353	)
Future income tax		(57,642	)
	$	124,836
Consideration for the acquisition:
Cash	$	75,000
Issuance of trust units		40,183
Issuance of exchangeable shares		8,870
Acquisition costs		783
	$	124,836

On June 1, 2003, the Trust acquired all of the common shares and the Net Profit Interest of a private company. Total consideration paid by the Trust was $10.1 million, and consisted of the issuance of 625,000 Trust Units at a price of $10.00 per Trust Unit, $3 million in cash and an $850,000 unsecured demand promissory note bearing an interest rate of 10% per annum effective June 27, 2003. The Trust assumed $2.5 million of working capital, $2.8 million of bank debt and acquired $15.4 million in capital assets as part of this acquisition.

5.

Capital Assets

			Accumulated
			depletion and
December 31, 2004	Cost		depreciation			Net book value
Oil and natural gas properties	$	845,396	$	(110,077	)	$	735,319
Production facilities and equipment		209,984		(27,817	)		182,167
Office furniture and equipment		1,337		(426	)		911
Total	$	1,056,717	$	(138,320	)	$	918,397

			Accumulated
			depletion and
December 31, 2003	Cost		depreciation			Net book value
Oil and natural gas properties	$	202,529	$	(31,262	)	$	171,267
Production facilities and equipment		47,071		(8,346	)		38,725
Office furniture and equipment		708		(157	)		551
Total	$	250,308	$	(39,765	)	$	210,543

On September 2, 2004, the Trust purchased oil and natural gas producing properties from a senior producer for cash consideration of approximately $526 million before final working capital adjustments. Final adjustments reduced the Trust’s purchase price to $511.4 million. In conjunction with the acquisition of these properties, the Trust issued approximately $175.2 million in subscription receipts which were converted into 12,166,666 Trust Units upon completion of the purchase [Note 11], and $100 million in 8% convertible unsecured subordinated debentures [Note 14]. The balance of the acquisition cost was funded with a new credit facility arrangement [Note 8].

On October 16, 2003, the Trust acquired the Carlyle Properties in southeastern Saskatchewan for total consideration of approximately $79.5 million before costs and purchase price adjustments. The acquisition was partially financed by the issue of Trust Units on October 16, 2003, with the balance being funded by the bank facility.

General and administrative costs of $3.6 million (2003 — $1.3 million) have been capitalized during the year ended December 31, 2004.

11

All costs are subject to depletion and depreciation at December 31, 2004 including future development costs of $83.3 million (2003 — $15.2 million). $28.6 million (2003 — nil) of undeveloped properties were excluded from the asset base subject to depletion at December 31, 2004.

In accordance with Canadian GAAP, the Trust performed an impairment test as at December 31, 2004 and 2003. The crude oil and natural gas future prices used in the impairment test were obtained from third parties and were adjusted for commodity price differentials specific to the Trust. Based on these assumptions, the undiscounted future net revenue from the Trust’s proved reserves exceed the carrying value of the Trust’s oil and natural gas assets as at December 31, 2004, and therefore no impairment was recorded.

Benchmark Prices:

	WTI Oil			Foreign			Edmonton Light			AECO Gas
Year	(US$/bbl)			Exchange Rate			Crude Oil (CDN$bbl)			(CDN$/GJ)
2005		42.00			0.83			49.60			6.45
2006		39.50			0.83			46.60			6.20
2007		37.00			0.83			43.50			6.05
2008		35.00			0.83			41.10			5.80
2009		34.50			0.83			40.50			5.70
Thereafter (escalation)		2.0	%		0	%		2.0	%		2.0	%

6. Accounts Payable and Accrued Liabilities

As at December 31,	2004		2003
Trade accounts payable	$	13,697	$	9,524
Accrued interest		5,993		897
Trust unit incentive plan[Note 12]		9,774		—
Premium on derivative contracts		4,500		—
Accrued closing adjustments on asset acquisition		13,546		—
Other accrued liabilities		27,139		7,629
Large corporation taxes payable		1,602		33
	$	76,251	$	18,083

7.

Asset Retirement Obligation

The Trust’s asset retirement obligation results from its net ownership interest in oil and natural gas assets including well sites, gathering systems and processing facilities and the estimated costs and timing to reclaim and abandon them. The Trust estimates the total undiscounted amount of cash flows required to settle its asset retirement obligation to be approximately $334.8 million which will be incurred between 2004 and 2023. The majority of the costs will be incurred between 2015 and 2021. A credit-adjusted risk-free rate of 10% was used to calculate the fair value of the asset retirement obligation.

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A reconciliation of the asset retirement obligation is provided below:

Year ended December 31	2004			2003
Balance, beginning of year	$	42,009		$	15,566
Liabilities incurred		53,488			25,175
Revision of estimates		(8,704	)		—
Liabilities settled		(929	)		(577	)
Accretion expense		4,221			1,845
Balance, end of year	$	90,085		$	42,009

8.	Bank Debt
	As at December 31, 2004, Harvest Operations has a senior borrowing base credit facility with a syndicate of lenders. This facility consists of a $310 million production loan, a $15 million operating loan, and a U.S. $21.3 million mark-to-market credit to be used for financial instrument hedging. The term of the facility is to June 29, 2005. Availability under the facility is subject to a borrowing base calculation performed by the lenders at least on a semi-annual basis. The facility permits drawings in Canadian or U.S. dollars, and includes banker’s acceptances, LIBOR loans and letters of credit. Outstanding balances bear interest at rates ranging from 0% to 2.25% above the applicable Canadian or U.S. prime rate depending upon the type of borrowing and the debt to annualized cash flow ratio. The debt is secured by a $750 million debenture with a fixed and floating charge over all of the assets of Harvest Operations, and a guarantee by the Trust and its subsidiaries.
	A bridge facility of $70 million was provided by the Trust’s lenders to assist in the closing of the significant property acquisition in September [Note 5]. This facility was due to mature on June 1, 2005, and outstanding balances under this facility accrued interest at progressive rates of 3% to 8% above the applicable Canadian prime rate. The bridge facility was repaid in full with the net proceeds of the senior notes issuance [Note 9].

9.

Senior Notes

On October 14, 2004, Harvest Operations closed an agreement to sell, on a private placement basis in the United States, U.S.$250 million of senior notes due October 15, 2011. The senior notes are unsecured and bear interest at an annual rate of 7 7/8% and were sold at a price of 99.3392% of their principal amount. A discount of $2.1 million on the senior notes is recorded in deferred charges and amortized into interest expense over the term of the notes. Interest is payable semi-annually on April 15 and October 15. The senior notes are unconditionally guaranteed by the Trust and all of its wholly-owned subsidiaries. The Trust used the net proceeds of the offering to repay in full Harvest’s bank bridge facility and partially repay outstanding balances under Harvest’s senior credit facility. The fair value of the senior notes at December 31, 2004 was U.S.$250.6 million (Cdn$301.2 million).

10.	Equity Bridge Notes
	A director of Harvest Operations and a corporation controlled by that director had advanced $25 million pursuant to the equity bridge notes as at December 31, 2003. On January 2, 2004 Harvest Operations paid $665,068 in accrued interest on these notes. On January 26 and 29, 2004, Harvest Operations repaid the principal amount and paid $185,232 of interest accrued since December 31, 2003. The notes were amended on June 29, July 7 and July 9, 2004. These notes were drawn by $30 million and repaid as to $20 million on August 11, 2004 and $10 million on December 30, 2004. The notes accrued interest at 10% per annum, were secured by a fixed and floating charge on the assets of the Trust and were subordinate to the interest of the senior secured lenders pursuant to Harvest Operations’ credit facility.
	The Trust had the option to settle the quarterly interest payments under the equity bridge notes with cash or the issue of Trust Units. If the Trust elected to issue Trust Units, the number of Trust Units to be issued to settle a quarterly interest payment would have been the equivalent of the quarterly payment amount divided by 90% of the most recent ten-day weighted average trading price. The Trust had the option at maturity of the notes to settle the principal obligation with cash or with the issue of Trust Units. The terms to settle principal with Units is the same as with the interest option described above.

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11. Unitholders’ Capital

(a) Authorized

          The authorized capital consists of an unlimited number of Trust Units.

(b) Issued

	(restated, Note 3)
	Number of units (000s)		Amount
As at December 31, 2002		9,312	$	36,728
Exercise of warrants		150		150
Special warrant exercise		1,500		15,000
Acquisitions		825		8,350
Trust unit issue		4,313		48,645
Distribution reinvestment plan issuance		1,009		10,638
Trust unit issue costs		—		(2,104	)
As at December 31, 2003		17,109	$	117,407
Storm Plan of Arrangement[Note 4]		2,721		40,183
Conversion of subscription receipts[Note 5]		12,167		175,200
Convertible debenture conversions—9% series		3,521		49,287
Convertible debenture conversions—8% series		5,221		84,226
Equity component of convertible debentures—9% series		—		14
Equity component of convertible debentures—8% series		—		632
Exchangeable share retraction		152		2,200
Distribution reinvestment plan issuance		752		12,553
Unit appreciation rights exercise		145		721
Trust unit issue costs		—		(16,899	)
As at December 31, 2004		41,788	$	465,524

(c) Per Trust Unit Information

          The following table summarizes the net income and Trust Units used in calculating income per Trust Unit:

	2004		2003
Weighted average trust units adjustments
Weighted average trust units outstanding, basic		25,033,567		12,590,937
Effect of trust unit appreciation rights		1,140,738		411,868
Weighted average trust units outstanding, diluted(1)		26,174,305		13,002,805

(1)

Weighted average Trust Units outstanding diluted for 2004 does not include the impact of the conversion of the debentures as the impact would be anti-dilutive. Total Units excluded amount to 6,004,145. The impact of the exchangeable shares has also been excluded as the impact was anti-dilutive. Total units excluded was 290,090, which reflects the weighted average exchangeable shares outstanding based on the conversion ratio at December 31, 2004.

(2)

Net income, diluted excludes the impact of the non-controlling interest of $225,000 and the impact of the conversion of the debentures of $5,223,000, as the impact was anti-dilutive.

12.

Trust Unit Incentive Plans

The Trust Unit incentive plan was established in 2002. In December 2004, the plan was modified such that the ability to settle a Unit right with cash is now solely at the option of the holder and not subject to the discretion of the Board of Directors. The Trust is authorized to grant non-transferable rights to purchase Trust Units to directors, officers, consultants, employees and other service providers to an aggregate of 1,487,250 Trust Units, of which 1,371,475 were granted as of December 31, 2004. The initial exercise price of rights granted under the plan is equal to the market price of the Trust Units at the time of grant and the maximum term of each right is five years. The rights vest equally over four years commencing on the first anniversary of the grant date. The exercise price of the rights may be reduced by an amount up to the amount of cash distributions made on the Trust Units subsequent to the date of grant of the respective

14

right, provided that the Trust’s net operating cash flow (on an annualized basis) exceeds 10% of the Trust’s recorded cost of capital assets less all debt, working capital deficiency (surplus) or debt equivalent instruments, accumulated depletion, depreciation and amortization charges, asset retirement obligations, and any future income tax liability associated with such capital assets. Any portion of a distribution that does not reduce the exercise price on vested rights is paid to the holder in cash on a semi-annual basis.

As a result of the modification of the Trust Unit incentive plan, the Trust is required to recognize an obligation for all of the Units reserved under the plan. This obligation represents the difference between the market value of the Trust Units and the exercise price of the Unit rights outstanding under the plan. As such, an obligation of $9.8 million has been recorded in accounts payable and accrued liabilities for the graded vested portion of the 1,117,725 Trust Units outstanding under the plan at December 31, 2004. A one time charge of $8.2 million has been included in Unit right compensation expense to reflect the additional expense resulting from the change in accounting from the fair value method previously used to the intrinsic method. The amount previously expensed has been removed from contributed surplus and reflected in accounts payable and accrued liabilities.

The following summarizes the Trust Units reserved for issuance under the Trust Unit incentive plan:

	2004						2003
	Unit			Weighted			Unit		Weighted
	Appreciation			Average			Appreciation		Average Exercise
	Rights			Exercise Price			Rights		Price(a)
Outstanding beginning of year		1,065,150		$	9.04			787,500	$	8.00
Granted		445,600			16.47			277,650		11.94
Exercised		(253,750	)		8.30			—		—
Cancelled		(139,275	)		10.91			—		—
Outstanding before exercise price reductions		1,117,725			11.92			1,065,150		9.04
Exercise price reductions		—			(1.83	)		—		(1.11	)
Outstanding, end of year		1,117,725		$	10.09			1,065,150	$	7.93
Exercisable before exercise price reductions		206,688		$	8.89			196,875	$	8.00
Exercise price reductions		—			(2.64	)		—		(1.30	)
Exercisable, end of year		206,688		$	6.25			196,875	$	6.70

(a) adjusted to retroactively reflect modifications to the plan made in 2004.

The following table summarizes information about Unit appreciation rights outstanding at December 31, 2004.

			Outstanding						Exercisable
					Exercise				Exercisable
Exercise Price	Exercise Price		Outstanding at		Price net of		Remaining		at		Exercise Price
before price	net of price		December 31,		price		Contractual		December,		net of price
reductions	reductions		2004		reductions(a)		Life(a)		31, 2004		reductions(a)
$8.00 - 10.21	$	5.18 - $7.86		509,625	$	5.27		2.9		163,375	$	5.23
$10.30 - $13.35	$	7.98 - $11.97		214,700		10.31		3.7		43,313		10.11
$13.75 - $18.90	$	12.37 -$18.50		308,400		14.92		4.5		—		n/a
$19.90 - $23.70	$	19.50 - $23.30		85,000		20.92		4.8		—		n/a
$8.00 - - $23.70	$	5.18 - $23.30		1,117,725	$	10.09		3.7		206,688	$	6.25

(a) Based on weighted average Unit appreciation rights outstanding.

When the Trust adopted the fair value method of accounting for its Trust Unit incentive plan on January 1, 2003, it was required to calculate the pro forma impact of having adopted that method from the date all rights were initially granted.

For purposes of those calculations the fair value of each Trust Unit right has been estimated on the grant date using the following:

15

	December 31, 2003
Expected volatility		23.3	%
Risk free interest rate		4.1	%
Expected life of the trust unit rights	4 years
Estimated annual distributions per unit	$	2.40

As at December 31, 2003 for the purposes of pro forma disclosures, the expense related to all of the Trust Unit rights issued prior to December 31, 2002 is reflected in proforma net income as shown below:

		(restated, Note 3)
		2003
Net income	As reported	$	14,646
	Pro forma	$	13,358
Income (loss) per unit — basic	As reported	$	1.16
	Pro forma	$	1.06
Income (loss) per unit — diluted	As reported	$	1.13
	Pro forma	$	1.03

During the years ended December 31, the Trust has recognized non-cash compensation expense of $9.5 million in 2004 and $239,000 in 2003 related to Trust Unit rights and included it in general and administrative expense in the consolidated statements of income.

Unit Award Incentive Plan

In the year ended December 31, 2004, the Trust has implemented a Unit Award Incentive Plan (“Unit Award Plan”). The Unit Award Plan authorizes the Trust to grant awards of Trust Units to directors, officers, employees and consultants of the Trust and its affiliates. Subject to the Board of Directors’ discretion, awards vest annually over a four year period and, upon vesting, entitle the holder to receive the number of Trust Units subject to the award or the equivalent cash amount. The number of Units to be issued is adjusted at each distribution date for an amount approximately equal to the foregone distributions. The fair value associated with the Trust Units granted under the Unit Award Plan is expensed in the statement of income over the vesting period. The Trust recorded compensation expense of $56,000 in 2004 related to this plan.

The Trust may issue up to a maximum of 150,000 Trust Units under the Unit Award Plan. In 2004, 15,000 Trust Units were issued under this plan, of which 5,000 were subsequently cancelled.

13. Exchangeable Shares

(a) Authorized

     Harvest Operations is authorized to issue an unlimited number of exchangeable shares without nominal or par value.

(b) Issued

Exchangeable shares, series 1	Number
Storm Plan of Arrangement		600,587
Shareholder retractions		(145,040	)
As at December 31, 2004		455,547

On June 30, 2004, 600,587 exchangeable shares, series 1 were issued at $14.77 each as partial consideration under the Plan of Arrangement with Storm [Note 4]. The exchangeable shares, series 1 can be converted at the option of the holder at any time into Trust Units. The number of Trust Units issued to the holder upon conversion is based upon the applicable exchange ratio at that time. The exchange ratio is calculated monthly and adjusts to account for distributions paid to Unitholders during the period that the exchangeable shares are outstanding. The exchangeable shares are not eligible to receive distributions. The exchangeable shares that have not been converted by the holder may be redeemed in part or in their entirety by Harvest Operations at any date until June 30, 2009, at which time all remaining exchangeable shares in this series will be redeemed for Trust Units. The exchangeable shares had an exchange ratio of 1:1.06466 as at December 31, 2004.

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(c)	Non-controlling interest
	The Trust retroactively applied EIC-151 “Exchangeable Securities Issued by a Subsidiary of an Income Trust” at January 1, 2005. The non-controlling interest on the consolidated balance sheet consists of the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to such non-controlling interest less conversions to date. On the consolidated statement of income the non-controlling interest represents the share of net income or loss attributable to the non-controlling interest based on the Trust Units issuable for exchangeable shares in proportion to total Trust Units issued and issuable at each period end.
	The following is a summary of the non-controlling interest:

	(restated, Note 3)
	December 31, 2004
Non-controlling interest, beginning of period	$	—
Issue of exchangeable shares		8,870
Exchanged for Trust Units		(2,200	)
Current period (loss) income attributable to non-controlling interest		225
Non-controlling interest, end of period		6,895

14.	Convertible Debentures
	On January 29, 2004, the Trust issued $60 million of 9% convertible unsecured subordinated debentures due May 31, 2009. Interest on the debentures is payable semi-annually in arrears in equal installments on May 31 and November 30 in each year, commencing May 31, 2004. The debentures are convertible into fully paid and non-assessable Trust Units at the option of the holder at any time prior to the close of business on the earlier of May 31, 2009 and the business day immediately preceding the date specified by the Trust for redemption of the Debentures, at a conversion price of $14.00 per Trust Unit plus a cash payment for accrued interest and in lieu of any fractional Trust Units resulting on the conversion. The debentures may be redeemed by the Trust at its option in whole or in part subsequent to May 31, 2007, at a price equal to $1,050 per debenture between June 1, 2007 and May 31, 2008 and at $1,025 per debenture between June 1, 2008 and May 31, 2009. Any redemption will include accrued and unpaid interest at such time. Under both redemption options, the Trust may elect to pay both the principal and accrued interest in the form of Trust Units at a price equal to 95% of the weighted average trading price for the preceding 20 consecutive trading days, 5 days prior to settlement date.
	On August 10, 2004, the Trust issued of $100 million of 8% convertible unsecured subordinated debentures due September 30, 2009. Interest on the debentures is payable semi-annually in arrears in equal installments on March 31 and September 30 in each year, commencing March 31, 2005. The debentures are convertible into fully paid and non-assessable Trust Units at the option of the holder at any time prior to the close of business on the earlier of September 30, 2009 and the business day immediately preceding the date specified by the Trust for redemption of the debentures, at a conversion price of $16.25 per Trust Unit plus a cash payment for accrued interest and in lieu of any fractional Trust Units resulting on the conversion. The debentures may be redeemed by the Trust at its option in whole or in part subsequent to September 30, 2007, at a price equal to $1,050 per debenture between October 1, 2007 and September 30, 2008 and at $1,025 per debenture between October 1, 2008 and September 30, 2009. Any redemption will include accrued and unpaid interest at such time. Under both redemption options, the Trust may elect to pay both the principal and accrued interest in the form of Trust Units at a price equal to 95% of the weighted average trading price for the preceding 20 consecutive trading days, 5 days prior to settlement date. This series of convertible debentures ranks pari-passu with the outstanding debentures issued on January 29, 2004.
	The following table summarizes the issuance and subsequent conversions of the convertible debentures:

										(restated, Note 3)
	9% Series						8% Series						Total
	Number of						Number of
	debentures			Amount			debentures			Amount				Amount
January 29, 2004 issuance		60,000		$	60,000			—			—			$	60,000
August 10, 2004 issuance		—			—			100,000		$	100,000				100,000
Portion allocated to equity		—			(17	)		—			(745	)			(762	)
Accretion of non-cash interest expense		—			2			—			23				25
Converted into Trust Units		(49,300	)		(49,287	)		(84,841	)		(84,226	)			(133,513	)
As at December 31, 2004		10,700		$	10,698			15,159		$	15,052			$	25,750

17

The following table summarizes the reclassification of the equity component of convertible to Unitholders’ capital:

	9% Series			8% Series
	Equity Value			Equity Value			Total
January 1, 2004		—			—			—
January 29, 2004 issuance	$	17		$	—		$	17
August 10, 2004 issuance		—			745			745
Converted into Trust Units		(14	)		(632	)		(646	)
As at December 31, 2004	$	3		$	113		$	116

15. Income Taxes

Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities of Harvest Operations and the Trust’s other corporate subsidiaries and their corresponding income tax bases. The legislated reductions in the Federal and Provincial income tax rates were implemented as expected in 2004. Federal rates are expected to decline further until 2007, resulting in an effective tax rate of approximately 34% for the Trust, which is the rate applied to the temporary differences in the future income tax calculation.

The provision for future income taxes varies from the amount that would be computed by applying the combined Canadian Federal and Provincial income tax rates to the reported income before taxes as follows:

	2004			2003
Income before taxes	$	2,609		$	5,825
Multiplied by tax rate		38.9	%		40.6	%
Computed income tax expense at statutory rates		1,015			2,365
Amount included in Trust income		(14,802	)		(12,940	)
		(13,787	)		(10,575	)
Increase (decrease) resulting from the following:
Non-deductible crown charges		1,278			(61	)
Resource allowance		(1,731	)		2,062
Non-tax portion of capital gain		2,633			(1,282	)
Unit appreciation rights expense		560			99
Rate change		549			794
Other		136			(15	)
Future income tax recovery	$	(10,362	)	$	(8,978	)

The components of the future income tax liability (asset) are as follows:

	2004			2003
Net book value of oil and natural gas assets in excess of tax pools	$	46,333		$	(1,085	)
Asset retirement obligation		(9,691	)		(9,468	)
Net unrealized gains on derivative contracts and foreign exchange		2,293			—
Tax loss carry forwards		(1,172	)		(1,649	)
Deferral of taxable income in partnership		2,339			—
Working capital and other items		(5,431	)		(407	)
Future income tax liability (asset)	$	34,671		$	(12,609	)

The non-capital losses described above expire in the years 2009 and 2010.

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16. Financial Instruments

The Trust is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations.
(a)	Fair Values
	Financial instruments of the Trust consist mainly of accounts receivable, deposits, accounts payable and accrued liabilities, cash distributions payable, bank debt, convertible debentures and senior notes. Other than as disclosed in the related notes to the convertible debentures and the senior notes, there were no significant differences between the carrying values of these financial instruments reported on the balance sheet and their estimated fair values due to their short term to maturity
(b)	Interest Rate Risk
	The Trust is exposed to interest rate risk on its bank debt. All of the Trust’s other debt has fixed interest rates.
(c)	Credit Risk
	Substantially all accounts receivable are due from customers in the oil and natural gas industry and are subject to normal industry credit risks. Concentration of credit risk is mitigated by having a broad customer base, which includes a significant number of companies engaged in joint operations with the Trust. The Trust periodically assesses the financial strength of its partners and customers, including parties involved in marketing or other commodity arrangements. The carrying value of accounts receivable reflects management’s assessment of the associated credit risks.
(d)	Foreign Exchange Rate Risk
	The Trust is exposed to the risk of changes in the Canadian/U.S. dollar exchange rate on sales of commodities that are denominated in U.S. dollars or directly influenced by U.S. dollar benchmark prices. In addition, the Trust’s senior notes are denominated in U.S. dollars (U.S.$250 million). These notes act as an economic hedge to help offset the impact of exchange rate movements on commodity sales during the year. As at December 31, 2004 the full balance of the notes is still outstanding and is not repayable until October 15, 2011. Interest is payable semi-annually on the notes in U.S. dollars.
(e)	Commodity Risk Management
	The Trust uses fixed price oil sales contracts and derivative financial instruments to manage its commodity price exposure. Under the terms of some of the derivative instruments, Harvest Operations is required to provide security from time to time based on the underlying market value of those contracts. The Trust is also exposed to counterparty risk for these derivative contracts. This risk is managed by diversifying the Trust’s derivative portfolio among a number of counterparties and by dealing with large investment grade institutions. The following is a summary of the oil sales price derivative contracts as at December 31, 2004, that have fixed future sales prices:

Oil price swap contracts based on West Texas Intermediate
					Mark to Market Gain
Daily Quantity	Term	Price per Barrel			(Loss)
500 Bbls/d	January through December 2005		U.S. $24.00		$	(4,107	)
1,100 Bbls/d	January through March 2005		U.S. $22.38			(2,535	)
1,030 Bbls/d	April through June 2005		U.S. $22.18			(2,358	)
50% Participating swap contracts based on West Texas Intermediate
8,750 Bbls/d	Jan – Dec 2006		U.S. $38.16	(b)	$	3,710

19

Oil price collar contracts based on West Texas Intermediate
2,500 Bbls/d	January through June 2005	U.S. $28.40 – 32.25 ($21.80	)	$	(6,032	)	(a)
1,500 Bbls/d	July through December 2005	U.S. $28.17 – 32.10 ($22.33	)		(3,296	)	(a)
2,000 Bbls/d	January through December 2005	U.S. $28.00 – 42.00			(529	)

(a)	Harvest has sold put options at the average price denoted in parenthesis, for the same volumes as the associated commodity contracts. The counterparty may exercise these options if the respective index falls below the specified price on a monthly settlement basis.
(b)	This price is a floor. The Trust realizes this price plus 50% of the difference between spot price and this price.

					Mark to Market Gain
Daily Quantity	Term	Type	Price per Bbl		(Loss)
4,000 bbls/d	Jan - Dec 2005	Long Put		U.S. $30.00	$	937
1,972 bbls/d	Jan - Dec 2005	Short Call		U.S. $30.00		(11,261	)
1,972 bbl/d	Jan - Dec 2005	Long Call		U.S. $40.00		4,642
7,000 bbl/d	Jan - Dec 2005	Long Put		U.S. $35.00	$	4,050
2,380 bbl/d	Jan - Dec 2005	Short Call		U.S. $35.00		(9,239	)
2,380 bbl/d	Jan - Dec 2005	Long Call		U.S. $45.00		3,090
7,500 bbl/d	Jan - Dec 2005	Long Put		U.S. $40.00	$	9,142
3,675 bbl/d	Jan - Dec 2005	Short Call		U.S. $40.00		(8,651	)
3,675 bbl/d	Jan - Dec 2005	Long Call		U.S. $50.00		2,678
7,500 bbl/d	Jan - June 2006	Long Put		U.S. $34.00	$	2,989
3,750 bbl/d	Jan - June 2006	Short Call		U.S. $34.00		(7,252	)
3,750 bbl/d	Jan - June 2006	Long Call		U.S. $44.00		3,170

(1) Each group of a long put, short call and a long call reflect an “indexed put option”. These series of puts and calls serve to fix a floor price while retaining upward price exposure on a portion of price movements above the floor price.

The following is a summary of electricity price physical and financial swap contracts entered into by Harvest Operations to fix the cost of future electricity usage as well as a put option related to the U.S./Canadian dollar exchange rate as at December 31, 2004:

Swap contracts based on electricity prices

Weighted Average		Average Price per
Quantity	Term	Megawatt	Mark to Market Gain (Loss
24.8 MWH 29.9 MWH	January through December 2005 January through December 2006	Cdn $47.43 Cdn $47.51	$1,272  (196)

Swap contracts based on electricity heat rate

Quantity	Term	Heat Rate	Mark to Market (Loss)
5 MW	January through December 2005	8.40 GJ/MWh	$(80)

Foreign currency contracts

Monthly Contract Amount	Term	Contract Rate	Mark to Market Gain
U.S. $8.33 million	January through December 2005	1.20 Cdn / U.S.	$4,500(1)

(1) Represents the premium paid on this contract.

At December 31, 2004, the net unrealized loss position reflected on the balance sheet for all the financial derivative contracts outstanding at that date was approximately $15.4 million. Harvest Operations has provided deposits to some counterparties for a portion of its financial derivative contracts, based on the fair value of those contracts at the end of the trading day.

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For the year ended December 31, 2004, the total unrealized loss recognized in the statement of income was $11.3 million. The realized losses on all derivative contracts are included in the period in which they are incurred. Both of these amounts are reflected in Gains and Losses on Derivative Contracts on the statement of income.

At October 1, 2004, the Trust discontinued hedge accounting for all of its derivative financial instruments. For those contracts where hedge accounting had previously been applied, a deferred charge or gain was recorded equal to the fair value of the contracts at the time hedge accounting was discontinued with a corresponding amount recorded in the derivative contracts balance. The deferred charge or gain is recognized in income in the period in which the underlying transaction is recognized.

For the year ended December 31, 2004, $14.9 million of the deferred charge and $350,000 of the deferred gain has been amortized and recorded in gains and losses on derivative contracts in the statement of income. At December 31, 2004, $10.8 million and $2.2 million has been recorded as a deferred charge and a deferred gain, respectively on the balance sheet.

	(restated, Note 3)			December 31
Deferred charges - asset	2004			2003
Balance, beginning of year	$	1,989		$	2,210
Deferred charge related to derivative contracts recorded upon adoption of AcG-13		5,490			—
Deferred charge related to derivative contracts recorded upon discontinuing hedge accounting		20,215			—
Discount on senior notes[Note 9]		2,075			—
Financing costs incurred		20,971			2,335
Financing costs transferred to share issue costs on conversion of debentures		(5,721	)		—
Amortization of deferred charges related to derivative contracts(1)		(14,946	)		—
Amortization of deferred financing costs(2)		(4,458	)		(2,556	)
Interest expense		(75	)		—
Balance, end of year	$	25,540		$	1,989

				December 31
Deferred gains - liability	2004			2003
Balance, beginning of year	$	—		$	—
Deferred gains related to derivative contracts recorded upon discontinuing hedge accounting		2,527			—
Amortization of deferred gains related to derivative contracts(1)		(350	)		—
Balance, end of year	$	2,177		$	—

(1)	Recorded within gains and losses on derivative contracts
(2)	Recorded within interest expense

17.      Related Party Transactions

Refer to Note 10 regarding equity bridge notes received from a director of Harvest Operations and a corporation controlled by that director.

A corporation controlled by a director of Harvest Operations sublets office space and is provided administrative services by Harvest Operations on a cost recovery basis.

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18. Change in Non-Cash Working Capital

	Year ended December 31
	2004			2003
Changes in non-cash working capital items:
Accounts receivable	$	(24,860	)	$	(5,590	)
Prepaid expenses and deposits		9,117			(11,596	)
Current portion of derivative contracts assets		(8,861	)		—
Accounts payable and accrued liabilities		58,168			12,154
Cash distributions payable		4,936			1,559
Current portion of derivative contracts liability		27,927			—
	$	66,427		$	(3,473	)
Changes relating to operating activities	$	(11,103	)	$	(12,290	)
Changes relating to financing activities		5,097			2,889
Changes relating to investing activities		16,547			329
Add: Non cash changes		55,886			5,599
	$	66,427		$	(3,473	)

19.	Commitments, Contingencies and Guarantees
	From time to time, the Trust is involved in litigation or has claims brought against it in the normal course of business operations. Management of the Trust is not currently aware of any claims or actions that would materially affect the Trust’s reported financial position or results from operations.
	In the normal course of operations, management may also enter into certain types of contracts that require the Trust to indemnify parties against possible third party claims, particularly when these contracts relate to purchase and sale agreements. The terms of such contracts vary and generally a maximum is not explicitly stated; as such the overall maximum amount of the obligations cannot be reasonably estimated. Management does not believe payments, if any, related to such contracts would have a material affect on the Trust’s reported financial position or results from operations.
	The Trust has letters of credit outstanding in the amount of approximately $5 million related to electricity infrastructure usage. These letters are provided by Harvest Operations’ lenders pursuant to the credit agreement [Note 8]. These letters expire throughout 2004 and 2005, and are expected to be renewed as required.
	Following is a summary of the Trust’s contractual obligations and commitments as at December 31, 2004:

	Payments Due by Period
($000’s)	2005		2006 – 2007		2008 – 2009		Thereafter		Total
Debt repayments (1)		75,519		—		—		300,500		376,019
Capital commitments		700		—		—		—		700
Operating leases		400		2,869		2,869		956		7,094
Total contractual obligations		76,619		2,869		2,869		301,456		383,813

(1) Includes long-term and short-term debt. Assumes that the outstanding convertible debentures either exchange at the holders’ option for Units or are redeemed for Units at the Trust’s option.

20.	Reconciliation of the Consolidated Financial Statements to United States Generally Accepted Accounting Principles
	These consolidated financial statements have been prepared in accordance with Canadian GAAP which, in most respects, conforms to generally accepted accounting principles in U.S. GAAP. Any differences in accounting principles as they have been applied to the accompanying consolidated financial statements are not material except as described below. All items required for financial disclosure under U.S. GAAP are not noted.
	The application of U.S. GAAP would have the following effects on net income as reported:

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	Year Ended December 31,
	2004			2003
Net income as restated	$	11,241		$	14,646
Adjustments
Unrealized loss on derivative financial instruments (f)		3,886			(9,345	)
Future income tax effect on unrealized loss on derivative financial instruments (f) (g)		(5,251	)		3,952
Future tax impact of deferred charges (f) (g)		2,885			—
Non-cash interest expense on debentures (d)		25			—
Amortization of deferred financing charges (d)		(99	)		—
Non-controlling interest (e)		225			—
Non-cash general and administrative expenses (c)		1,455			(1,288	)
Net income under US GAAP before cumulative effect of change in accounting policy		14,367			7,965
Cumulative effect of change in accounting policy (b)		—			(304	)
Net income under US GAAP after cumulative effect of change in accounting policy		14,367			7,661
Increase in redemption value of trust units under US GAAP (e)		(298,893	)		(48,362	)
Net loss available to unitholders under US GAAP (e)	$	(284,526	)	$	(40,701	)
Basic
Net income under US GAAP before cumulative effect of change in accounting policy	$	0.57		$	0.63
Cumulative effect of change in accounting policy (b)		—			(0.02	)
Net income after the cumulative effect of change in accounting policy (before changes in redemption value of trust units)		0.57			0.61
Net loss available to unitholders per trust unit under US GAAP	$	(11.24	)	$	(3.23	)
Diluted
Net income under US GAAP before cumulative effect of change in accounting policy	$	0.54		$	0.61
Cumulative effect of change in accounting policy					(0.02	)
Net income after the cumulative effect of change in accounting policy (before changes in redemption value of trust units)	$	0.54		$	0.59
Net loss available to unitholders per trust unit under U.S GAAP	$	(11.24	)	$	(3.23	)

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

	December 31, 2004					December 31, 2003
	Canadian		US			Canadian		US
	GAAP		GAAP			GAAP		GAAP
Assets
Current portion of derivative contracts (f)	$	8,861	$	8,861		$	—	$	—
Capital assets (a)		918,397		918,397			210,543		210,543
Long term portion of derivative contracts (f)		3,710		3,710			—		—
Deferred charges (f) (d)		24,540		12,768			1,989		1,989
Future taxes (g)		—		—			12,609		17,860
Liabilities
Derivative contracts (f)		27,927		27,927			—		12,468
Deferred gains (f)		2,177		—			—		—
Senior notes (i)		300,500		298,488			—		—
Convertible debentures (d)		25,750		25,859			—		—
Equity bridge notes (d)		—		—			25,000		25,000
Asset retirement obligation (b)		90,085		90,085			42,009		42,009
Future taxes (f)(g)		34,671		31,786			—		—
Non-controlling interest (e)		6,895		—			—		—
Temporary equity (e)		—		867,452			—		213,692
Unitholders’ Equity
Unitholders’ capital (e)	$	465,524	$	—		$	117,407	$	—
Equity component of convertible debentures (d)		116		—			—		—
Contributed surplus (c)		—		—			239		1,694
Accumulated income		30,719		(370,005	)		19,478		(85,479	)

(a)	Under Canadian GAAP, the Trust performs an impairment test that limits the capitalized costs of its oil and natural gas assets to the discounted estimated future net revenue from proved and risked probable oil and natural gas reserves plus the cost of unproved properties less impairment, using forward prices. The discount rate used is equal to the Trust’s risk free interest rate. Under U.S. GAAP, entities using the full cost method of accounting for oil and natural gas activities perform an impairment test on each cost centre using discounted future net revenue from proved oil and natural gas reserves discounted at 10%. The prices used under the U.S. GAAP ceiling tests are those in effect at year end. There was no impairment under U.S. GAAP at December 31, 2004 or 2003.
(b)	Effective January 1, 2004, the Trust retroactively adopted the CICA Handbook standard for accounting for asset retirement obligations. This section is equivalent to Statement of Financial Accounting Standards (“SFAS”) No. 143 for fiscal periods beginning on or after January 1, 2003. The transitional provisions between Canadian GAAP and U.S. GAAP differ however, as Canadian GAAP requires a restatement of comparative amounts whereas U.S. GAAP does not allow restatement.
(c)	During the year, the Trust modified the Trust Unit incentive plan to include a feature that allows participants to receive cash for the value of their Units at their sole option. As such, under Canadian GAAP the Trust now determines compensation expense based on the excess of the market price over the adjusted exercise price of all of the rights outstanding at the end of each reporting period and the expense is deferred and recognized in income over the vesting period of the rights, with a corresponding amount recorded to liabilities. After the rights have vested, compensation expense is recognized in income in the period in which a change in the market price of the Trust Units or the exercise price of the rights occurs. For the year ended December 31, 2003, under Canadian GAAP, the Trust used the fair value method to account for these rights.
	For U.S. GAAP purposes, the Trust Unit incentive plan is a variable compensation plan as the exercise price of the rights is subject to downward revisions from time to time. Accordingly, compensation expense is determined using the same method as under Canadian GAAP for 2004. An adjustment is made to reflect compensation expense recorded under U.S. GAAP relating to rights issued in 2002 previously not expensed under Canadian GAAP. For the year ended December

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	31, 2003, an adjustment is also made for the difference between compensation expense using the fair value method and the intrinsic method used.
(d)	Upon adoption of amendments to CICA Handbook Section 3860 “Financial Instruments, the equity bridge notes outstanding at December 31, 2003 were classified as debt. The debentures were also classified as debt with a portion, representing the value associated with the conversion feature, being allocated to equity under Canadian GAAP. Issue costs for the debentures are allocated between the equity portion and deferred chares resulting in a difference in amortization expense. In addition, under Canadian GAAP a non-cash interest expense representing the effective yield of the debt component is recorded in the income statement with a corresponding credit to the convertible debt balance. Under U.S. GAAP, the convertible debentures would be fully classified as debt.
(e)	Under the Trust Indenture, Trust Units are redeemable at any time on demand by the Unitholder for cash. Under U.S. GAAP, the amount included on the consolidated balance sheet for Unitholders’ Equity would be reduced by an amount equal to the redemption value of the Trust Units as at the balance sheet date. The same accounting treatment would be applicable to the exchangeable shares. The redemption value of the Trust Units and the exchangeable shares is determined with respect to the trading value of the Trust Units as at each balance sheet date, and the amount of the redemption value is classified as temporary equity. Increases, if any, in the redemption value during a period results in a charge to permanent equity and is reflected as a reduction in earnings available to Unitholders for the year. Under Canadian GAAP the exchangeable shares issued by a subsidiary of the Trust to third parties are recorded as non-controlling interest.
(f)	Under U.S. GAAP, SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” requires that all derivative instruments be recorded on the consolidated balance sheet as either an asset or liability measured at fair value, and requires that changes in fair value be recognized currently in income unless specific hedge accounting criteria are met. U.S. GAAP requires that a company formally document, designate, and assess the effectiveness of derivative instruments before they can receive this accounting treatment. The Trust had not formally documented and designated all hedging relationships as at December 31, 2004 or December 31, 2003, and as such was not eligible for hedge accounting treatment.
	Upon adoption of AcG-13, the Trust has implemented fair value accounting effective January 1, 2004 under Canadian GAAP and had designated a portion of its derivative contracts as hedges. A difference does arise due to the adoption of fair value accounting under Canadian GAAP. Upon discontinuing hedge accounting a deferred charge or gain is recorded representing the fair value of the contract at that time. This difference is amortized over the term of the contract. During the year, the Trust discontinued hedge accounting for all derivative contracts under Canadian GAAP. Under U.S. GAAP there were no contracts designated as hedges. To the extent deferred charges and gains are recorded and amortized when hedge accounting was discontinued, there is a difference between Canadian and U.S. GAAP.
(g)	The Canadian GAAP liability method of accounting for income taxes is similar to the U.S. GAAP SFAS 109, “Accounting for Income Taxes”, which requires the recognition of tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Trust’s consolidated financial statements. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future income tax, whereas Canadian GAAP uses substantively enacted rates. There are no differences for the year ended December 31, 2004 or the year ended December 31, 2003 relating to tax rate differences.
	Upon adoption of fair value accounting for derivative contracts under Canadian GAAP, deferred charges and gains were set up when hedge accounting was discontinued. As there is no tax base relating to these amounts a temporary difference was created. This difference does not exist under U.S. GAAP as there are no deferred charges or gains under U.S. GAAP. In addition, to the extent there were historical differences with respect to Canadian and U.S. GAAP due to derivative contract assets and liabilities, these amounts are now required to be eliminated as the balances of those accounts under Canadian and U.S. GAAP are now the same.
	At December 31, 2003, the difference relates to the recording of a derivative contract liability under U.S. GAAP and not under Canadian GAAP.
(h)	Unless otherwise noted, the consolidated statements of cash flows prepared in accordance with Canadian GAAP conform in all material respects with U.S. GAAP, with the exception that Canadian GAAP allows for the presentation of a subtotal of cash flows from operating activities before changes in non-cash working capital items in the consolidated statement of cash flows. This sub-total cannot be presented under U.S. GAAP.

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(i)	Under Canadian GAAP, the discount on the senior notes has been recorded in deferred charges. Under U.S. GAAP, this amount is required to be applied against the senior notes balance.
	The following are standards and interpretations that have been issued by the Financial Accounting Standards Board (“FASB”) and the Trust has assessed the impact to be as follows:
	In December 2004, FASB issued statement 123R “Share Based Payments” that addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. The proposal eliminates the ability to account for share-based compensation transactions using APB 25, “Accounting for Stock Issued to Employees”, and generally requires instead, that such transactions be accounted for using a fair-value-based method. The effective date would be for the first interim or annual period beginning on or after June 15, 2005, for awards granted on or after the effective date. Management has not yet assessed the impact of this standard on its consolidated financial statements.
	In December 2004, FASB issued statement number 153 “Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29”. This Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Management does not expect this statement to have a material impact on its consolidated financial statements.

Additional disclosures required under U.S. GAAP:
(thousands of Canadian dollars)

	December 31, 2004		December 31, 2003
Components of accounts receivable
Trade	$	14,743	$	16,334
Accruals		29,285		2,834
	$	44,028	$	19,168
Components of prepaid expenses
Prepaid expenses	$	1,730	$	232
Funds on deposit		1,284		11,899
	$	3,014	$	12,131

21. Subsequent Events

a)	On June 24, 2005, the Trust entered into an agreement to purchase properties located in Northern British Columbia for $260 million before working capital adjustments. The acquisition closed on August 2, 2005 and is effective from that date onward. The purchase was financed with the drawings from the Corporation’s senior secured credit facility, which was increased in size from $325 million to $400 million coincident with the closing of the acquisition.
b)	On August 2, 2005, the Trust completed the issuance of 6,505,600 subscription receipts for gross proceeds of $175 million and $75 million principal amount of 6.5% convertible extendible unsecured subordinated debentures. Net proceeds from this financing were used to settle outstanding bank debt under the credit facility.
c)	On November 28, 2005, the Trust announced the proposed merger with Viking Energy Royalty Trust (“Viking”). Through a plan of arrangement (the “Arrangement”) Unitholders of Viking will receive 0.25 Harvest Trust Units for every Viking Unit held. Unitholder meetings for each of the Trust and Viking will be held on February 2, 2006 and upon receipt of Unitholder approval and other regulatory approvals, the Arrangement is expected to close on or about February 3, 2006. The total purchase price (excluding debt and working capital) is estimated to be approximately $1.6 billion (including estimated transaction costs of approximately $10 million) based on currently available information. Amendments to the purchase price estimate may be made as final information becomes available.

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