F-10/A 1 a2149638zf-10a.htm FORM F-10/A
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As filed with the Securities and Exchange Commission on January 10, 2005

Registration No. 333-121620

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

AMENDMENT NO. 1
TO
FORM F-10
REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933

Harvest Operations Corp.
(Exact Name of Registrant as Specified in its Charter)

Alberta, Canada
(Province or other jurisdiction of
incorporation or organization)

1311
(Primary Standard Industrial
Classification Code Number)

Not Applicable
(I.R.S. Employer Identification No.,
if applicable)

Suite 1900, 330 - 5th Avenue S.W.,
Calgary, Alberta, Canada T2P 0L4
(403) 265-1178
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Harvest Energy Trust		Harvest Sask Energy Trust
Redearth Energy Inc.		Harvest Breeze Trust No. 1
1115638 Alberta Ltd.		Harvest Breeze Trust No. 2
1115650 Alberta Ltd.		Breeze Resources Partnership
(Exact Name of Registrant as Specified in its Charter)

Alberta, Canada
(Province or other jurisdiction of
incorporation or organization)

1311
(Primary Standard Industrial
Classification Code Number)

Not Applicable
(I.R.S. Employer Identification No.,
if applicable)

CT Corporation System
111 Eighth Avenue
New York, New York 10011
(212) 894-8940
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

David Rain
Harvest Operations Corp.
Suite 1900, 330 - 5th Avenue S.W.,
Calgary, Alberta, Canada
T2P 0L4
(403) 265-1178

Keith A. Greenfield
Burnet, Duckworth & Palmer LLP
1400, 350 - 7th Avenue S.W.,
Calgary, Alberta, Canada
T2P 3N9
(403) 260-0100

Andrew J. Foley
Paul, Weiss, Rifkind
Wharton & Garrison LLP
1285 Avenue of the Americas
New York, New York
10019-6064
(212) 373-3000

Approximate date of commencement of proposed sale of the securities to the public:
From time to time after the effective date of this Registration Statement.
Province of Alberta, Canada
(Principal jurisdiction regulating this offering)

It is proposed that this filing shall become effective (check appropriate box below):


A.	o	upon filing with the Commission, pursuant to Rule 467(a) (if in connection with an offering being made contemporaneously in the United States and Canada).
B.	ý	at some future date (check appropriate box below)
	1.	o	pursuant to Rule 467(b) on ( ) at ( ) (designate a time not sooner than 7 calendar days after filing).
	2.	o	pursuant to Rule 467(b) on ( ) at ( ) (designate a time 7 calendar days or sooner after filing) because the securities regulatory authority in the review jurisdiction has issued a receipt or notification of clearance on ( ).
	3.	ý	pursuant to Rule 467(b) as soon as practicable after notification of the Commission by the Registrant or the Canadian securities regulatory authority of the review jurisdiction that a receipt or notification of clearance has been issued with respect hereto.
	4.	o	after the filing of the next amendment to this Form (if preliminary material is being filed).

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to the home jurisdiction's shelf prospectus offering procedures, check the following box. o

The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registration statement shall become effective as provided in Rule 467 under the Securities Act of 1933 or on such date as the Commission, acting pursuant to Section 8(a) of the Act, may determine.

PART I

INFORMATION REQUIRED TO BE DELIVERED
TO OFFEREES OR PURCHASERS

New Issue

January 10, 2005

US$250,000,000

Harvest Operations Corp

7⁷/8% Senior Notes Due 2011
Unconditionally Guaranteed By

Harvest Energy Trust

Interest payable on April 15 and October 15

The Exchange Offer:

•: If all of the conditions to this exchange offer are satisfied, we will exchange all 7⁷/8% Senior Notes due 2011 (the "old notes") that are validly tendered and not validly withdrawn for an equal principal amount of 7⁷/8% Senior Notes due 2011 (the "new notes") that have been registered under the Securities Act of 1933.
•: You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.
•: The exchange offer expires at 5:00 p.m., New York City time on February 11, 2005, unless we extend the exchange offer.

The New Notes:

•: The terms of the new notes (with the old notes, collectively referred to as the "notes") to be issued in the exchange offer are substantially identical to the old notes, except that the new notes will be freely tradable by persons who are not affiliated with us.
•: No public market currently exists for the old notes. We do not intend to list the new notes on any securities exchange and, therefore, no active public market is anticipated.
•: The new notes will be guaranteed by all of Harvest Energy Trust's wholly-owned subsidiaries, other than Harvest Operations, with respect to the payment of the principal, premium, if any, and interest on the new notes on an unsecured, unsubordinated basis. The payment obligations of all the Trust's subsidiaries, including Harvest Operations, under the Indenture, notes and subsidiary guarantees will be guaranteed by the Trust on an unsecured, unsubordinated basis.

For a more detailed description of the notes, see "Description of the Notes" beginning on page 72.

There is no market through which these securities may be sold and purchasers may not be able to resell securities purchased under the short form prospectus.

Before participating in the exchange offer, please refer to the section in this prospectus entitled "Risk Factors" beginning on page 14.

The offering of the new notes is made by Harvest Operations Corp. and the offering of the guarantees accompanying the new notes is made by Harvest Energy Trust and each of the Trust's wholly-owned subsidiaries. Each of these entities is a foreign issuer and is permitted, under a multijurisdictional disclosure system adopted by the United States, to prepare this prospectus in accordance with the disclosure requirements of Canada. Prospective investors should be aware that such requirements are different from those of the United States. The financial statements included or incorporated herein have been prepared in accordance with Canadian generally accepted accounting principles, and may be subject to Canadian auditing and auditor independence standards, and thus may not be comparable to financial statements of United States companies.

Owning the securities described herein may subject you to tax consequences both in the United States and in Canada. This prospectus may not describe these tax consequences fully. You should read the tax discussion contained in this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities, passed upon the accuracy or adequacy of this prospectus or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. No securities regulatory authority in Canada has expressed an opinion about these securities and it is an offense to claim otherwise.

No underwriter has been involved in the preparation of this short form prospectus or performed any review of the contents of this short form prospectus.

The pro forma interest coverage ratios for the year ended December 31, 2003, and the twelve-month period ended September 30, 2004, are less than one-to-one. See "Interest Coverage" on page 27.

TABLE OF CONTENTS

		Page
Documents Incorporated by Reference		i
Enforceability of Civil Liabilities Against Foreign Persons		ii
Presentation of Financial Information		ii
Exchange Rate Data		iii
Where You Can Find More Information		iii
Disclosure Regarding Forward-Looking Statements		iv
Definitions and Other Matters		v
Presentation of Reserve Information		vi
Certain Financial Reporting Measures		vi
Summary		1
Risk Factors		14
Use of Proceeds		26
Capitalization		26
Interest Coverage		27
Selected Consolidated Financial Data		27
Management's Discussion and Analysis of Financial Condition and Results of Operations		30
Business		42
Management		56
Relationships and Related Transactions		58
Principal Unitholders		59
Description of Other Indebtedness		60
The Exchange Offer		64
Description of the Notes		73
Income Tax Considerations		109
Plan of Distribution		112
Legal Matters		113
Experts		114
Documents Filed as Part of the Registration Statement		115
Index to Financial Statements		F-1

DOCUMENTS INCORPORATED BY REFERENCE

Information has been incorporated by reference in this prospectus from documents filed with securities commissions or similar authorities in Canada. Copies of the documents incorporated herein by reference may be obtained on request without charge from our Corporate Secretary at 1900, 330 - 5th Avenue S.W., Calgary, Alberta, T2P 0L4 (toll free number 1-866-666-1178). A copy of the permanent information record may be obtained from our Corporate Secretary at the above-mentioned address and telephone number. In addition, copies of the documents incorporated herein by reference may be obtained from the securities commissions or similar authorities in Canada through the SEDAR website at www.sedar.com. The Trust's SEDAR profile number is 18577 and Storm Energy Ltd.'s SEDAR profile number is 18616.

The following documents, filed with the various provincial securities commissions or similar regulatory authorities in Canada, are specifically incorporated into and form an integral part of this prospectus.

(a)

the Renewal Annual Information Form of the Trust dated April 30, 2004 (excluding:

(i): the Schedule of Revenue and Expenses for certain of the Provost Properties Acquired from Devon Canada Corporation for the Years Ended December 31, 2001 and 1999 and Six Months Ended June 30, 2002 and 2001;
(ii): the Schedule of Revenue and Expenses for certain of the Provost Properties Acquired from Anadarko Canada Corporation for the Years Ended December 31, 2001 and 1999 and Six Months Ended June 30, 2002 and 2001; and
(iii): the Pro Forma Consolidated Financial Statements of Harvest Energy Trust as at and for the Year ended December 31, 2003);

(b)

the Information Circular — Proxy Statement of the Trust dated May 12, 2004, relating to the annual and special meeting of Unitholders held on June 22, 2004 (excluding those portions thereof which appear under the headings "Performance Chart" and "Corporate Governance");

(c)

the Material Change Report of the Trust dated July 8, 2004, relating to the acquisition of Storm Energy Ltd.;

(d)

the Material Change Report of the Trust dated July 23, 2004, relating to the acquisition of Breeze Resources Partnership; and

(e): the Material Change Report of the Trust dated October 22, 2004, relating to the private placement of US$250,000,000 of 7⁷/8% senior notes due 2011.

The financial results of Harvest Operations Corp. are included in the consolidated financial statements of the Trust which are contained in this prospectus.

Any material change report and any document of the type referred to in the preceding paragraph (excluding confidential material change reports) comparative interim financial statements, comparative annual financial statements together with the auditors' report thereon and information circulars filed by the Trust with the securities commissions or similar authorities in the provinces of Canada subsequent to the date of this prospectus and prior to the termination of this distribution shall be deemed to be incorporated by reference into this prospectus.

Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this short form prospectus to the extent that a statement contained herein or in any other subsequently filed document which also is, or is deemed to be, incorporated by reference herein modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omissions to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS

Harvest Operations Corp. is a corporation incorporated under the laws of Alberta, Canada. Harvest Energy Trust and its subsidiaries are organized under the laws of Alberta, Canada. All of the directors and officers and some of the experts named in this prospectus reside principally in Canada. Because these persons are located outside the United States it may not be possible for you to effect service of process within the United States upon those persons. Furthermore, it may not be possible for you to enforce against Harvest or them, in the United States, judgments obtained in U.S. courts, because all or a substantial portion of Harvest's assets and the assets of these persons are located outside the United States. Harvest has been advised by Burnet, Duckworth & Palmer LLP, its Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the U.S. federal securities laws and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against Harvest, the directors and officers or the experts named in this prospectus.

PRESENTATION OF FINANCIAL INFORMATION

The financial statements included in this prospectus are presented in Canadian dollars. In this prospectus, references to "$" or "dollars" are to Canadian dollars and references to "US$" and "U.S. dollars" are to United States dollars. See "Exchange Rate Data" below.

The financial statements included in this prospectus have been prepared in accordance with Canadian generally accepted accounting principles or Canadian GAAP. Canadian GAAP differs in some material respects from United States generally accepted accounting principles, or U.S. GAAP, and so these financial statements may not be comparable to the financial statements of U.S. companies. For a discussion of the differences between Canadian GAAP and U.S. GAAP as they relate to Harvest, see note 20 to Harvest's consolidated financial statements, which is included elsewhere in this prospectus. Also, see note 3 to Harvest's pro forma consolidated statements of income, note 11 to Storm Energy Ltd.'s consolidated financial statements as at and for the periods ended December 31, 2003 and 2002, note 11 to Storm Energy Ltd.'s unaudited consolidated financial statements as at and for the 3 month period ended March 31, 2004 and note 1 to the New Properties Schedule of Revenues, Royalties and Expenses which are included in this prospectus.

EXCHANGE RATE DATA

In this prospectus, unless otherwise specified or the context otherwise requires, all dollar amounts are expressed in Canadian dollars.

The following table lists, for each period presented, the high and low exchange rates, the average of the exchange rates on the last day of each month during the period indicated and the exchange rates at the end of the period for one Canadian dollar, expressed in United States dollars, based on the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York. On January 6, 2005, the inverse of the noon buying rate in New York City for cable transfers of Canadian dollars was Cdn$1.00 = US$0.8082.

	Year Ended December 31,		Nine Months Ended September 30,
	2002	2003	2003	2004
High for the Period	0.6619	0.7738	0.7907	0.7492
Low for the Period	0.6200	0.6349	0.7158	0.6349
End of Period	0.6329	0.7738	0.7525	0.7049
Average for the period⁽¹⁾	0.6368	0.7186	0.7906	0.7404

(1): Average represents the average of the rates on the last day of each month during the period.

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form F-10 with the Securities and Exchange Commission (the "SEC") covering the exchange notes. This prospectus is part of our registration statement. For further information about us and the exchange notes, you should refer to our registration statement and its exhibits. This prospectus summarizes material provisions of contracts and other documents to which we refer you. Since the prospectus might not contain all of the information that you might find important, you should review the full text of these documents. We have included copies of these documents as exhibits to our registration statement.

We are subject to the periodic reporting and other informational requirements of the U.S. Securities Exchange Act of 1934, and accordingly we file reports and other information with the SEC. Copies of our reports and other information may be inspected and copied at the public reference facilities maintained by the SEC. However, we are a "foreign private issuer" as defined in Rule 405 of the Securities Act, and therefore are not required to comply with Exchange Act provisions regarding proxy statements and short swing profit disclosure.

Copies of these materials may also be obtained by mail at prescribed rates from the Public Reference Section of the SEC, 450 Fifth Street, N.W., Washington, D.C. 20549 or by calling the SEC at 1-800-SEC-0330. Our filings are also electronically available from the SEC's Electronic Document Gathering and Retrieval System, which is commonly known by the acronym EDGAR and which may be accessed at www.sec.gov, as well as from commercial document retrieval services.

We also file information, such as periodic reports and financial information, with the Canadian Securities Administrators, which may be accessed at www.sedar.com.

Anyone who receives a copy of this prospectus may obtain a copy of the senior note indenture without charge by writing to us at Suite 1900, 330 - 5th Avenue S.W., Calgary, Alberta, TP2 0L4.

iii

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements within the meaning of the Unites States Private Securities Litigation Reform Act of 1995. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those included in the forward-looking statements. The words "believe," "expect," "intend," "estimate" or "anticipate" and similar expressions, as well as future or conditional verbs such as "will," "should," "would," and "could" often identify forward-looking statements. Specific forward-looking statements contained in this prospectus include, among others, statements regarding Harvest's:

•: expected financial performance in future periods;
•: expected increases in revenue attributable to its development and production activities;
•: estimated capital expenditures for fiscal 2004 and subsequent periods;
•: competitive advantages and ability to compete successfully;
•: intention to continue adding value through drilling and exploitation activities;
•: emphasis on having a low cost structure;
•: intention to retain a portion of its cash flows after distributions to repay indebtedness and invest in further development of its properties;
•: reserve estimates and its estimates of the present value of its future net cash flows;
•: methods of raising capital for exploitation and development of reserves;
•: approach to deciding whether or not to undertake a development or exploitation project;
•: plans to make acquisitions and expected synergies from acquisitions made;
•: expectations regarding the development and production potential of its properties; and
•: treatment under government regulatory regimes.

With respect to forward-looking statements contained in this prospectus, Harvest has made assumptions regarding, among other things:

•: future oil and natural gas prices and differentials between light, medium and heavy oil prices;
•: the cost of expanding its property holdings;
•: its ability to obtain equipment in a timely manner to carry out development activities;
•: its ability to market oil and natural gas successfully to current and new customers;
•: the impact of increasing competition;
•: its ability to obtain financing on acceptable terms; and
•: its ability to add production and reserves through its development and exploitation activities.

Some of the risks that could affect Harvest's future results and could cause results to differ materially from those expressed in its forward-looking statements include:

•: the volatility of oil and natural gas prices, including the differential between the price of light and medium and heavy oil;
•: the uncertainty of estimates of oil and natural gas reserves;
•: the impact of competition;
•: difficulties encountered during the drilling for and production of oil and natural gas;
•: the difficulties encountered in delivering oil and natural gas to commercial markets;
•: foreign currency fluctuations;

•: the uncertainty of its ability to attract capital;
•: changes in, or the introduction of new, government regulations relating to the oil and natural gas business;
•: costs associated with developing and producing oil and natural gas;
•: compliance with environmental regulations;
•: liabilities stemming from accidental damage to the environment;
•: loss of the services of any of its executive officers or directors; and
•: adverse changes in the economy generally.

The information contained in this prospectus, including the information provided under the heading "Risk Factors," identifies additional factors that could affect Harvest's operating results and performance. We urge you to carefully consider those factors.

Harvest's forward-looking statements are expressly qualified in their entirety by this cautionary statement. Harvest's forward-looking statements are only made as of the date of this prospectus and we undertake no obligation to publicly update these forward-looking statements to reflect new information, subsequent events or otherwise.

DEFINITIONS AND OTHER MATTERS

As used in this prospectus, the following terms have the meaning indicated:

•: "bbls", "mbbls" and "mmbbls" mean barrels, thousand barrels and million barrels, respectively;
•: "bbls/d", "mcf/d", "mmcf/d" and "boe/d" mean barrels per day, thousand cubic feet per day, million cubic feet per day and barrels of oil equivalent per day, respectively;
•: "boe", "mboe" and "mmboe" mean barrel of oil equivalent, thousand barrels of oil equivalent and million barrels of oil equivalent, respectively;
•: "GJ" means gigajoule;
•: "mcf", "mmcf" and "bcf" mean thousand cubic feet, million cubic feet and billion cubic feet, respectively;
•: "mmbtu" means millions British thermal units;
•: "MW" and "MWh" mean megawatt and megawatt hour, respectively;
•: "NGL" means natural gas liquids.

Developed acreage means acreage on which Harvest has a productive well. Undeveloped acreage means acreage on which Harvest does not have a productive well and includes exploratory acreage. Proved developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities, or if facilities have not been installed, that would involve a low expenditure to put the reserves on production. Gross proved reserves or gross production are proved reserves or production attributable to Harvest's interest before deducting royalties and without including any royalty interests; net proved reserves or net production are proved reserves or production attributable to Harvest's interest after deducting royalties plus royalty interests. Natural gas volumes are converted to barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil, which is based on an energy equivalency method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Natural gas volumes are stated at the official temperature and pressure bases of the area in which the reserves are located.

PRESENTATION OF RESERVE INFORMATION

In this prospectus, proved reserves are defined in accordance with Canadian securities legislation and policies as set forth in National Instrument 51-101, which differ from SEC standards. Accordingly, in this prospectus, Harvest follows the Canadian practice of reporting its reserves and production using gross volumes which are volumes prior to deduction of royalties and without including any royalty interests. The SEC requires U.S. companies to report reserves and production using net volumes, after deduction of applicable royalties and similar payments.

The present value of future net revenues derived from proved reserves are calculated in accordance with Canadian practices and use forecast prices and costs. Included in this prospectus under the heading "Business — Oil and Gas Reserves" is the forecast pricing used to determine these future net revenues. The SEC requires U.S. companies to calculate the present value of future net revenues derived from proved reserves using constant prices and operating costs in effect on the date of the reserve report. Harvest has, however, provided supplementary information on oil and gas producing activities included with the financial statements which are included in this prospectus. This supplementary information provides disclosure about Harvest's oil and natural gas reserves in accordance with FASB Statement No. 69 and, in particular sets forth the standardized measure of Harvest's discounted future net cash flows based on constant prices and operating costs in effect on the date of the reserve report. Such supplementary information can be found commencing on page F-84.

CERTAIN FINANCIAL REPORTING MEASURES

We have used certain measures of financial reporting throughout this prospectus that are commonly used as benchmarks within the oil and natural gas industry. These measures include: Cash flow from operations, Net Debt, Adjusted Total Debt, EBITDA, Adjusted EBITDA and Operating Netbacks per BOE. These measures are not defined under Canadian GAAP or U.S. GAAP and should not be considered in isolation or as an alternative to conventional GAAP measures. Certain of these measures are not necessarily comparable to a similarly titled measure of another company or trust. Management uses Cash flow from operations and EBITDA to analyze operating performance and leverage. Cash flow from operations and EBITDA as presented are not intended to represent operating cash flow or operating profits for the period nor should they be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP or U.S. GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital.

SUMMARY

The summary highlights information contained elsewhere in this prospectus. Because this is only a summary, it does not contain all the information that may be important to you. Therefore, you should read the entire prospectus carefully, including in particular the "Risk Factors" and the financial statements and related notes. References in this prospectus to "Harvest Operations," "we," "our" and "us" refer to Harvest Operations Corp. References to "Harvest" and "the Trust" refer to Harvest Energy Trust and its subsidiaries, including Harvest Operations Corp., as a combined entity, except where the context requires otherwise. Information presented in this prospectus on a "pro forma" basis, unless the context suggests otherwise, gives effect to the acquisition of Storm Energy Ltd. and the EnCana assets, and related financings as if they had occurred at the beginning of the period indicated. All dollar amounts are in Canadian dollars unless otherwise indicated.

Harvest

Harvest is a Canadian oil and natural gas producer focused on extracting value from high quality, mature properties by employing state of the art technology and operational practices. Harvest uses technology and selective capital investment to maximize production rates while enhancing operational efficiencies to control and reduce expenses. Harvest also utilizes hedging techniques to manage cash flow. Harvest is an oil and natural gas royalty trust, and has operations in the East Central, Crossfield, Southeast and Redearth regions of Alberta and in the Carlyle region of southeastern Saskatchewan.

Harvest applies a two-pronged approach to increasing asset value and cash flow. First, Harvest seeks to make disciplined acquisitions of mature producing assets at prices that generate strong rates of return. Harvest's recent acquisitions of Storm and the EnCana assets built on the momentum created from its earlier transactions and resulted in longer reserve life and an improved balance in Harvest's commodity portfolio, and we believe will result in stronger operating netbacks. Second, Harvest focuses on creating incremental value through active management and technical and operating expertise. For example, Harvest works to optimize production and reduce unit costs to improve efficiencies, to economically add production and reserves and to extend property life.

At September 30, 2004, Harvest had approximately 37,500 boe/d of daily production and for the nine months ended September 30, 2004 pro forma adjusted EBITDA of approximately $228.3 million. See Note 4 to the table which is found on page 10 of this prospectus.

The following table summarizes Harvest's proved reserves as at July 1, 2004 on a pro forma basis and pro forma daily production:

	Light and Medium Oil	Heavy Oil	Natural Gas	NGLs	Total	PV10 Value⁽¹⁾
	(mbbls)	(mbbls)	(mmcf)	(mbbls)	(mboe)
Total proved reserves	42,517.6	20,857.3	69,681.7	2,114.1	77,102.6	$	802 million
Daily production	18.5	13.2	29.1	0.9	37.5

(1): PV10 is the present value of Harvest's estimated future net cash flow before income taxes for total proved reserves, discounted at 10% per year, calculated using forecast pricing. PV10 is not necessarily indicative of actual future cash flow or the fair market value of Harvest's reserves. See "Business — Oil and Gas Reserves" for forecast pricing used to determine this value.

Business Strengths

Ability to Extract Incremental Value from Mature Properties. Harvest focuses on acquiring under-managed properties, with predictable production profiles and significant original in place petroleum resource volumes. Harvest believes that these properties, despite having been under production for many years, have the potential to yield incremental production and proved reserves. Harvest undertakes active reservoir and infrastructure management, production optimization and low-risk development drilling to economically add incremental production and proved reserves. For example, Harvest has continuously increased proved reserves, net of production, at its Hayter property each year since the property was acquired in 2002.

Demonstrated Ability to Successfully Acquire Properties. Harvest has completed seven acquisitions in the past two years. Harvest believes that the average price paid per boe of reserves and per boe per day of production are below comparable acquisitions carried out in western Canada over the same time frame.

Low Cost Structure. Harvest's finding and development costs for the last two years have averaged $6.00/boe on a total proved reserve basis, which it believes is below the industry average. Operating costs as reflected in the pro forma consolidated statement of income for the nine months ended September 30, 2004 were $7.38/boe. In addition, some of the EnCana properties have no royalty associated with them, reducing Harvest's average royalty percentage to approximately 16%. The high ratio of proved producing reserves to total proved reserves (90%) also allows Harvest to realize value from its proved reserves more quickly and with fewer costs than would otherwise be the case. Managing costs allows Harvest to extend reserve life and mitigate the impact of a lower commodity price cycle.

Conservative Fiscal Management. Harvest employs a conservative fiscal management approach, which includes: (i) maintaining a prudent debt to cash flow ratio, (ii) active risk management and (iii) conservative distribution payout. Harvest actively manages its commodity price exposures by consistently reviewing market forecasts and executing commodity price hedges on significant portions of its production for periods ranging from 12 to 24 months. Harvest's cash retention ratio, which is the ratio of cash flow from operations less distributions to cash flow from operations, is currently the highest among the energy royalty trusts in Canada. This allows greater flexibility to repay indebtedness, invest in capital projects and manage through lower commodity price cycles.

Control Over Operations. Harvest maintains an average 85% working interest ownership in its properties and operates 90% of these properties, providing it with significant control over its results and allowing it to effect its business strategy.

Business Strategy

Harvest is focused on cash flow generation and increasing the value of its assets. The key elements of Harvest's strategy include the following:

Improve the Operating Netbacks of our Mature Properties. Harvest intends to continue to fine-tune each well and improve all aspects of its operations. Harvest is focused on reducing costs, which increases profit margins and cash flow, strengthens net asset value and increases proved reserves. Harvest also intends to increase net revenues through effective marketing measures.

Selectively Acquire Mature Properties. Harvest will continue to selectively acquire mature properties with an established production history. Once an asset is acquired, Harvest focuses its technical teams on improving resource recovery, reducing costs and extending reserve life from these properties. This approach is designed to increase production levels and extend property life, creating additional value. Harvest will continue to evaluate all future acquisitions on the basis of recycle ratio, which is the ratio of the operating netback obtained from a boe of production to the cost of acquiring a boe of reserves. Harvest will seek to achieve ratios in excess of 2 to 1, which Harvest believes will result in strong internal rates of return.

Minimize Risk to Assets and Operating Results. By employing comprehensive risk-management tools, Harvest will seek to protect its assets and provide a reliable near-term base for its cash flow. Risk management includes hedging a significant portion of production and electricity costs. Harvest has hedged the WTI price on approximately 75% of expected 2005 net oil production and the price of approximately 85% of expected 2005 electricity costs. In addition, Harvest will continue to perform preventative maintenance at field facilities, maintain comprehensive insurance programs, increase geographical diversification of assets and products and implement a strong environmental, health and safety program.

business principles for Harvest. Harvest has further strengthened its talent pool with selective personnel additions associated with asset acquisitions.

Recent Acquisitions

Storm Energy Ltd. On June 30, 2004, Harvest acquired Storm for approximately $189 million, including assumed net debt of approximately $65 million. Harvest paid approximately $75 million in cash and issued approximately $40 million of trust units and approximately $9 million of exchangeable shares of Harvest Operations to former shareholders of Storm. The Storm properties acquired produced approximately 4,060 boe/d during the six months ended June 30, 2004 and are primarily concentrated in the Redearth area of north central Alberta. These properties added high quality light oil to Harvest's product mix, providing diversification benefits, along with low operating costs.

EnCana Assets. On September 2, 2004, Harvest acquired Breeze Resources Partnership, which held the EnCana assets, for the purchase price of approximately $526 million, subject to adjustment. Harvest financed this acquisition through the issuance of $175 million of trust units and $100 million aggregate principal amount of convertible subordinated debentures, and borrowings of approximately $195 million under the revolving credit facility and $70 million under the bank bridge facility. The EnCana assets produced approximately 20,481 boe/d for the six months ended June 30, 2004 and are primarily concentrated in the Crossfield area of Alberta, southeast Alberta and east central Alberta. The Crossfield and southeast Alberta properties comprise Harvest's new southern Alberta core area, and the east central Alberta properties supplemented Harvest's existing properties in that core area. The acquisition of the EnCana assets added Harvest's first significant natural gas production.

The acquisition of Storm and the EnCana assets has increased production to approximately 37,500 boe/d as at September 30, 2004 from the previous production level of 15,060 boe/d on average for the six months ended June 30, 2004. Natural gas, as a percentage of total production, has increased to approximately 13% from approximately 2%. These acquisitions have provided a diversification of properties and commodities, and as of July 1, 2004, on a pro forma basis, increased Harvest's proved reserve life to 5.8 years and total proved reserves to 77.1 mmboe.

Corporate Structure

Harvest Energy Trust is an open-ended, unincorporated investment trust established under the laws of the Province of Alberta and created pursuant to the trust indenture in July 2002. The head and principal office of Harvest is located at Suite 1900, 330 - 5th Avenue S.W., Calgary, Alberta, T2P 0L4. Harvest's general phone number is (403) 265-1178. Harvest's trust units and convertible debentures are listed and posted for trading on the Toronto Stock Exchange under the trading symbols "HTE.UN," "HTE.DB" and "HTE.DB.A." The notes and the subsidiary guarantees will be fully and unconditionally guaranteed on an unsecured, unsubordinated basis by Harvest Energy Trust. The notes will not trade on a public stock exchange and Harvest has no plans at this time to list any of its securities on a U.S. public stock exchange.

Harvest Operations Corp. is a corporation incorporated under the laws of the Province of Alberta. Harvest Operations is a wholly-owned subsidiary of Harvest Energy Trust. Harvest Operations owns certain oil and natural gas properties and manages all of the properties held indirectly by the Trust.

Harvest acquired a 60% interest in the Redearth Partnership when it purchased Storm. Harvest's interest in the Redearth Partnership at the time of the Storm acquisition was approximately $20 million. As the partnership is not wholly owned, it is not a guarantor of Harvest Operations' obligations under the notes. See "Risk Factors Risks Relating to this Offering The notes and the guarantees will be structurally subordinate to the indebtedness of Harvest's subsidiaries that are not guarantors of the notes."

THE EXCHANGE OFFER

On October 14, 2004, Harvest sold its old notes in a private placement exempt from the registration requirements of the Securities Act, and Morgan Stanley & Co. Incorporated, TD Securities (USA) Inc., NFB Securities (USA) Corp. and WestLB AG London Branch as initial purchasers of these old notes then resold them in reliance on other exemptions from the registration requirements of the Securities Act. Consequently, the old notes are subject to transfer restrictions under the Securities Act. Pursuant to the terms of a registration rights agreement entered into by Harvest, the Guarantors and the initial purchasers on October 14, 2004, Harvest and the Guarantors agreed, among other things, to deliver this prospectus and to keep the exchange offer open for no less than 20 business days (or longer if required by applicable law) after the date the Notice of the Exchange Offer is mailed to the holders of the old notes. In addition, Harvest and the Guarantors agreed in the event that (i) the Company and the Guarantors determine that the Exchange Offer Registration is not available or may not be consummated as soon as practicable after the Exchange Date because it would violate applicable law or the applicable interpretations of the Staff of the SEC, (ii) the exchange offer is not for any other reason completed by 210 days from the Closing Date or (iii) the exchange offer has been completed and in the opinion of counsel for the Initial Purchasers a Registration Statement must be filed and a Prospectus must be delivered by the Initial Purchasers in connection with any offering or sale of Registrable Securities, they shall use their commercially reasonable efforts to cause to be filed as soon as practicable after such determination, date or notice of such opinion of counsel is given to the Company and the Guarantors, as the case may be, a Shelf Registration Statement providing for the sale by the Holders of all of the Registrable Securities and to have such Shelf Registration Statement declared effective by the SEC.

As holders of the old notes you are entitled to exchange in the exchange offer your old notes for new notes, which are identical in all material respects to the old notes except that:

•: In the event the exchange offer is not completed or the Shelf Registration Statement is not declared effective on or prior to 210 days from the Closing Date, the interest rate on the old notes will be increased by 0.25% per annum until the exchange offer is completed or the Shelf Registration Statement is declared effective by the SEC;
•: the new notes have been registered under the Securities Act and will be freely tradable by persons who are not affiliated with us;
•: the new notes are not entitled to the rights that are applicable to the old notes under the Registration Rights Agreement.

The Exchange Offer:		We are offering to exchange up to US$250,000,000 aggregate principal amount of our New 7⁷/8% Senior Notes, which have been registered under the Securities Act, for up to US$250,000,000 aggregate principal amount of our Old 7⁷/8% Senior Notes, which were issued on October 14, 2004 in a private placement. Old notes may be exchanged for new notes only in integral multiples of US$1,000.
Resale of the New Notes:		Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued in the exchange offer may be offered for resale, resold and otherwise transferred by you (unless you are our "affiliate" within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery requirements of the Securities Act, provided that you are:
		• acquiring the new notes in the ordinary course of business;
		• not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes; and

		• not a broker-dealer who purchased your old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.
		We do not intend to seek our own no-action letter, and there is no assurance that the SEC staff would make a similar determination with respect to the new notes. If this interpretation is inapplicable and you transfer any new notes issued to you in the exchange offer without delivering a prospectus or without an exemption under the Securities Act, you may incur liability under the Securities Act. We do not assume or indemnify you against this liability.
		Each broker-dealer that receives new notes for its own account in exchange for the old notes that were acquired by this broker-dealer as a result of market-making activities or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of those new notes. See "Plan of Distribution." Any holder of old notes who:
		• is our "affiliate" as defined in Rule 405 under the Securities Act;
		• does not acquire the new notes in the ordinary course of business;
		• tenders in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of the new notes; or
		• is a broker-dealer that purchased old notes from us to resell them pursuant to Rule 144A or any other available exemption under the Securities Act,
		cannot rely on the position of the SEC staff expressed in the no- action letters described above and, in the absence of an exemption, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of the new notes.
Expiration of Exchange Offer:		The exchange offer will expire at 5:00 p.m., New York City time, on February 11, 2005, unless we decide to extend the expiration date.
Withdrawal Rights:		You may withdraw the tender of your old notes at any time prior to 5:00 p.m., New York City time, on the expiration date.
Accrued Interest on the New Notes and the Old Notes:		The new notes will bear interest from the most recent date to which interest has been paid on the old notes or, if no interest has been paid on the old notes, from October 14, 2004.
Conditions to the Exchange Offer:		The exchange offer is subject to customary conditions, some of which we may waive. See "The Exchange Offer — Conditions to the Exchange Offer."
Procedures for Tendering Old Notes:		If you wish to exchange your old notes for new notes pursuant to the exchange offer, you must complete, sign and date the letter of transmittal according to the instructions contained in this prospectus and the letter of transmittal. You must also mail or otherwise deliver the letter of transmittal, together with your old notes and any other required documents, to the Exchange Agent at the address set forth on the cover of the letter of transmittal. If you hold old notes through The Depository Trust Company (the "DTC") and wish to participate in the exchange offer, you must comply with the Automated Tender Offer Program procedures of DTC, by which you will agree to be bound by the letter of transmittal. By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:
		• you are acquiring the new notes in the ordinary course of business;

		• you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the new notes;
		• if you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making or other trading activities, you will deliver a prospectus, as required by law, in connection with any resale of the new notes; and
		• you are not our "affiliate" as defined in Rule 405 under the Securities Act.
		See "The Exchange Offer — Procedures for Tendering Old Notes."
Special Procedures for Beneficial Owners:		If you own a beneficial interest in old notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee or custodian, and you wish to tender your old notes in the exchange offer, you should contact the registered holder as soon as possible and instruct the registered holder to tender on your behalf.
Guaranteed Delivery Procedures:		If you wish to tender your old notes and your old notes are not immediately available or you cannot deliver your old notes, the letter of transmittal or any other documents required by the letter of transmittal to the Exchange Agent or comply with the applicable procedures under DTC's Automated Tender Offer Program by the expiration date, you must tender your old notes pursuant to the guaranteed delivery procedures described in this prospectus under the heading "The Exchange Offer — Procedures for Tendering Old Notes — Guaranteed Delivery Procedures."
Consequences of Failure to Exchange the Old Notes for the New Notes:		All unexchanged old notes will continue to be subject to transfer restrictions. In general, the old notes may not be offered or sold unless registered under the Securities Act or pursuant to an exemption from registration under the Securities Act and applicable state securities laws. Therefore, the market for secondary resales of any unexchanged old notes is likely to be minimal. Other than in connection with the exchange offer, we do not currently anticipate that we will register the old notes under the Securities Act.
Federal Income Tax Consequences:		The exchange of the old notes for the new notes will generally not be a taxable event for U.S. federal income tax purposes. See "Important Federal Income Tax Considerations — Certain United States Federal Income Tax Consequences."
Use of Proceeds:		We will not receive any cash proceeds from the issuance of the new notes in the exchange offer. We will pay all expenses incident to the exchange offer. See "Use of Proceeds" and "The Exchange Offer — Fees and Expenses."
Exchange Agent for Notes:		U.S. Bank National Association is the Exchange Agent for the exchange offer.

THE NEW NOTES

The following summary is provided solely for your convenience. This summary is not intended to be complete. For a more detailed description of the notes, see "Description of the Notes."


Issuer:		Harvest Operations Corp.
Notes Offered:		US$250,000,000 aggregate principal amount of 7⁷/8% Senior Notes due October 15, 2011.
Maturity:		October 15, 2011.
Interest:		7⁷/8% per annum, payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2005.
Guarantees:		The new notes will be guaranteed by all of Harvest Energy Trust's wholly-owned subsidiaries, other than Harvest Operations, with respect to the payment of the principal, premium, if any, and interest on the new notes on an unsecured, unsubordinated basis. The payment obligations of all of the Trust's subsidiaries, including Harvest Operations Corp, under the Indenture, notes and subsidiary guarantees will be guaranteed by the Trust on an unsecured, unsubordinated basis.
Optional Redemption:		We may redeem any of the new notes beginning on October 15, 2008. The initial redemption price is 103.938% of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption price will decline each year after 2009 and will be 100% of their principal amount, plus accrued interest, beginning on October 15, 2010.
		In addition, before October 15, 2007, we may redeem up to 35% of the aggregate principal amount of outstanding notes with the proceeds from sales of Harvest's trust units or equivalent interests at a redemption price equal to 107.875% of their principal amount, plus accrued and unpaid interest to the redemption date. We may make such redemption only if, after any such redemption, at least 65% of the aggregate principal amount of notes originally issued under the indenture remains outstanding.
		In addition, before October 15, 2008, we may also redeem the new notes at a redemption price of 103.938% of their principal amount, plus accrued and unpaid interest to the redemption date, if, in the opinion of counsel, such redemption is necessary to prevent the Trust from being disqualified as a unit trust or a mutual fund trust for the purposes of the Income Tax Act (Canada). If such redemption would result in less than 65% of the aggregate principal amount of notes originally issued under the indenture being outstanding, the Issuer shall be required to redeem all of the outstanding new notes on the same terms.
Tax Redemption:		If we become obligated to pay withholding taxes related to payments on the new notes as a result of changes affecting Canadian withholding taxes, we may redeem all, but not less than all, of the notes at 100% of their principal amount, plus accrued and unpaid interest to the redemption date.
Change of Control:		Upon a change of control (as defined under "Description of the Notes — Definitions"), we will be required to make an offer to purchase the new notes. The purchase price will equal 101% of the principal amount of the notes on the date of purchase, plus accrued and unpaid interest. We may not have sufficient funds available at the time of a change of control to make any required debt payment (including repurchases of the new notes).

Ranking:		The new notes will be equal in right of payment with our existing and future unsubordinated indebtedness and senior in right of payment to our existing and future subordinated indebtedness. The new notes will be effectively junior to any of our existing and future secured indebtedness to the extent of the value of the assets securing such indebtedness. As of September 30, 2004, we had approximately $401.6 million of secured indebtedness outstanding.
		The guarantees will be equal in right of payment with the guarantors' existing and future unsubordinated indebtedness and senior in right of payment to any future subordinated indebtedness. The guarantees will be effectively junior to any of the guarantors' existing and future secured indebtedness to the extent of the value of the assets securing such indebtedness. As of September 30, 2004, the Trust had approximately $411.6 million of secured indebtedness outstanding, on a consolidated basis, and the subsidiary guarantors had approximately $401.6 million of secured indebtedness outstanding.
		The net proceeds from the issuance of the old notes was used to repay outstanding secured debt of Harvest Operations. On a pro forma basis, as at September 30, 2004 and after reflecting partial repayment of Harvest Operations' senior credit facility, the Trust had approximately $104.6 million of secured debt outstanding and the subsidiary guarantors had approximately $94.6 million secured debt outstanding. See "Capitalization."
		The new notes will be subordinated to any existing and future liabilities of any of the Trust's subsidiaries that are not guarantors. The Trust's interest in its only subsidiary that is not a guarantor of the new notes is not subject to any indebtedness other than Indebtedness under the Credit Agreement. See "Summary — Corporate Structure."
Additional Amounts:		All payments with respect to the new notes will be made without withholding or deduction for Canadian taxes unless required by law or the interpretation or administration thereof, in which case we will pay such withholding or deduction as may be necessary so that the net amount received by the holders after such withholding or deduction will not be less than the amount that would have been received in the absence of such withholding or deduction. See "Description of the Notes — Additional Amounts for Canadian Withholding Taxes."
Certain Covenants:		The terms of the new notes will limit the ability of Harvest to:
		• incur additional indebtedness;
		• pay dividends and make distributions in respect of its trust units and capital stock;
		• make investments or certain other restricted payments;
		• place limits on dividends and other payment restrictions affecting certain subsidiaries;
		• engage in sale-leaseback transactions;
		• enter into transactions with unitholders or affiliates;
		• guarantee debts;
		• sell assets and utilize proceeds therefrom;
		• create liens;
		• issue or sell stock of certain subsidiaries; and
		• merge, consolidate or amalgamate with another company.


		During any future period in which Moody's Investors Service and Standard and Poor's Ratings Services have each assigned an investment grade rating to the new notes, some of the covenants will cease to be in effect with the exception of the covenants that contain limitations on, among other things, the designation of restricted and unrestricted subsidiaries, consolidations, amalgamations, mergers and transfers of assets, liens and sale-leaseback transactions. These covenants are subject to important exceptions and qualifications, which are described under the heading "Description of the Notes — Certain Covenants" in this prospectus.

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table provides Harvest's selected financial data for the period from inception (July 10, 2002) to December 31, 2002 and the year ended December 31, 2003 and for the nine-month periods ended September 30, 2003 and 2004. The financial data for the period ended December 31, 2002 as well as the year ended December 31, 2003 have been derived from Harvest's consolidated financial statements for those periods, which were audited by KPMG LLP, independent accountants. The financial data for each of the nine month periods ended September 30, 2003 and 2004 have been derived from Harvest's unaudited consolidated financial statements for those periods. The unaudited consolidated financial statements have been prepared on the same basis as Harvest's audited financial statements except as disclosed in the notes to those financial statements. Harvest believes that the unaudited consolidated financial statements contain all adjustments necessary for a fair presentation of the financial information presented (consisting only of normal recurring adjustments). The historical financial data for the interim periods is not necessarily indicative of the results that may be expected for Harvest's full year of operations. The summary unaudited pro forma financial information for the nine months ended September 30, 2004 assumes that Harvest completed the acquisitions of Storm and the EnCana assets, and related financings, and this offering of notes and the application of the net proceeds therefrom on January 1, 2004. The summary unaudited pro forma financial information for the year ended December 31, 2003 assumes that Harvest completed these same transactions as well as the acquisition of the Carlyle properties on January 1, 2003. The pro forma information is not necessarily indicative of the actual operating results that would have occurred had these acquisitions and the issuance of the notes occurred on that date. The period over period comparisons are impacted by the acquisitions described in "Management's Discussion and Analysis of Financial Condition and Results of Operations." You should read Harvest's consolidated financial statements, unaudited consolidated financial statements, unaudited pro forma consolidated financial statements and the related notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this prospectus.

Harvest's financial statements have been prepared in accordance with Canadian GAAP, including a reconciliation to U.S. GAAP. In addition, Storm Energy Ltd.'s annual and interim consolidated financial statements, which have also been prepared in accordance with Canadian GAAP, include a reconciliation to U.S. GAAP. For a discussion of the differences between Canadian GAAP and U.S. GAAP as they pertain to Harvest's and Storm Energy Ltd.'s financial statements, you should read Note 20 to Harvest's consolidated financial statements, Note 3 to Harvest's pro forma consolidated balance sheet and statements of income, Note 11 to Storm Energy Ltd.'s consolidated financial statements as at and for the periods ended December 31, 2003 and 2002, note 11 to Storm Energy Ltd.'s unaudited consolidated financial statements as at and for the 3 month period ended March 31, 2004 and note 1 to the New Properties Schedule of Revenues, Royalties and Expenses which are included in this prospectus. All dollar amounts are in Canadian dollars unless otherwise stated.

									Nine Months Ended September 30,
			Period from July 10 (date of formation) to December 31, 2002⁽¹⁾			Year Ended December 31, 2003⁽¹⁾			Nine Months Ended September 30,						Pro Forma Nine Months Ended September 30, 2004
						Year Ended December 31, 2003⁽¹⁾			2003⁽¹⁾			2004			Pro Forma Nine Months Ended September 30, 2004
			(dollars in thousands)
Statement of Income Data:
Revenue:
	Oil and natural gas sales		$	22,709		$	119,351		$	79,407		$	202,681		$	426,058
	Royalty expense, net			(2,745	)		(16,412	)		(10,045	)		(33,031	)		(64,033	)
	Alberta royalty tax credit			—			—			—			—			198
	Other			—			—			—			—			328
	Hedging loss			(1,009	)		(18,924	)		(15,821	)		(37,761	)		(42,446	)
	Mark to market loss on commodity derivative contracts			—			—			—			(29,396	)		(29,396	)

				18,955			84,015			53,541			102,493			290,709
Expenses:
	Operating			6,396			36,045			23,061			46,267			83,784
	General and administrative			577			4,340			2,087			6,049			8,013
	Interest			2,010			2,975			1,807			3,919			22,763
	Finance charges and amortization of deferred finance charges			636			2,607			1,579			1,845			6,587
	Depletion, depreciation and accretion			6,192			35,727			24,275			53,002			142,206
	Foreign exchange gain			(255	)		(4,374	)		(5,313	)		(565	)		(565	)

		Total expenses		15,556			77,320			47,496			110,517			262,788

Income (loss) before taxes				3,399			6,695			6,045			(8,024	)		27,921
Taxes:
	Current income tax			—			—			—			—			841
	Corporation tax			47			157			138			256			373
	Future tax recovery			(1,480	)		(8,978	)		(3,906	)		(13,976	)		(14,195	)

Net income			$	4,832		$	15,516		$	9,813		$	5,696		$	40,902

Balance Sheet Data (at end of period):
Cash and short term investments			$	4,503		$	—		$	17,404		$	—
Non-cash working capital (deficiency)⁽²⁾				6,220			9,794			681			(25,149	)
Total assets				108,447			256,440			168,167			1,070,016
Bank debt				45,286			63,349			27,825			401,556
Total debt				45,286			63,349			27,825			401,556
Adjusted total debt⁽³⁾				45,286			88,349			61,325			507,690
Unitholders' equity				39,703			129,577			92,897			450,623
Other Financial Data:
Adjusted EBITDA⁽⁴⁾			$	11,982		$	43,630		$	28,263		$	79,573		$	228,308
Adjusted interest expense⁽⁵⁾				2,010			3,845			2,012			9,535			33,369
Capital expenditures				76,923			117,758			34,012			547,637

(1): Restated to reflect the adoption of the CICA Handbook standard for accounting for asset retirement obligation. See note 4 to Harvest's consolidated financial statements.
(2): Excludes current portion of debt.
(3): Adjusted total debt includes the full principal amount of the convertible subordinated debentures and the equity bridge, which under Canadian GAAP are classified as unitholders' equity.
(4): Adjusted EBITDA is the sum of net income before interest, taxes, depletion, depreciation and accretion expense, finance charges and amortization of deferred finance charges, foreign exchange gain and mark to market loss on commodity derivative contracts. Adjusted EBITDA is presented because management believes that it is a useful indicator of Harvest's ability to service indebtedness. However, adjusted EBITDA does not represent net income or cash flow from operations as defined by generally accepted accounting principles, is not necessarily indicative of cash available to fund all cash flow needs, should not be considered as an alternative to net income or to cash flow from operating activities (as determined in accordance with Canadian GAAP) and should not be construed as an indication of

a company's operating performance or as a measure of liquidity. The adjusted EBITDA of Harvest is not necessarily comparable with similarly-titled measures presented by other companies.

The following table reconciles adjusted EBITDA to net income:

							Nine Months Ended September 30,
	Period from July 10 (date of formation) to December 31, 2002⁽¹⁾			Year Ended December 31, 2003⁽¹⁾			Nine Months Ended September 30,						Pro Forma Nine Months Ended September 30, 2004
				Year Ended December 31, 2003⁽¹⁾			2003⁽¹⁾			2004			Pro Forma Nine Months Ended September 30, 2004
	(dollars in thousands)
Reconciliation of net income to Adjusted EBITDA:
Net income	$	4,832		$	15,516		$	9,813		$	5,696		$	40,902
Add (deduct):
Interest		2,010			2,975			1,807			3,919			22,763
Finance charges and amortization of deferred finance charges		636			2,607			1,579			1,845			6,587
Depletion, depreciation and accretion		6,192			35,727			24,275			53,002			142,206
Current income tax		—			—			—			—			841
Large corporation tax		47			157			138			256			373
Future tax recovery		(1,480	)		(8,978	)		(3,906	)		(13,976	)		(14,195	)

EBITDA		12,237			48,004			33,576			50,472			199,477
Foreign exchange gain		(255	)		(4,374	)		(5,313	)		(565	)		(565	)
Mark to market loss on commodity derivative contracts		—			—			—			29,396			29,396

Adjusted EBITDA	$	11,982		$	43,630		$	28,263		$	79,573		$	228,308

(5): Adjusted interest expense includes the interest associated with the equity bridge and the convertible subordinated debentures, which under Canadian GAAP are classified as unitholders' equity.

SUMMARY OIL AND NATURAL GAS RESERVE DATA

The following table summarizes Harvest's total proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at those dates, discounted at 10%. The proved reserve and present value data below has been prepared by McDaniel & Associates Consultants Ltd., independent qualified reserves evaluators, in respect of the Harvest assets as at December 31, 2003, and by McDaniel & Associates Consultants Ltd. and Paddock Lindstrom and Associates, independent qualified reserves evaluators, in respect of the Storm assets, and by McDaniel & Associates Consultants Ltd. and Gilbert Laustsen Jung Associates Ltd., independent qualified reserves evaluators, in respect of the EnCana assets. The total proved reserve and present value data as of July 1, 2004 include evaluations as of January 1, 2004, which have been updated to July 1, 2004 by the engineering firms who evaluated those reserves as of December 31, 2003.

	As of
	December 31, 2003		July 1, 2004 On a Pro Forma Basis
Proved Reserves:
Light and medium oil (mbbls)		19,251.6		42,517.6
Heavy oil (mbbls)		7,511.3		20,857.3
Natural gas (mmcf)		1,988.2		69,681.7
NGLs (mbbls)		122.1		2,114.1
Total (mboe)		27,216.4		77,102.6
Proved developed reserves as a percentage of total proved reserves		95.0%		89.9%
Present Value:
PV10 ($000)⁽¹⁾	$	154,922	$	801,589
Other Reserve Data:
Proved reserve life index (years)⁽²⁾		5.0		5.8

(1): PV10 is the present value of Harvest's estimated future net cash flow before income taxes for total proved reserves, discounted at 10% per year, calculated using forecast pricing. PV10 is not necessarily indicative of actual future cash flow or the fair market value of Harvest's reserves. See "Business Oil and Gas Reserves" for forecast pricing used to determine this value as of July 1, 2004.
(2): Calculated by dividing the total proved reserves by the total production expected in the independent reserve evaluator's report, for each period.

SUMMARY OPERATING DATA

The following table provides summary data with respect to Harvest's production and sales of oil and natural gas for the periods indicated.

							Nine Months Ended September 30,
		Period from July 10 (date of formation) to December 31, 2002		Year Ended December 31, 2003			Nine Months Ended September 30,
				Year Ended December 31, 2003			2003			2004
Net Daily Production Volumes:
	Light crude oil (bbls/day)		—		1,028			—			6,461
	Medium crude oil (bbls/day)		2,718		4,286			4,300			4,553
	Heavy crude oil (bbls/day)		1,463		5,444			5,192			6,271
	Natural gas (mcf/day)		624		1,311			1,165			5,049
	Natural gas liquids (bbls/day)		22		64			68			190
	Total (boe/day)		4,307		11,040			9,754			18,317
Weighted Average Sales Prices:
	Light crude oil (per barrel)	$	—	$	35.56		$	—		$	46.52
	Medium crude oil (per barrel)		34.21		32.18			32.05			39.89
	Heavy crude oil (per barrel)		22.63		27.34			27.80			35.67
	Natural gas (per mcf)		4.54		6.70			6.71			5.83
	Natural gas liquids (per barrel)		37.64		29.92			29.93			37.37
Per Barrel of Oil Equivalent Data:
	Net revenue⁽¹⁾	$	25.15	$	20.88		$	20.11		$	26.43
	Operating costs		8.49		8.94			8.66			9.22

	Operating netback		16.66		11.94			11.45			17.21
	General and administrative cash expenses⁽³⁾		0.76		1.02			0.77			1.06
	Interest expense		2.67		0.74			0.68			0.78
	Finance charges⁽⁴⁾		0.56		0.01			—			—
	Realized foreign exchange gain		—		(1.44	)		(2.37	)		(0.36	)
	Current taxes		0.06		0.04			0.05			0.05

	Cash flow from operations⁽²⁾	$	12.61	$	11.57		$	12.32		$	15.68

(1): Represents oil and natural gas sales less net royalty expense and hedging loss, but excludes mark to market losses on commodity derivative contracts as a non-cash item.
(2): Represents cash flow provided by operating activities, exclusive of the net change in non-cash working capital balances and site restoration and reclamation expenditures.
(3): Excludes unit based compensation as a non-cash item.
(4): Excludes amortization of deferred finance charges as a non-cash item.

RISK FACTORS

You should carefully consider the following matters, as well as the other information contained in this prospectus, before making an investment decision. If any of the risks described below materialize, Harvest's business, financial condition or results of operations could be materially and adversely affected. Additional risks and uncertainties not currently known to Harvest that it currently views as immaterial may also materially and adversely affect its business, financial condition or results of operations. In such case, our ability to satisfy our obligations to the holders of the notes and the trading price of the notes would be adversely affected.

Risks Relating to Harvest's Business

Oil and natural gas prices are volatile and low prices will adversely affect Harvest's business.

Fluctuations in the prices of oil and natural gas will affect many aspects of Harvest's business, including:

•: revenues, cash flow and earnings;
•: ability to attract capital to finance its operations;
•: cost of capital;
•: the amount Harvest is allowed to borrow under its senior credit facilities; and
•: the value of Harvest's oil and natural gas properties.

Both oil and natural gas prices are extremely volatile. Oil prices are determined by international supply and demand. Political developments, compliance or non-compliance with self-imposed quotas, or agreements between members of the Organization of Petroleum Exporting Countries can affect world oil supply and prices. Prices obtained for Harvest's natural gas production are determined by supply and demand factors within North America. Harvest sells its natural gas production at sales points in Canada and there is a differential between those prices and prices for natural gas determined at various markets in the United States, such as quoted prices at Henry Hub and on the NYMEX. These differentials change from time to time depending on a number of factors.

Any material decline in prices could result in a reduction of Harvest's net production revenue and overall value. The economics of producing from some wells could change as a result of lower prices. As a result, Harvest could elect not to produce from certain wells. Any material decline in prices, and resultant impact on earnings, cash flow and Harvest's ability to complete additional financings could also result in a reduction in Harvest's oil and natural gas acquisition and development activities.

In addition, a material decline in oil and natural gas prices from historical average prices could reduce Harvest's borrowing base under its senior credit facilities, therefore reducing amounts available to Harvest and possibly requiring that a portion of its senior credit facilities be repaid, which could have a material adverse effect on Harvest's liquidity.

The differential between light oil and heavy oil prices is volatile and could adversely affect net prices obtained and cash flow.

Harvest's crude oil production is approximately 34% light oil, 26% medium oil and 40% heavy oil. Processing medium oil and heavy oil is more expensive than processing light oil, and such processing yields less valuable products compared to refining light oil; accordingly, producers of heavy oil or medium oil receive lower wellhead prices. The price differential between light oil and heavy oil or medium oil has fluctuated widely during recent years and when considered with the fluctuating prices of light oil, substantially increases the volatility of prices for heavy oil and medium oil. Any increase in the differentials could result in lower prices being received for petroleum and natural gas liquids and could have a material adverse effect on Harvest's operations, financial condition and the level of funds available for the development of its oil and natural gas reserves. Volatility in the differential is a result of availability of supply, seasonal demand, pipeline constraints and conversion capacity of refineries, which are beyond the control of Harvest.

You should not unduly rely on reserve information because reserve information represents estimates.

Estimates of oil and natural gas reserves involve a great deal of uncertainty because they depend in large part upon the reliability of available geologic and engineering data, which is inherently imprecise. Geologic and engineering data are used to determine the probability that a reservoir of oil and natural gas exists at a particular location, and whether oil and natural gas are recoverable from a reservoir. Recoverability is ultimately subject to the accuracy of data regarding, among other factors:

•: geological characteristics of the reservoir structure;
•: reservoir fluid properties;
•: the size and boundaries of the drainage area; and
•: reservoir pressure and the anticipated rate of pressure depletion.

The evaluation of these and other factors is based upon available seismic data, computer modeling, well tests and information obtained from production of oil and natural gas from adjacent or similar properties, but the probability of the existence and recoverability of reserves is less than 100% and actual recoveries of proved reserves usually differ from estimates.

Estimates of oil and natural gas reserves also require numerous assumptions relating to operating conditions and economic factors, including, among others:

•: the price at which recovered oil and natural gas can be sold;
•: the costs associated with recovering oil and natural gas;
•: the prevailing environmental conditions associated with drilling and production sites;
•: the availability of enhanced recovery techniques;
•: the ability to transport oil and natural gas to markets; and
•: governmental and other regulatory factors, such as taxes and environmental laws.

A change in any one or more of these factors could result in known quantities of oil and natural gas previously estimated as proved reserves becoming unrecoverable. For example, a decline in the market price of oil or natural gas to an amount that is less than the cost of recovery of such oil and natural gas in a particular location could make production thereof commercially impracticable. The risk that a decline in price could have that effect is magnified in the case of reserves requiring sophisticated or expensive production enhancement technology and equipment, such as some types of heavy oil. Each of these factors, by having an impact on the cost of recovery and the rate of production, will also affect the present value of future net cash flow from estimated reserves.

In addition, estimates of reserves and future net cash flows expected from them prepared by different independent engineers or by the same engineers at different times, may vary substantially.

In addition, in accordance with Canadian GAAP, Harvest could be required to write down the carrying value of its oil and natural gas properties if oil and natural gas prices become depressed for even a short period of time, or if there are substantial downward revisions to its quantities of proved reserves. A write down would result in a charge to earnings.

If Harvest is unsuccessful in acquiring and developing oil and natural gas properties, it will be unable to replace reserves that it has produced and its business will be adversely affected because it will eventually deplete its reserves.

Harvest's future success depends upon its ability to find, acquire and develop additional oil and natural gas reserves that are economically recoverable. Without successful exploitation or acquisition activities, Harvest's reserves, revenues and cash flow may decline and we may not have sufficient funds to service our indebtedness, including the notes. Based on current production, Harvest's total proved reserves will be depleted prior to the maturity of the notes. Harvest may not be able to find, acquire or develop additional reserves at an acceptable

cost. Competition for the acquisition of prospective oil and natural gas properties and oil and natural gas reserves is intense. Harvest expects the competition to continue which may increase the purchase price of any potential acquisition. If Harvest does not successfully replace its reserves and extend its reserve life, Harvest might not generate sufficient cash flow to be able to repay the notes at maturity.

The successful acquisition and development of oil and natural gas properties requires an assessment of:

•: recoverable reserves;
•: future oil and natural gas prices and operating costs;
•: potential environmental and other liabilities, including any defects in land title; and
•: productivity of new wells drilled.

These assessments are inexact. As a result, Harvest might not recover the purchase price of a property from the sale of production from the property, or might not recognize an acceptable return from properties it acquires. In addition, Harvest's exploration and development activities may not result in any increases in reserves.

In addition, the costs of acquisition, exploitation and development could materially exceed initial estimates. Depending on exploration and development activity levels generally in the oil and natural gas industry in western Canada, access to services and the cost of those services may change and may limit Harvest's ability to carry out acquisitions or necessary or planned exploitation and development activities on its properties.

Harvest has used both debt and equity to finance its acquisitions. Harvest's ability to obtain the necessary financing is subject to external factors including, but not limited to, fluctuations in equity and commodity markets, economic downturns and interest and foreign exchange rates. Adverse changes in these factors could require Harvest's management to alter Harvest's current business plan, and may impair its ability to acquire oil and natural gas properties. A substantial portion of the debt that Harvest has used to effect acquisitions has been borrowed under its revolving credit facility. Borrowing under the revolving credit facility is limited by a borrowing base which is established periodically by the unanimous determination of its lenders.

Failure to realize anticipated benefits of recent and future acquisitions may have a material adverse effect on Harvest's business, results of operations and financial condition.

Since July 2002, Harvest has acquired a number of oil and natural gas producing properties, including the recent acquisition of Storm and the EnCana assets. Achieving the benefits of these and future acquisitions depends in part on the timely and efficient integration of the acquired operations, procedures and personnel as well as the successful application of our reserve management techniques to these assets. The integration process involves a number of financial, managerial and operational risks such as the loss of key employees and the disruption of ongoing business, customer and employee relationships. The failure to integrate these acquisitions successfully may have a material adverse effect on Harvest's business, results of operations and financial condition.

Reductions in cash flow, due to changes in realized prices or any of the other risk factors described herein, would impact Harvest's ability to make distributions, which could severely limit its ability to issue units as a source of financing.

Harvest currently pays a monthly distribution to its unitholders of $0.20 per unit. Should Harvest's cash flow decline significantly, Harvest may be unable to continue to make such distribution payments to its unitholders, limiting its ability to issue incremental equity and restricting one of the main sources of acquisition financing otherwise available to it.

Harvest will not be able to develop its reserves or make acquisitions if it is unable to generate sufficient cash flow or raise capital.

Harvest will be required to make substantial capital expenditures to develop its existing reserves and to discover new oil and gas reserves. Historically, Harvest has financed these expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from the sale of debt and equity securities. Harvest

may not be able to generate sufficient cash flow or raise capital in the future. Harvest also makes offers to acquire oil and natural gas properties in the ordinary course of its business. If these offers are accepted, Harvest's capital needs may increase substantially.

Information in this prospectus regarding Harvest's future exploitation and development projects reflects Harvest's current intent and is subject to change.

Harvest's current exploitation and development plans are described in this prospectus. Whether Harvest ultimately undertakes an exploitation or development project will depend on the following factors:

•: availability and cost of capital;
•: receipt of additional seismic data or the reprocessing of existing data;
•: current and projected oil or natural gas prices;
•: the costs and availability of drilling rigs and other equipment supplies and personnel necessary to conduct these operations;
•: success or failure of activities in similar areas;
•: changes in the estimates of the costs to complete the projects;
•: Harvest's ability to attract other industry partners to acquire a portion of the working interest to reduce costs and exposure to risks; and
•: decisions of Harvest's joint working interest owners and partners.

Harvest will continue to gather data about its projects and it is possible that additional information will cause Harvest to alter its schedule or determine that a project should not be pursued at all. You should understand that Harvest's plans regarding its projects might change.

Drilling and other capital activities are subject to many risks and any interruption or lack of success in Harvest's drilling activities will adversely affect its business.

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. New wells that Harvest drills may not be productive or Harvest may not recover all or any portion of its investment. Drilling for oil and natural gas could involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce enough net revenue to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Harvest's drilling, completion, well workover and pipeline and facility construction operations could be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond Harvest's control, including:

•: adverse weather conditions;
•: compliance with governmental regulations; and
•: mechanical difficulties or shortages or delays in the delivery of equipment and services.

Harvest's operations are affected by operating hazards and uninsured risks and a shutdown or slowdown of its operations will adversely affect its business.

There are many operating hazards in drilling for and producing oil and natural gas, including:

•: Harvest's drilling operations could encounter unexpected formations or pressures that could cause damage to equipment or personal injury;
•: Harvest could experience blowouts, accidents, oil spills, fires or other damage to a well that could require it to redrill it or take other corrective action;
•: Harvest could experience equipment failure that curtails or stops production;

•: Harvest's drilling and production operations, such as trucking of oil, are often interrupted by bad weather; and
•: Harvest could be unable to access its properties or conduct its operations due to surface conditions.

Any of these events could result in damage to or destruction of oil and natural gas wells, production facilities or other property, or injury to persons. In addition, any of the above events could result in environmental damage or personal injury for which Harvest will be liable.

Harvest may not be able to maintain adequate insurance at rates it considers reasonable to cover its possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could seriously harm Harvest's financial condition and operating results. Furthermore, insurance may not be continually available or available at commercially acceptable prices for Harvest.

If Harvest is unable to access its properties or conduct its operations due to surface conditions, its business will be adversely affected.

The exploitation and development of oil and natural gas reserves depends upon access to areas where operations are to be conducted. Oil and natural gas industry operations are affected by road bans imposed from time to time during the break-up and thaw period in the spring. Road bans are also imposed due to snow, mud and rock slides and periods of high water, which can restrict access to Harvest's well sites and production facility sites.

Harvest conducts a portion of its operations in northern regions where it is only able to do so on a seasonal basis. Unless the surface is sufficiently frozen, Harvest is unable to access its properties, drill or otherwise conduct its operations as planned. In addition, if the surface thaws earlier than expected, Harvest must cease its operations for the season earlier than planned. In recent years, winters in Harvest's northern operating areas have been warmer than normally experienced and, as a result, Harvest's operating seasons have been shorter than in the past. Harvest's inability to access its properties or to conduct its operations as planned will result in a shutdown or slow down of its operations, which will adversely affect its business.

Aboriginal peoples may make claims regarding the lands on which Harvest's operations are conducted.

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada, including some of the properties on which Harvest conducts its operations. If any aboriginal peoples file a claim claiming aboriginal title or rights to the lands on which any of Harvest's properties are located, and if any such claim is successful, it could have a material adverse effect on Harvest's operations.

Harvest's commodity price hedging activities could result in losses.

The nature of Harvest's operations results in exposure to fluctuations in commodity prices and foreign exchange movements. Harvest monitors and, when appropriate, utilizes derivative financial instruments and physical delivery contracts to hedge its exposure to these risks. Harvest is exposed to credit-related losses in the event of non-performance by counter-parties to the financial instruments. From time to time Harvest enters into hedging activities in an effort to mitigate the potential impact of declines in oil and natural gas prices, strengthening of the Canadian dollar and increases in electricity prices. These activities consist of, but are not limited to:

•: buying a price floor under which Harvest will receive a minimum price for its oil and natural gas production;
•: buying a collar, under which Harvest will receive a price within a specified price range for oil and natural gas production;
•: entering into fixed price contracts for oil and natural gas production;
•: entering into a contract to fix the price differential between light and heavy oil;
•: entering into fixed price contracts for electricity supply in Alberta; and

•: buying a floor or an option to exchange U.S. dollars for Canadian dollars at a fixed exchange rate.

If product or electricity prices increase above or decrease below those levels specified in Harvest's various hedging agreements or the U.S. dollar strengthens against the Canadian dollar, Harvest could lose the amount paid to purchase any related cost of floors, or a ceiling or fixed price could limit Harvest from receiving the full benefit of favorable commodity price movements. For the nine months ended September 30, 2004, Harvest's hedging resulted in an opportunity cost of $37.8 million due to strong oil and natural gas prices. Harvest may face continued opportunity cost in the future as a result of hedging.

In addition, by entering into these hedging activities, Harvest may suffer financial loss if:

•: it is unable to produce oil or natural gas to fulfill its obligations;
•: it is required to pay a margin call on a hedge contract; or
•: it is required to pay royalties based on a market or reference price that is higher than its fixed or ceiling price.

Harvest is exposed to currency exchange risk which could have a material adverse effect on its results of operations and financial condition.

Harvest's operating results are sensitive to fluctuations in the exchange rate of the Canadian dollar to the U.S. dollar, as prices for its products are denominated in U.S. dollars or linked to prices quoted in U.S. dollars, while most of its operating costs are incurred in Canadian dollars. Therefore, an increase in the value of the Canadian dollar relative to the U.S. dollar reduces the amount of revenue in Canadian dollar terms realized by Harvest from sales made in U.S. dollars, which reduces its operating margin and the cash flow available to fund its operations.

In addition, Harvest is exposed to currency exchange risk on its debt, including the notes and interest thereon, and assets denominated in U.S. dollars. Since Harvest presents its financial statements in Canadian dollars, any change in the value of the Canadian dollar relative to the U.S. dollar during a given financial reporting period would result in a foreign currency loss or gain on the translation of its U.S. dollar-denominated debt and assets into Canadian dollars. Consequently, Harvest's reported earnings could fluctuate materially as a result of foreign exchange translation gains or losses.

To mitigate the impact of foreign exchange volatility on its earnings, from time to time Harvest may enter into agreements to fix the exchange rate of Canadian dollars to United States dollars. Harvest does so in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the U.S. dollar. However, if the Canadian dollar declines in value compared to the U.S. dollar, Harvest will not benefit from the fluctuating exchange rate to the extent that it has entered into such foreign exchange agreements. Conversely, Harvest may enter into agreements to fix the exchange rate to protect the principal and interest payments on its U.S. dollar denominated liabilities. If it does so, it will not benefit from any increase in the value of the Canadian dollar compared to the U.S. dollar when these payments become due. Harvest's exchange rate agreements could result in losses.

Harvest's business is subject to environmental and other government laws and regulations in all jurisdictions in which it operates and its compliance with such regulations could be costly and could negatively impact its results of operations and production.

Harvest's operations are governed by numerous Canadian laws and regulations at the provincial and federal level. These laws and regulations govern the operation and maintenance of Harvest's facilities, the discharge of materials into the environment and other environmental protection issues. The laws and regulations may, among other potential consequences:

•: require that Harvest acquire permits before commencing drilling;
•: restrict the substances that can be released into the environment in connection with drilling and production activities;
•: limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas;

•: require that reclamation measures be taken to prevent pollution from former operations;
•: require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remediating contaminated soil and groundwater; and
•: require remedial measures be taken with respect to property designated as a contaminated site, for which Harvest is a responsible person.

Under these laws and regulations, Harvest could be liable for personal injury, clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. Harvest maintains limited insurance coverage for sudden and accidental environmental damages. However, Harvest does not believe that insurance coverage for the full potential liability of environmental damages is available at a reasonable cost. Accordingly, Harvest could be liable, or could be required to cease production on properties, if environmental damage exists or occurs.

The costs of complying with environmental laws and regulations in the future may have that kind of effect. Furthermore, changes could occur that result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on Harvest's financial condition or results of operations.

In addition, Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called "greenhouse gases." Harvest's production facilities and other operations and activities emit a small amount of greenhouse gases which may subject Harvest to legislation regulating emissions of greenhouse gases. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and natural gas development and production. Future federal legislation, together with provincial emission reduction requirements, such as those proposed in Alberta's Bill 32: Climate Change and Emissions Management, may require the reduction of emissions or emissions intensity of Harvest's operations and facilities. The direct or indirect costs of these regulations may adversely affect Harvest's business.

Factors beyond Harvest's control affect its ability to market production.

Harvest's ability to market oil and natural gas from its wells depends upon numerous factors beyond its control. These factors include:

•: the availability of capacity to refine heavy oil;
•: the availability of natural gas processing capacity;
•: the availability of pipeline capacity;
•: the supply of and demand for oil and natural gas;
•: the availability of alternative fuel sources;
•: the availability of diluent to blend with heavy oil to enable transportation;
•: the availability of fuel natural gas to operate processing and transportation facilities;
•: the price of electricity;
•: the price of oilfield services;
•: the effects of inclement weather;
•: Canadian federal and provincial regulation of oil and natural gas operations, production and marketing; and
•: Canadian federal regulation of natural gas sold or transported outside of the province of Alberta.

Because of these factors, Harvest may be unable to market all of the oil or natural gas it produces or to obtain favorable prices for the oil and natural gas it produces.

Harvest does not control all of its operations.

Harvest does not operate all of its properties and it therefore has limited influence over the operations of some of its properties. Harvest's lack of control could result in the following:

•: the operator might initiate exploration or development on a faster or slower pace than Harvest prefers;
•: the operator might propose to drill more wells or build more facilities on a project than Harvest has funds for or that Harvest deems appropriate, which could mean that Harvest is unable to participate in the project or share in the revenues generated by the project even though it paid its share of exploration costs, and Harvest could have its working interest ownership in the related lands and petroleum reserves reduced as a result of its failure to participate in development expenditures; and
•: if an operator refuses to initiate a project, Harvest might be unable to pursue the project.

Any of these events could materially reduce the value of Harvest's properties.

Essential equipment might not be available.

Oil and natural gas exploitation and development activities depend upon the availability of drilling and related equipment in the particular areas where those activities will be conducted. Demand for that equipment or access restrictions may affect the availability of that equipment to Harvest and delay its exploitation and development activities.

Harvest operates in a highly competitive industry.

The oil and natural gas industry is highly competitive. Harvest's competitors include companies and other entities, such as other royalty trusts, that have greater financial and personnel resources than it does. Harvest's ability to acquire additional properties and to discover reserves in the future depends upon its ability to evaluate and select suitable properties and to complete transactions in a highly competitive environment. You should refer to the section of this prospectus entitled "Business Competition."

Risks Relating to the Notes

If you do not properly tender your old notes, you will not receive new notes in the exchange offer, and you may not be able to sell your old notes.

We registered the new notes, but not the old notes, under the Securities Act. The old notes may not be offered or sold except pursuant to an exemption from the registration of the Securities Act and applicable state securities laws or pursuant to an effective registration statement. We will issue new notes only in exchange for old notes that are timely received by the Exchange Agent, together with all required documents, including a properly completed and duly signed letter of transmittal. Therefore, you should allow sufficient time to ensure timely delivery of the old notes, and you should carefully follow the instructions on how to tender your old notes.

Neither we nor the Exchange Agent is required to tell you of any defects or irregularities with respect to your tender of the old notes. If you do not tender your old notes or if we do not accept your old notes because you did not tender your old notes properly, then, after we consummate the exchange offer, you will continue to hold old notes that are subject to the existing special interest and transfer restrictions. In general, you may not offer or sell the old notes unless they are registered under the Securities Act or offered or sold in a transaction exempt from, or not subject to, the registration requirements of the Securities Act and applicable state securities laws.

Although we may in the future seek to acquire unexchanged old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise, we have no present plans to acquire any unexchanged old notes or to file with the SEC a shelf registration statement to permit resales of any unexchanged old notes. In addition, holders who do not tender their old notes, except for initial purchasers or

holders of old notes who are prohibited by applicable law or SEC policy from participating in the exchange offer or may not resell the new notes acquired in the exchange offer without delivering a prospectus and this prospectus is not appropriate or available for such resales by such holders, will not have any further registration rights and will not have the right to receive special interest on their old notes.

The market for the old notes may be significantly more limited after the exchange offer.

Because we anticipate that most holders of old notes will elect to exchange their old notes, we expect that the liquidity of the market for any old notes remaining after the completion of the exchange offer may be substantially limited. Any old notes tendered and exchanged in the exchange offer will reduce the aggregate principal amount of the old notes outstanding. Accordingly, the liquidity of the market for any old notes could be adversely affected and you may be unable to sell them. The extent of the market for the old notes and the availability of price quotations would depend on a number of factors, including the number of holders of old notes remaining outstanding and the interest of securities firms in maintaining a market in the old notes. An issue of securities with a smaller number of units available for trading may command a lower, and more volatile, price than would a comparable issue of securities with a larger number of units available for trading. Therefore, the market price for the old notes that are not exchanged may be lower and more volatile as a result of the reduction in the aggregate principal amount of the old notes outstanding.

If you do not properly tender your old notes, you will not receive new notes in the exchange offer, and you may not be able to sell your old notes.

The amount of Harvest's indebtedness could adversely affect its financial health and prevent it from fulfilling its obligations under the notes.

Harvest has now and will continue to have a significant amount of indebtedness. As of September 30, 2004, Harvest had total indebtedness of approximately $508 million, which consists of approximately $402 million outstanding under the senior credit facilities, $96 million principal amount of convertible debentures and $10 million outstanding under the equity bridge. Following completion of the offering of the notes in October 2004, Harvest issued US$250 million of notes and used net proceeds therefrom to repay outstanding balances under its senior credit facilities.

Harvest's substantial indebtedness could have important consequences to you. For example, it could:

•: make it more difficult for Harvest to satisfy its obligations with respect to the notes;
•: increase Harvest's vulnerability to general adverse economic and industry conditions;
•: require Harvest to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of its cash flow to fund property development expenditures, acquisition efforts and other general corporate purposes;
•: limit Harvest's flexibility in planning for, or reacting to, changes in its business and the industry in which it operates;
•: place Harvest at a competitive disadvantage compared to its competitors that have less indebtedness; and
•: limit Harvest's ability to borrow additional funds.

Despite its current level of indebtedness, Harvest and its subsidiaries may still be able to incur substantially more indebtedness. This could further exacerbate the risks associated with Harvest's substantial leverage.

Harvest and its subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indenture do not fully prohibit Harvest or its subsidiaries from doing so. If new indebtedness is added to Harvest and its subsidiaries' current level of indebtedness, the related risks that Harvest and its subsidiaries now face could intensify. See "Description of Other Indebtedness."

To service its indebtedness, Harvest will require a significant amount of cash. Harvest's ability to generate cash depends on many factors beyond its control.

Harvest's ability to make payments on and to refinance its indebtedness, including these notes, and to fund planned capital expenditures will depend on its ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors, including commodity prices, that are beyond its control. In addition, as a Canadian royalty trust, Harvest distributes a significant portion of its cash flow from operations to unitholders on a monthly basis. As a result, Harvest does not expect to accumulate significant amounts of cash to help fund its liquidity needs or service its debt.

Harvest cannot assure you that its business will generate sufficient cash flow from operations or that future borrowings will be available to it under its senior credit facilities in an amount sufficient to enable it to pay its indebtedness, including these notes, or to fund its other liquidity needs. Harvest may need to refinance all or a portion of its indebtedness, including these notes on or before maturity. Harvest cannot assure you that it will be able to refinance any of its indebtedness, including its senior credit facilities, its convertible debentures and these notes, on commercially reasonable terms or at all.

The notes will be effectively subordinated to Harvest's existing and future secured indebtedness and other secured obligations and any other secured indebtedness.

Holders of Harvest's secured indebtedness and the secured indebtedness of any of its subsidiaries will have claims that are prior to your claims as holders of the notes to the extent of the value of the assets securing that other indebtedness. In the event of any distribution or payment of assets of Harvest or its subsidiaries in any foreclosure, dissolution, winding-up, liquidation, reorganization or other bankruptcy proceeding, holders of secured indebtedness will have a prior claim to the assets that constitute their collateral. Harvest cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of notes may receive less, on a pro rata basis, than holders of secured indebtedness. As of September 30, 2004, Harvest and its subsidiaries had approximately $411.6 million of outstanding secured indebtedness and on a pro forma basis, reflecting repayment of bank indebtedness with net proceeds from the issuance of the old notes, $104.6 million of secured indebtedness. Harvest may also incur additional secured indebtedness in the future in accordance with the terms of the indenture.

The notes and the guarantees will be structurally subordinate to the indebtedness of Harvest's subsidiaries that are not guarantors of the notes.

You will not have any claim as a creditor against Harvest's subsidiaries that are not guarantors of the notes which currently includes Harvest's 60% owned subsidiary, Redearth Partnership. As a result, all indebtedness and other liabilities, including trade payables, of the non-guarantor subsidiaries, whether secured or unsecured, must be satisfied before any of the assets of such subsidiaries would be available for distribution, upon a liquidation or otherwise, to Harvest in order for it to meet its obligations with respect to the guarantees. As of September 30, 2004, Harvest's interest in the assets of the Redearth Partnership was approximately $20 million.

Harvest's senior credit facilities and the indenture governing the notes will contain covenants limiting the discretion of management in the operation of its business.

Harvest's senior credit facilities and the indenture governing the notes will contain provisions that limit management's discretion by restricting its ability to:

•: incur additional indebtedness and effect hedging arrangements;
•: pay dividends or distributions on its trust units and capital stock or repurchase its trust units;
•: make certain investments or certain other restricted payments;
•: place limits on dividends and other payment restrictions affecting it and its subsidiaries;
•: engage in sale-leaseback transactions;
•: enter into transactions with unitholders or affiliates;

•: guarantee debts or provide other financial assistance;
•: sell assets and utilize proceeds therefrom;
•: create liens;
•: issue or sell stock of certain subsidiaries;
•: merge, consolidate or amalgamate with another company; and
•: transfer and sell assets.

Some of the restrictions in the indenture will not apply when the notes have investment grade ratings. In addition, the senior credit facilities require that Harvest meet specified financial ratios.

If Harvest fails to comply with the restrictions in the senior credit facilities, the Indenture governing the notes or any other subsequent financing agreements, it will be in default. A default may allow Harvest's lenders, if the agreements so provide, to accelerate the related obligations and any other obligations to which a cross-acceleration or cross-default provision applies. In addition, the lenders may be able to terminate any commitments they had made to supply Harvest with further funds.

Federal, state and provincial statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from guarantors.

Under U.S. or Canadian federal bankruptcy law and comparable provisions of state or provincial fraudulent transfer laws, the guarantees could be voided, or claims in respect of a guarantee could be subordinated to all other debts of a guarantor issuing a guarantee if, among other things, such guarantor, at the time it incurred the indebtedness evidenced by its guarantee:

•: incurred such indebtedness with the intent to hinder, delay or defraud creditors; or
•: received less than reasonably equivalent value or fair consideration for the incurrence of such indebtedness; or
•: was insolvent or rendered insolvent by reason of such incurrence or by reason of making such payment; or
•: was engaged in a business or transaction for which the guarantor's remaining assets constituted unreasonably small capital; or
•: intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

In addition, any payment by such guarantor pursuant to its guarantee could be voided and required to be returned to such guarantor, or to a fund for the benefit of the creditors of such guarantor, including if such payment was made with the intent to, and which had effect to, hinder, delay or defraud creditors.

The measure of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:

•: the sum of its debts, which may include certain contingent liabilities, were greater than the fair saleable value of all of its assets; or
•: the present, fair saleable value of its assets were less than the amount that would be required to pay its probable liabilities on its existing debts, which may include certain contingent liabilities, as they become absolute and mature, or if the guarantor is unable in the ordinary course of business to meet its obligations as they become due.

Based on historical financial information, recent operating history and other factors, Harvest believes that each guarantor of the notes offered hereby, upon completion of this offering, will not be insolvent, will not have unreasonably small capital for the business in which it is engaged and will not have incurred debts beyond its

ability to pay such debts as they mature. There can be no assurance, however, as to what standard a court would apply in making such determinations or that a court would agree with Harvest's conclusion in this regard.

If Harvest experiences a change of control, it may be unable to repurchase the notes as required under the indenture.

If Harvest experiences a change of control, you will have the right to require it, subject to various conditions, to repurchase the notes. Under its senior credit facilities, a change of control is an event of default which would require it to repay all amounts due and outstanding under the senior credit facilities. Harvest might not have sufficient financial resources to repay those borrowings or to pay the purchase price for the notes. Harvest also cannot assure you that after paying those amounts, it will have sufficient funds to meet its obligations under the notes.

Non-U.S. holders of the notes are subject to applicable restrictions on the resale of the notes.

We sold the old notes in reliance on exemptions from applicable Canadian provincial and territorial securities laws and laws of other jurisdictions where the old notes were offered and sold, and therefore the old notes may be transferred and resold only in compliance with the laws of those jurisdictions to the extent applicable to the transaction, the transferor and/or the transferee. Although we registered the new notes under the Securities Act, we did not, and do not intend to, qualify the new notes by prospectus in Canada (other than in the province of Alberta) or any other jurisdiction, and, accordingly, the new notes will be subject to applicable restrictions on resale in Canada (other than in the province of Alberta) and in any other jurisdiction. In addition, non-U.S. holders will remain subject to restrictions imposed by the jurisdiction in which the holder is resident.

Certain persons who participate in the exchange offer must deliver a prospectus in connection with resales of the new notes, which subjects you to potential liability under the Securities Act.

In some instances described in this prospectus under "The Exchange Offer — Resale of the new notes," you will be obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer your new notes. In those cases, if you transfer any new notes without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes under the Securities Act, you may incur liability under the Securities Act. We do not and will not assume, or indemnify you against, this liability.

Absence of public market for the new notes.

No active trading market currently exists for the new notes and an active trading market may not develop in the future. The new notes will not be listed on any stock exchange. If an active trading market does not develop, it could have an adverse effect on the market price of, and your ability to sell, the new notes. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the new notes. The market for the new notes, if any, may be subject to similar disruptions, and other factors, including general economic conditions and our financial condition, performance and prospects. These factors could adversely affect you as a holder of new notes.

USE OF PROCEEDS

Net proceeds of approximately $307 million (assuming the exchange rate of US$1.00=$1.264 as at September 30, 2004, and net of $9 million of issuance costs) from the offering of the Old Notes were used to permanently repay Harvest's bank bridge facility in its entirety of $70 million with the remainder used to repay a portion of the amount outstanding under its revolving credit facility.

We will not receive any cash proceeds from the issuance of the new notes in exchange for the outstanding old notes. We are making this exchange solely to satisfy our obligations under the registration rights agreement entered into in connection with the offering of the old notes. In consideration for issuing the new notes, we will receive old notes in the same aggregate principal amount.

CAPITALIZATION

The following table provides as of September 30, 2004, Harvest's capitalization, both actual and as adjusted, to give effect to the issuance of the old notes, the exchange of the old notes for the new notes and the use of net proceeds from the notes to repay balances outstanding under Harvest Operations' senior credit facility.

You should read this table together with "Description of Other Indebtedness," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Harvest's consolidated historical and pro forma financial statements and the related notes included elsewhere in this prospectus.

	As of December 31, 2003		As of September 30, 2004
	Actual		Actual		As Adjusted
	(Canadian dollars in thousands)
Senior credit facility⁽¹⁾	$	63,349	$	401,556	$	94,556
Old Notes⁽²⁾		—		—		—
New Notes⁽²⁾		—		—		316,000
Convertible subordinated debentures due 2009⁽³⁾⁽⁴⁾		—		91,821		91,821
Equity bridge notes⁽⁴⁾		25,000		10,000		10,000
Other unitholders' equity		104,577		348,802		348,802

Total capitalization	$	192,926	$	852,179	$	861,179

(1): Harvest's revolving credit facility provides for total borrowings of up to $325 million following issuance of the notes. Net proceeds from the issuance of the notes after issuance costs of approximately $9.0 million, were used to repay a portion of amounts outstanding under the senior credit facility. Approximately $245 million is available for borrowing under Harvest's revolving credit facility, after taking into account outstanding letters of credit. Borrowing under the revolving credit facility is limited by a borrowing base which is established periodically by the unanimous determination of the lenders.
(2): The old notes and the new notes offered by this prospectus have been converted to Canadian dollars at an exchange rate of US$1.00 = $1.264 applicable as at September 30, 2004.
(3): Reflects two separate issuances of convertible debentures, including $60 million original principal amount of 9% notes convertible at $14.00 per unit, and $100 million original principal amount of 8% notes convertible at $16.25 per unit, net of convertible debentures that have been converted and costs of issuance. As of September 30, 2004, $24.9 million of 9% debentures and $71.2 million of 8% debentures face value remain outstanding, following conversions up to that date.
(4): The convertible subordinated debentures and the equity bridge notes are classified as unitholders' equity under Canadian GAAP and as debt under U.S. GAAP.

INTEREST COVERAGE

The following interest coverages are calculated on a consolidated basis for the twelve month periods ended December 31, 2003, and September 30, 2004, based on audited financial information in the case of December 31, 2003, and unaudited financial information in the case of September 30, 2004. In accordance with Canadian generally accepted accounting principles, the notes will be included in unitholders' equity and the interest paid on the notes will be charged to accumulated earnings as distributions to unitholders.

The earnings of the Trust before interest and income tax expense for the year ended December 31, 2003 and the twelve-month period ended September 30, 2004 were $12.3 million and $0.6 million, respectively. The pro forma interest expense for the year ended December 31, 2003 and the twelve-month period ended September 30, 2004 was $42.1 million and $39.9 million, respectively, for a ratio of 0.3 and 0.01 times, respectively. These ratios reflect historical earnings, excluding the pro forma impact of the Storm acquisition and the EnCana acquisition, but including the related interest expense on debt associated with these acquisitions. After giving effect to the Storm acquisition, the EnCana acquisition and the note offering, the pro forma earnings of the Trust before interest and income tax expense for the year ended December 31, 2003 and the twelve-month period ended September 30, 2004 would be $137.5 million and $91.6 million, respectively. After giving effect to the equity treatment of the convertible debentures and the equity bridge notes, the pro forma interest expense for the year ended December 31, 2003 and the twelve-month period ended September 30, 2004 were $42.1 million and $39.9 million, respectively, for a ratio of 3.3 and 2.3 times, respectively.

If the convertible debentures and the equity bridge notes were included in long-term debt, the pro forma interest coverage after giving effect to the Storm acquisition, the EnCana acquisition and the note offering would be 3.0 times for the year ended December 31, 2003 and 2.1 times for the twelve-month period ended September 30, 2004, based on a pro forma interest expense of $45.6 million and $43.4 million, respectively.

SELECTED CONSOLIDATED FINANCIAL DATA

The following table provides Harvest's selected financial data for the period from inception (July 10, 2002) to December 31, 2002 and the year ended December 31, 2003 and for the nine-month periods ended September 30, 2003 and 2004. The financial data for the period ended December 31, 2002 as well as the year ended December 31, 2003 have been derived from Harvest's consolidated financial statements for those periods, which were audited by KPMG LLP, independent accountants. The financial data for each of the nine month periods ended September 30, 2003 and 2004 have been derived from Harvest's unaudited consolidated financial statements for those periods. The unaudited consolidated financial statements have been prepared on the same basis as Harvest's audited financial statements except as described in notes to those financial statements. Harvest believes that the unaudited consolidated financial statements contain all adjustments necessary for a fair presentation of the financial information presented (consisting only of normal recurring adjustments). The historical financial data for the interim periods is not necessarily indicative of the results that may be expected for Harvest's full year of operations. The period over period comparisons are impacted by the acquisitions described in "Management's Discussion and Analysis of Financial Condition and Results of Operations." You should read Harvest's consolidated financial statements, unaudited consolidated financial statements, unaudited pro forma consolidated financial statements and the related notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this prospectus.

Harvest's financial statements have been prepared in accordance with Canadian GAAP, which differs in some material respects from U.S. GAAP. For a discussion of the differences between Canadian GAAP and U.S. GAAP as they pertain to Harvest's financial statements, you should read Note 20 to Harvest's consolidated

financial statements included in this prospectus. All dollar amounts are in Canadian dollars unless otherwise stated.

									Nine Months Ended September 30,
			Period from July 10 (date of formation) to December 31, 2002⁽¹⁾			Year Ended December 31, 2003⁽¹⁾			Nine Months Ended September 30,
						Year Ended December 31, 2003⁽¹⁾			2003⁽¹⁾			2004
			(dollars in thousands)
Statement of Income Data:
Revenue:
	Oil and natural gas sales		$	22,709		$	119,351		$	79,407		$	202,681
	Royalty expense, net			(2,745	)		(16,412	)		(10,045	)		(33,031	)
	Hedging loss			(1,009	)		(18,924	)		(15,821	)		(37,761	)
	Mark to market loss on commodity derivative contracts			—			—			—			(29,396	)

				18,955			84,015			53,541			102,493
Expense:
	Operating			6,396			36,045			23,061			46,267
	General and administrative			577			4,340			2,087			6,049
	Interest			2,010			2,975			1,807			3,919
	Finance charges and amortization of deferred finance charges			636			2,607			1,579			1,845
	Depletion, depreciation and accretion			6,192			35,727			24,275			53,002
	Foreign exchange gain			(255	)		(4,374	)		(5,313	)		(565	)

		Total expenses		15,556			77,320			47,496			110,517

Income (loss) before taxes				3,399			6,695			6,045			(8,024	)
Taxes:
	Large corporation tax			47			157			138			256
	Future tax recovery			(1,480	)		(8,978	)		(3,906	)		(13,976	)

Net income			$	4,832		$	15,516		$	9,813		$	5,696

Balance Sheet Data (at end of period):
Cash and short term investments			$	4,503		$	—		$	17,404		$	—
Non-cash working capital (deficiency)⁽²⁾				6,220			9,794			681			(25,149	)
Total assets				108,447			256,440			168,167			1,070,016
Bank debt				45,286			63,349			27,825			401,556
Total debt				45,286			63,349			27,825			401,556
Adjusted total debt⁽³⁾				45,286			88,349			61,325			507,690
Unitholders' equity				39,703			129,577			92,897			450,623
Other Financial Data:
Adjusted EBITDA⁽⁴⁾			$	11,982		$	43,630		$	28,263		$	79,573
Adjusted interest expense⁽⁵⁾				2,010			3,845			2,012			9,535
Capital expenditures				76,923			117,758			34,012			547,637

(1): Restated to reflect the adoption of the CICA Handbook standard for accounting for asset retirement obligations. See note 4 to Harvest's consolidated financial statements.
(2): Excludes current portion of debt.
(3): Adjusted total debt includes the full principal amount of the convertible subordinated debentures and the equity bridge, which under Canadian GAAP are classified as unitholders' equity.
(4): Adjusted EBITDA is the sum of net income before interest, taxes, depletion, depreciation and accretion expense, finance charges and amortization of deferred finance charges, foreign exchange gain and mark to market loss on commodity derivative contracts. Adjusted

EBITDA is presented because management believes that it is a useful indicator of Harvest's ability to service indebtedness. However, adjusted EBITDA does not represent net income or cash flow from operations as defined by generally accepted accounting principles, is not necessarily indicative of cash available to fund all cash flow needs, should not be considered as an alternative to net income or to cash flow from operating activities (as determined in accordance with Canadian GAAP) and should not be construed as an indication of a company's operating performance or as a measure of liquidity. The adjusted EBITDA of Harvest is not necessarily comparable with similarly-titled measures presented by other companies.

The following table reconciles adjusted EBITDA to net income:

							Nine Months Ended September 30,
	Period from July 10 (date of formation) to December 31, 2002⁽¹⁾			Year Ended December 31, 2003⁽¹⁾			Nine Months Ended September 30,
				Year Ended December 31, 2003⁽¹⁾			2003⁽¹⁾			2004
	(dollars in thousands)
Reconciliation of net income to adjusted EBITDA:
Net income	$	4,832		$	15,516		$	9,813		$	5,696
Add (deduct):
Interest		2,010			2,975			1,807			3,919
Finance changes and amortization of deferred finance charges		636			2,607			1,579			1,845
Depletion, depreciation and accretion		6,192			35,727			24,275			53,002
Current income tax		—			—			—
Large corporation tax		47			157			138			256
Future tax recovery		(1,480	)		(8,978	)		(3,906	)		(13,976	)

EBITDA		12,237			48,004			33,576			50,422
Foreign exchange gain		(255	)		(4,374	)		(5,313	)		(565	)
Mark to market loss on commodity derivative contracts		—			—			—			29,396

Adjusted EBITDA	$	11,982		$	43,630		$	28,263		$	79,573

(5): Adjusted interest expense includes the interest associated with the equity bridge and the convertible subordinated debentures, which under Canadian GAAP are classified as unitholders' equity.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following management's discussion and analysis of Harvest's financial condition and results of operations along with Harvest's audited and unaudited financial statements and the related notes appearing elsewhere in this prospectus.

Overview

Harvest is a Canadian oil and natural gas producer focused on extracting value from high quality, mature properties by employing state of the art technology and operational practices. Harvest uses technology and selective capital investment to maximize production rates while enhancing operational efficiencies to control and reduce expenses. Harvest also utilizes hedging techniques to manage cash flow. Harvest is an oil and natural gas royalty trust, and has operations in four core areas: East Central Alberta, Southern Alberta, North Central Alberta and Southeast Saskatchewan.

Industry Overview

	Year Ended December 31,			Nine Months Ended September 30,
Prices	Year Ended December 31,		% Change	Nine Months Ended September 30,		% Change
Prices	2002	2003	% Change	2003	2004	% Change
West Texas intermediate crude oil (US$ per barrel)	26.15	30.99	18.5%	30.99	39.11	26%
Edmonton light crude ($ per barrel)	40.41	43.77	8.3%	44.33	50.83	15%
Lloyd blend crude oil ($ per barrel)	30.73	31.48	2.4%	32.90	36.74	12%
Bow River blend crude oil ($ per barrel)	31.77	32.39	2.0%	33.80	37.70	12%
AECO natural gas ($ per mcf)	4.09	6.67	63.1%	6.70	6.29	-6%
Alberta Power Pool electricity price ($ per MWh)	43.93	62.99	43.4%	67.75	54.43	-20%
Canadian$/US$ exchange rate	1.570	1.403	11.0%	1.429	1.328	8%
Bank of Canada bank rate	2.70%	3.19%	18.2%	3.25%	2.44%	-25%

The benchmark price of WTI crude oil impacts Harvest's revenues, because the Trust's primary product is crude oil. Foreign exchange also has an impact on Harvest's revenues because it affects the realized revenues in Canadian dollars for products denominated in U.S. dollars. Although Harvest's natural gas weighting is relatively low, fluctuations in AECO natural gas spot prices also impact the Trust's revenues. This impact is expected to increase as a result of the acquisition of the EnCana assets, because Harvest's natural gas production weighting has increased to 13% from 2%.

Although the price of WTI in U.S. dollars has increased significantly period on period, crude prices in Canadian dollar terms did not keep pace as a result of the strengthening of the Canadian versus the U.S. dollar and slightly wider differentials for Canadian crude. The overall average increase in WTI of approximately 45% in the 3rd quarter of 2004 over the same period in 2003 was slightly offset by the 5% increase in the value of the Canadian dollar relative to the U.S. dollar. Edmonton light (posted price for light oil delivered to Edmonton) rose 38% during the third quarter of 2004 relative to the same period of 2003.

The differential between heavy and light crude oil widened slightly in Canadian dollar terms as the lighter crudes were afforded a premium due to their proportionately higher gasoline yield, the cost of upgrading heavier gravity crude and in response to higher WTI prices.

Harvest has been mostly exposed to swings in world oil prices (WTI) and light to medium/heavy differentials given the fact that, in the past, 97% of production was medium and heavy crude oil. In the third quarter of 2004, light oil made up 37% of total production. Exit production for the third quarter of 2004 was 50% light and medium gravity crude oil, 35% heavy oil and 15% natural gas and NGL's. This compares to 44% light and medium gravity crude, 53% heavy crude and 3% natural gas and NGL's in the third quarter of 2003. This diversification reduces Harvest's exposure to WTI prices and heavy oil differentials and increases our exposure to North American natural gas prices.

The average Alberta Electricity System Operator (AESO) electricity price decreased in the third quarter of 2004 by approximately 13% over the same period in 2003. Events during the month of July 2003 versus 2004 were the leading factors in the decrease. In 2003, July brought high temperatures and many days with multiple large generators off-line putting extreme strain on the province's ability to supply power leading to an average electricity spot market price of $87.91/MWh. By comparison, July 2004 had milder temperatures and more generation capacity resulting in an average electricity spot market price of $56.55/MWh. Demand growth in the third quarter continued at its 2004 pace of approximately 4% over 2003. Third quarter 2004 natural gas prices increased by 3% compared to 2003; however, this increase was not reflected in higher prices due to higher availability of coal fired generators.

Acquisitions

During April and May 2003 Harvest closed the acquisition of various interests in two properties in the Killarney area of Alberta. On the acquisition date the properties were producing approximately 925 boe/d. The properties, including an interest in two oil batteries, were acquired from two major oil and natural gas producers for $13.2 million and the issuance of 200,000 trust units. The cash consideration was financed through Harvest's senior credit facilities.

On June 27, 2003, Harvest completed the acquisition of all of the common shares and Net Profit Interest ("NPI") of a private company in exchange for total consideration of approximately $10.1 million (consisting of the issuance of 625,000 trust units, $3 million in cash and a $850,000 unsecured promissory note) plus the assumption of $2.8 million in bank debt and $2.5 million in working capital deficit. The oil and natural gas producing properties acquired provided production of approximately 1,350 boe/d at the acquisition date and include working interests ranging from 20% to 100% in the fields of Amisk, Czar and Killarney, all of which are operated by Harvest.

On October 16, 2003, Harvest closed the acquisition of oil and natural gas properties producing about 5,100 boe/d in the Carlyle region of southeastern Saskatchewan. The total consideration for the properties was approximately $79.5 million, prior to adjustments and transaction costs.

On June 30, 2004, Harvest acquired Storm for approximately $189 million, including assumed net debt of approximately $65 million. Harvest paid approximately $75 million in cash and issued approximately $40 million of trust units and approximately $9 million of exchangeable shares of Harvest Operations to former shareholders of Storm. The Storm properties acquired produced approximately 4,060 boe/d during the six months ended June 30, 2004 and are primarily concentrated in the Redearth area of north central Alberta. These properties added high quality light oil to Harvest's product mix, providing diversification benefits, along with low operating costs.

On September 2, 2004, Harvest acquired Breeze Resources Partnership, which held the EnCana assets, for the purchase price of approximately $526 million, subject to adjustment. Harvest financed this acquisition through the issuance of $175 million of trust units and $100 million aggregate principal amount of convertible subordinated debentures, and borrowings of approximately $195 million under the revolving credit facility and $70 million under the bank bridge facility. The EnCana assets produced approximately 20,481 boe/d for the six months ended June 30, 2004 and are primarily concentrated in the Crossfield area of Alberta, southern Alberta and east central Alberta. The Crossfield and southeast Alberta properties comprise Harvest's new Southern Alberta core area, and the east central Alberta properties supplemented Harvest's existing properties in that core area. The acquisition of the EnCana assets added Harvest's first significant natural gas production.

The acquisition of Storm and the EnCana assets has increased production to approximately 37,500 boe/d as at September 30, 2004 from the average production level of 18,317 boe/d for the nine months ended September 30, 2004. Natural gas, as a percentage of total production, has increased to approximately 13% from approximately 2%. These acquisitions have provided a diversification of properties and commodities, and as of July 1, 2004, on a pro forma basis, increased Harvest's proved reserve life to 5.8 years and total reserves to 77.1 mmboe.

Production related to the Storm assets was reflected beginning in the third quarter, and production from the EnCana assets was reflected from September 2, 2004, the date of closing of that acquisition.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

Sales Volumes

Harvest's production as of September 30, 2004 consists of light, medium and heavy crude oil, natural gas liquids, and natural gas from properties located in North Central, East Central and Southern Alberta and Southeastern Saskatchewan. Sales volumes, on a barrel of oil equivalent (boe) basis, averaged 18,317 boe/d for the nine months ended September 30, 2004, in comparison to 9,754 boe/d for the similar period ended September 30, 2003. Compared to the third quarter of 2003, the higher average production in the third quarter of 2004 reflects the impact of acquisitions completed during the balance of 2003 and in 2004, as well as the ongoing optimization and development programs conducted by Harvest on its oil and natural gas properties.

The average daily sales volumes by product were as follows:

	Nine Months Ended September 30, 2003		Nine Months Ended September 30, 2004
Light crude oil (Bbls/d)	—	0%	6,461	35%
Medium crude oil (Bbls/d)	4,300	44%	4,553	25%
Heavy crude oil (Bbls/d)	5,192	53%	6,271	34%

Total oil (Bbls/d)	9,492	97%	17,285	94%
Natural gas liquids (Bbls/d)	68	1%	190	1%

Total oil and natural gas liquids (Bbls/d)	9,560	98%	17,475	95%
Natural gas (mcf/d)	1,165	2%	5,049	5%

Total (boe/d)	9,754	100%	18,317	100%

Harvest's September 30, 2004 exit rate was approximately 37,500 boe/d, a 223% increase over the exit rate of 11,600 boe/d for the period ended September 30, 2003. The exit rate was also 95% higher than the 19,200 boe/d exit rate as at June 30, 2004. The increases can primarily be attributed to the production acquired in the Storm, EnCana and Carlyle acquisitions noted above.

Revenues

For the first nine months of 2004, revenues net of hedging losses and before royalties increased 159% to $164.9 million, compared to $63.6 million recorded for the same period in 2003. Higher net revenues in the nine months ended September 30, 2004 are as a result of Harvest's higher production volumes as well as higher average commodity prices in 2004 compared to 2003. For the nine months ended September 30, 2004, Harvest's average sales price was $40.53/boe, compared to $29.82/boe for the same period in the previous year.

The following is a breakdown of average market prices by product for the nine months ended September 30, 2004 and 2003.

		Nine Months Ended September 30, 2003	Nine Months Ended September 30, 2004
Product prices:
	Light oil ($/bbl)	—	46.52
	Medium oil ($/bbl)	32.05	39.89
	Heavy oil ($/bbl)	27.80	35.67
	Natural gas liquids ($/bbl)	29.93	37.37
	Natural gas ($/mcf)	6.71	5.83
	Combined average ($/boe)	29.82	40.53

Operating Netbacks

Operating netbacks are an indicator of the amount of cash flow per boe that Harvest realizes before head office expenses, interest expenses and taxes. The following is a summary of Harvest's operating netbacks:

	Nine Months Ended September 30, 2003		Nine Months Ended September 30, 2004
	(amounts expressed are $/boe)
Sales price	$	29.82	$	40.53
Hedging loss		5.94		7.52

Realized price		23.88		33.01
Royalties, net		3.77		6.58
Operating costs		8.66		9.22

Operating netback	$	11.45	$	17.21

Operating netbacks were 50% higher in the nine months ended September 30, 2004 compared to 2003. The increase in netbacks is primarily attributable to higher sales and realized prices slightly offset by higher royalties and operating costs per boe, which are addressed below.

Royalties

For the nine months ended September 30, 2004, Harvest's net royalties were $33.0 million ($6.58/boe), an increase of 230% compared to $10.0 million ($3.77/boe) for the same period in 2003. Higher net royalties in 2004 compared to 2003 is due to the change in Harvest's royalty structure as the result of the addition of the higher royalty burdened Carlyle and Storm properties as well as higher commodity prices. Royalty expense as a percentage of revenues before hedging increased from 12.6% to 16.2% in the nine months ended September 30, 2004 compared to the same period the previous year. Royalties as a percentage of revenues are expected to decline in future quarters due to lower royalty rates for the EnCana assets.

Operating Expenses

Harvest's operating expenses were $46.3 million ($9.22/boe) for the nine months ended September 30, 2004. This compares to $23.1 million ($8.66/boe) for the same period in 2003. The increase in unit operating expenses during the nine months ended September 30, 2004 compared to the comparable period in 2003 reflects the higher per unit operating costs associated with the Carlyle properties acquired in the fourth quarter of 2003.

During the third quarter of 2004, approximately 35% of Harvest's operating costs related to the consumption of electricity. Management has utilized fixed price electricity contracts to mitigate electricity price risk within Alberta. For the balance of the year, Harvest anticipates realizing further benefits from its electricity hedges (with approximately 29 MWh of its estimated Alberta electricity usage hedged at an average price of $45.25 per MWh) and capital expenditures of approximately $4.9 million in 2004 being dedicated to power efficiency projects. The increased exposure to natural gas production associated with the EnCana assets will provide a natural hedge to electricity prices and power costs.

Harvest's third quarter 2004 operating costs were $8.34/boe. Further efficiencies realized from the Harvest capital program coupled with lower cost production volumes from the Storm and EnCana asset purchases are expected to reduce the overall 2004 average unit operating expenses.

General and Administration Expenses

The portion of general and administrative expenditures charged against income totaled $6.0 million ($1.21/boe) for the nine months ended September 30, 2004. This compares to $2.1 million ($0.78/boe) for the same period in 2003. The increase in general and administrative expenses on a per boe basis, period over period, is the result of a build-up of staff and systems required to operate a growing enterprise, and approximately $0.4 million related to unit appreciation right expenses as the result of adopting the new Canadian GAAP

requirements relating to stock based compensation. Harvest's general and administrative expenses charged against income are expected to decrease due to anticipated economies of scale following the acquisition of Storm and the EnCana assets.

During the nine months ended September 30, 2004, $1.8 million of general and administrative costs were capitalized with regards to field enhancement and acquisition activities; $0.7 million of such costs were capitalized for the same period in 2003.

Interest Expense and Finance Charges and Amortization of Deferred Financing Charges

For the nine month periods ended September 30, 2004 and 2003, interest expense and amortization of deferred financing charges were $5.8 million and $3.4 million, respectively. The increase in the third quarter of 2004 is due to interest costs associated with bank debt used to partially finance the Storm and EnCana acquisitions. Interest expense will increase further in the fourth quarter due to a full three months of costs associated with EnCana related debt and also the higher interest rate associated with the senior notes issued in October to repay outstanding bank debt.

Depletion, Depreciation and Accretion

Harvest's depletion, depreciation and accretion expense totaled $53.0 million for the nine months ended September 30, 2004. This compares to the depletion, depreciation and accretion expense total of $24.3 million for the same period in 2003.

For the nine months ended September 30, 2004, the total depletion, depreciation and accretion expense primarily consists of: crude oil and natural gas properties depletion and depreciation of $44.1 million; depletion of capitalized asset retirement costs of $6.0 million; and approximately $2.9 million for accretion on the asset retirement obligation. The depletion rate for oil and natural gas properties was approximately $8.76/boe for the nine months ended September 30, 2004, and is based on the costs of the oil and natural gas properties purchased, capital expenditures incurred, capitalization of general and administrative expenses and the long-lived asset retirement costs. For the nine months ended September 30, 2004, Harvest's depletion rate is higher compared to the same period in 2003. This increase in the depletion rate in 2004 is attributable to the Storm properties acquired in the second quarter of 2004, the purchase price for which reflected both the higher value netback for those properties, as well as an increased cost for accounting purposes arising from the future income tax liability associated with that acquisition.

For the nine months ended September 30, 2003, the total depletion, depreciation and accretion expense primarily consists of: crude oil and natural gas properties depletion and depreciation of $20.1 million; depletion of capitalized asset retirement costs of $1.8 million; and approximately $1.2 million for accretion on the asset retirement obligation. The depletion rate for oil and natural gas properties was approximately $7.58/boe.

Future taxes

Future taxes for the nine months ended September 30, 2004 and 2003 are comprised of approximately $14 million and $3.9 million in recoveries, respectively.

The estimated value of the tax pools associated with the acquisition of Storm is less than the book value of the net assets acquired, resulting in a future tax liability of $19.1 million on Harvest's balance sheet.

Year Ended December 31, 2003 Compared to Period Ended December 31, 2002

Sales Volumes

Sales volumes, on a barrel of oil equivalent, averaged 11,040 boe/d, in comparison to 4,307 boe/d for the year ended December 31, 2003, and the period ended December 31, 2002, respectively. In the fourth quarter of

2003, average crude oil and natural gas sales were 14,858 boe/d with the increase primarily due to acquisition of the properties in Saskatchewan in mid October. The average daily sales volumes by product were as follows:

	Period Ended December 31, 2002		Year Ended December 31, 2003
Light and medium crude oil (Bbls/d)	2,718	63%	5,314	48%
Heavy crude oil (Bbls/d)	1,463	34%	5,444	49%

Total oil (Bbls/d)	4,181	97%	10,758	97%
Natural gas liquids (Bbls/d)	22	1%	64	1%

Total oil and natural gas liquids (Bbls/d)	4,203	98%	10,822	98%
Natural gas (mcf/d)	624	2%	1,311	2%

Total (boe/d)	4,307	100%	11,040	100%

Harvest exited December 31, 2003 with a daily production rate of approximately 15,400 boe/d, a 79% increase year over year, which reflects the impact of the ongoing development and optimization activities, and acquisitions throughout the year. In comparison, the exit rate for the period ended December 31, 2002 was approximately 8,600 boe/d.

Revenues

Revenues net of hedging loss and before royalties totaled $100.4 million in 2003 and $21.7 million in 2002, which was the result of average market prices of $29.62 and $30.13 per barrel of oil equivalent for the year ended December 31, 2003 and period ended December 31, 2002 respectively.

		Period Ended December 31, 2002	Year Ended December 31, 2003
Product prices:
	Light oil ($/bbl)	—	35.56
	Medium oil ($/bbl)	34.21	32.18
	Heavy oil ($/bbl)	22.63	27.34
	Natural gas liquids ($/bbl)	37.64	29.92
	Natural gas ($/mcf)	4.54	6.70

	Combined average ($/boe)	30.13	29.62

Operating Netbacks

The following is a summary of Harvest's operating netbacks:

	Period Ended December 31, 2002		Year Ended December 31, 2003
	(amounts expressed are $/boe)
Market price	$	30.13	$	29.62
Hedging loss		1.34		4.67

Realized price		28.79		24.95
Royalties net		3.64		4.07
Operating costs		8.49		8.94

Operating netback	$	16.66	$	11.94

Royalties

Harvest paid net royalties of $16.4 million and $2.8 million during the year ended December 31, 2003 and the period ended December 31, 2002, or approximately $4.07/boe and $3.64/boe, respectively. The net royalty amount for the year ended December 31, 2003 is comprised of $11.1 million in freehold royalties and freehold

mineral tax, $5.2 million in crown royalties and $0.8 million in gross overriding royalties net of $0.7 million in royalty income received. In comparison, the net royalty amount for the period ended December 31, 2002 was comprised of $1.5 million in freehold royalties and freehold mineral tax, $1.2 million in crown royalties and $0.2 million in gross overriding royalties net of $0.1 million in royalty income received.

Operating Expenses

Harvest's operating expenses were $36.0 million and $6.4 million or approximately $8.94 and $8.49/boe for the year and period ended December 31, 2003 and 2002, respectively. Substantially all of the entity's properties are operated by Harvest. Approximately 60% of Harvest's operating costs are in respect of electricity. Management has utilized fixed price delivery contracts to mitigate electricity price risk within Alberta.

General and Administration Expenses

The portion of general and administrative expenditures charged against income totaled $4.3 million or $1.08/boe for the year ended December 31, 2003, in comparison to $0.6 million or $0.77/boe for the period ended December 31, 2002. During the year and period ended December 31, 2003 and December 31, 2002, $1.3 million and $0.2 million, respectively, of general and administrative costs were capitalized with regards to field enhancement and acquisition activities.

Interest Expense and Finance Charges and Amortization of Deferred Financing Charges

Interest expense and deferred financing charges amounted to $5.6 million and $2.6 million for the year and period ended December 31, 2003 and 2002, respectively. The amortization of deferred financing charges associated with fees to secure bank lending facilities amounted to $2.6 million and $0.2 million for the year and period ended December 31, 2003 and 2002, respectively.

Depletion, Depreciation and Accretion

Harvest's depletion, depreciation, and accretion totaled $35.7 million and $6.2 million for the year and period ended December 31, 2003 and 2002, respectively. This balance is comprised of crude oil and natural gas properties depletion and depreciation of $29.2 million and $5.1 million, approximately $0.1 million and $23,000 for depreciation of office furniture and equipment, and $6.4 million and $1.1 million for accretion for the year and period ended December 31, 2003 and 2002, respectively. The depletion rate for oil and natural gas properties was approximately $7.29 and $6.77 per boe for the year and period ended December 31, 2003 and 2002 respectively, and is based on the costs of the oil and natural gas properties purchased, capital expenditures incurred and capitalization of general and administrative expenses. The depreciation of office furniture and equipment and leasehold improvement costs has been calculated on a straight-line basis ranging from 20% to 50%.

Income taxes

Income taxes for the year and period ended December 31, 2003 and 2002 are comprised of approximately $0.2 million and $0.1 million in large corporation tax and $9.0 million and $1.5 million recoveries of future income tax expense, respectively.

Liquidity and Capital Resources

Harvest's capital investment and operational enhancement programs, as well as current financial commitments are expected to be supported by cash flow from operations net of distributions, senior credit facilities and unitholder reinvestment of distributions through the distribution reinvestment plan.

For the nine months ended September 30, 2004, Harvest's cash flow from operations was $78.0 million and net income was $5.7 million. For the same period in 2003, cash flow from operations was $32.8 million and net income was $9.8 million. This increase in cash flow from operations is primarily due to increased production arising from the Carlyle, Storm and EnCana acquisitions.

Harvest's cash flow from operations and net income for the year ended December 31, 2003 was $46.5 million and $15.5 million, in comparison to $9.5 million and $4.8 million respectively, for the period ended December 31, 2002. While the strengthening Canadian dollar reduced the cash flow from the sales of oil and natural gas, the impact was partially offset through the gains realized when the U.S. denominated debt was repaid in the third quarter of 2003.

Harvest's net debt (including working capital deficiency but excluding the current portion of commodity derivative contract liabilities) at September 30, 2004 was $403.4 million, which is an increase of $349.8 million in comparison to net debt of $53.6 million as at December 31, 2003. The increase is primarily the result of the plan of arrangement with Storm and the $526 million acquisition of properties from Storm.

Harvest's net debt (working capital plus demand loan) at December 31, 2003 was $53.6 million, which is an increase of $19.0 million in comparison to net debt of $34.6 million as at December 31, 2002. This increase is the result of property and corporate acquisitions throughout the year, which were partially financed with bank debt. On September 30, 2003, Harvest changed its debt structure by extinguishing a demand loan denominated in U.S. dollars, and replacing it with equity bridge financing and a credit agreement with a syndicate of Canadian financial institutions. This series of transactions lowered the overall effective interest rate on Harvest's demand loan, and consolidated the financing requirements of counterparty collateral including a portion of the hedging activity. At the date of this prospectus, Harvest's secured credit facility with a syndicate of lenders had a borrowing base of $325 million and Harvest has currently drawn (exclusive of letters of credit) approximately $75 million under this facility.

During the nine months ended September 30, 2004, Harvest declared $39.7 million in distributions payable to unitholders; $0.20 per trust unit for each month for January through September 2004. Of the distributions paid, $7.1 million was reinvested into Harvest by unitholders through the issue of 483,458 trust units under the distribution reinvestment plan. This reflects 17.9% participation. Harvest will continue to declare its distributions monthly, consistent with the preceding 24 months. The distributions will continue to be financed with cash flow from operations. Harvest anticipates its payout ratio, which is the ratio of distributions to cash flow from operations, to decline to approximately 40% after the acquisition of the EnCana assets. This low payout ratio is expected to provide Harvest significant flexibility in servicing its outstanding debt and financing capital and acquisition activities.

Capital Expenditures

Capital expenditures, excluding the acquisition of Storm and the acquisition of the EnCana properties, totaled $33.8 million for the nine months ended September 30, 2004. The capital expenditures were dedicated to ongoing optimization and development of existing assets. This compares to $34.0 million for the nine months ending September 30, 2003. Total consideration for the acquisition of Storm and the EnCana properties were approximately $189 million and $526 million respectively, bringing Harvest's total capital expenditures in the nine months ended September 30, 2004 to $748.8 million, including acquisitions.

Capital expenditures totaled $135.3 million for the year ended December 31, 2003, in comparison to $76.9 million for the period ended December 31, 2002. Of these expenditures, acquisitions of oil and natural gas producing properties in eastern Alberta accounted for approximately $29.2 million, which complemented Harvest's current operations and production in this area. Additionally, Harvest purchased oil and natural gas properties in the Carlyle area located in southeastern Saskatchewan for approximately $79.5 million.

The following table itemizes the balance of non-acquisition capital expenditures during the periods:

	Period Ended December 31, 2002		Year Ended December 31, 2003
	(dollars in thousands)
Land and undeveloped lease rentals	$	—	$	78
Geological and geophysical		156		182
Drilling and completion		37		10,095
Well equipment, pipelines & facilities		167		14,521
Capitalized general and administrative expenses		174		1,311
Furniture, leaseholds & office equipment		236		436
Acquisitions		76,153		108,677

Total capital expenditures	$	76,923	$	135,300

Excluding acquisitions, Harvest continues to expect full year 2004 capital expenditures of approximately $50 million, and will be focused on production, reserve additions, and operating efficiency programs. Harvest continues to review capital for the fourth quarter and may reallocate funds to properties acquired in the EnCana acquisition, but does not anticipate a material increase to this figure.

Future Liquidity Requirements

From time to time Harvest may require external financing, through both debt and equity, to maintain its business plan of growing through acquisitions and capital expenditures. Harvest's ability to obtain the necessary financing is subject to external factors including, but not limited to, fluctuations in equity and commodity markets, economic downturns and interest and foreign exchange rates. Adverse changes in these factors could require Harvest's management to alter Harvest's current business plan.

In the past, Harvest has been able to utilize equity to carry out its business plan. Harvest's financial flexibility has been enhanced by an issue of $60 million convertible debentures bearing interest at 9% issued in January 2004 and an issue of $100 million convertible debentures bearing interest at 8% issued in August 2004. Access to lower cost capital improves Harvest's ability to compete and cost effectively carry out its business plan.

Harvest has available borrowings of approximately $245 million under its revolving credit facility after taking into account outstanding letters of credit. Borrowing under the revolving credit facility is limited by a borrowing base which is established periodically by the unanimous determination of Harvest's lenders. Depending upon market conditions, Harvest will consider additional financings in the form of convertible debentures or trust units to fund future capital requirements or to finance additional acquisitions. In addition, Harvest currently has access to and may also utilize its equity bridge under which it has available borrowings of $40 million.

Contractual Obligations

Harvest has entered into the following contractual obligations:

	Maturity
	Less than 1 Year	Years 1 - 3	Years 4 - 5	After 5 Years
	(dollars in thousands)
Annual Contractual Obligations
Product transportation agreements	35	39	25	—
Operating and premises leases	325	755	755	—

At present, Harvest has approximately $5.0 million in letters of credit outstanding under the senior credit facility.

As at September 30, 2004 Harvest has entered into physical and financial contracts for production with average deliveries of approximately 10,575 barrels per day for the balance of 2004 and 6,033 barrels per day in 2005. Harvest has also entered into financial contracts to minimize its exposure to fluctuating electricity prices and the U.S./Canadian dollar exchange rate. Please see Note 15 to the consolidated financial statements for further details.

Harvest has entered into a number of insignificant contractual obligations under operating leases and normal course oil and natural gas business relationships. All of these agreements are cancelable on a month to month basis, and do not require additional payment upon defeasance.

Off-Balance Sheet Arrangements

Harvest has a number of immaterial operating leases in place on moveable field equipment and vehicles. The leases require periodic lease payments and are recorded as operating costs. Harvest also finances its annual insurance requirements, whereby a portion of the annual premium is deferred and paid monthly over the balance of the term.

Critical Accounting Policies

Harvest's management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities when applying Canadian generally accepted accounting principles. Certain accounting policies have been deemed critical by management in the preparation of Harvest's financial results. The following is a discussion of the accounting policies that are deemed critical by management in the preparation of the financial results of Harvest.

Oil and Gas Accounting

Harvest follows the Canadian Institute of Chartered Accountants (CICA) guideline for the full cost method of accounting for the oil and natural gas industry. All costs of acquiring oil and natural gas properties and related exploration and development costs, including overhead charges directly related to these activities, are capitalized and accumulated in one cost center. The maintenance and repairs are charged against income, and renewals and enhancements that extend the economic life of the capital assets are capitalized. Any gains or 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. The provision for depletion and depreciation of petroleum and natural gas assets is calculated on the unit-of-production method, based on proved reserves before royalties as estimated by independent petroleum engineers. The basis used for the calculation of the provision is the capitalized costs of petroleum and natural gas assets plus the estimated future 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 reserve estimates used in these calculations can have a significant impact on the net income, and any downward revision in this estimate could result in a higher depletion and depreciation expense. In addition, a downward revision of this reserve estimate could require an additional charge to income as a result of the computation of the prescribed ceiling test calculation under this guideline.

Site Restoration and Reclamation Provision

Harvest provides for the cost of future site restoration and reclamation based on estimates by management using the unit-of-production method and associated reserve estimates. Management estimates the expected future costs to abandon and environmentally restore a well or battery site under specific environmental legislation. These estimates are characteristically difficult to assess due to their expected timing and associated costs at that future date. Due to this estimation, any upward revision of these expected costs or revisions in timing could adversely affect the provision being charged to income.

Trust Unit Incentive Plan

Harvest has established a trust unit incentive plan whereby it is authorized to grant non-transferable rights to purchase trust units to directors, officers, employees, consultants and other service personnel. The initial exercise price of rights granted under the plan is equal to the closing market price on the date immediately prior

to the date the rights are granted and the maximum term of each right is not to exceed five years. The exercise price of the rights is adjusted downwards from time to time based upon the cash distributions made on the trust units subject to a specific return as outlined in the Trust Unit Rights Incentive Plan. Under Canadian GAAP Harvest records a compensation expense based on the binomial model for valuing options. The binomial model has been utilized by Harvest as it allows for the calculation of the fair value of a trust unit right with a decreasing exercise price, based on the distributions paid from the date of issue to date of exercise. Management is required to make certain assumptions and estimates when applying the binomial model. Further details regarding Harvest's trust unit rights incentive plan and assumptions and estimates used are included in the Note 12 of the consolidated financial statements.

Changes in Accounting Policies

Trust Unit Incentive Plan

Harvest has elected to prospectively adopt the amendments to CICA Handbook section 3870 "Stock-based Compensation and Other Stock-based payments." Under this section, Harvest has chosen to recognize compensation expense when trust unit rights are granted under the trust unit incentive plan on a prospective basis. As such, compensation expense has been calculated on all trust unit rights issued on or subsequent to January 1, 2003. The fair value of trust unit rights issued has been determined using a binomial option pricing model.

Changes in Accounting Standards

Asset Retirement Obligation

The CICA has issued a new Handbook section 3110 "Accounting for Asset Retirement Obligation" which requires that entities recognize the liability associated with the fair value of future site reclamation and abandonment costs in the financial statements at the time when the liability is incurred. Harvest has adopted this standard commencing January 1, 2004.

Full Cost Accounting Guideline

In September 2003 the CICA issued Accounting Guideline 16 "Oil and Gas Accounting Full Cost." The guideline replaces Accounting Guideline 5 "Full Cost Accounting in the Oil and Gas Industry" and is effective for fiscal years beginning on or after January 1, 2004, with earlier adoption encouraged. Under the new guideline the definition for proved and probable reserves has been changed to synthesize with the new reserve definitions under the recently issued National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" issued by the Canadian Securities Administrators. These changes include modifications to the ceiling test calculation, additional disclosure within the notes to the financial statements and changes in accounting for disposals of properties other than by sale. Harvest has adopted this standard commencing January 1, 2004.

Hedging

In December 2001 the CICA issued Accounting Guideline 13 "Hedging Relationships" that provides guidance on the identification, designation, documentation and measurement of the effectiveness of hedging relationships for the purposes of applying hedge accounting. This guideline is effective for fiscal years beginning on or after July 1, 2003. Harvest has implemented the requirements of this guideline in 2003.

Financial Instruments

In 2004, the CICA issued new guidance related to accounting for debt instruments with equity features. Beginning in 2005, such instruments must be reflected as debt on the balance sheet and related interest payments reflected as interest expense on the income statement. This will change the presentation of Harvest's convertible debentures and equity bridge notes which had previously been reflected as equity on the balance sheet with interest payments included in accumulated income.

Risk Management Activities

Under Harvest's risk management policy, management enters into crude oil based financial and physical contracts to mitigate the risk of price volatility for its expected production. Management also enters into electricity price based swaps to assist in maintaining stable operating costs. Finally, as a further means to manage revenue risks, management has entered into foreign exchange contracts to minimize the effect of adverse foreign exchange fluctuations of the Canadian dollar against the U.S. dollar.

As at September 30, 2004, Harvest Operations Corp. had entered into physical and financial contracts for production with average deliveries of approximately 10,575 bbls/d for the balance of 2004, 16,033 bbls/d in 2005 and 3,750 bbls/d in 2006. Harvest has also entered into financial swap and collared contracts for WTI crude oil, LLB differential, U.S./Canadian dollar exchange rate, electricity and natural gas heat rate. Collectively these contracts had a mark to market unrealized loss of $47.1 million as at September 30, 2004. Please refer to Note 15 in the consolidated financial statements for further information.

The following table summarizes the risk management activities undertaken by Harvest, the volumes hedged and the associated unrecognized mark to market gains and losses as at September 30, 2004:

	Maturity
	2004	2005	2006
Volumes Hedged
West Texas intermediate crude oil price based swaps (bbls/d)	3,825	1,033	—
West Texas intermediate crude oil price based collars (bbls/d)	5,500	4,000	—
West Texas intermediate crude oil price based floors (bbls/d)	1,250	11,000	3,750
Lloyd blend crude oil price based swaps (bbls/d)	4,500	—	—
Alberta electricity price based swaps (MW)	25	25	30
Electricity heat rate (GJ/MWh)	—	5	—
Canadian/U.S. dollar based swap (US$ million)	3	—	—

	2004			2005			2006
	($ thousands)
Mark to Market Gains (Losses)
West Texas intermediate crude oil price based swaps	$	(9,075	)	$	(10,759	)	$	—
West Texas intermediate crude oil price based collars		(8,328	)		(12,027	)		—
West Texas intermediate crude oil price based floors		(415	)		(11,326	)		(1,294	)
Lloyd blend crude oil price based swaps		2,933			—			—
Alberta electricity price based swaps		582			1,483			352
Electricity heat rate		—			111			—
Canadian/U.S. dollar put option		679			—			—

	$	(13,624	)	$	(32,518	)	$	(942	)

Sensitivities

The table below indicates the impact of changes in key variables on Harvest's cash flow for the balance of 2004, including the impact of the hedging program.

	Variable
	WTI price/bbl	Heavy Oil LLB differential/bbl	Crude Oil Production	Canadian Bank Prime Rate	Foreign Exchange Cdn/U.S.
Assumption	US$40.00	US$15.00	36,000 bbls/d	4.25%	1.21
Change (plus or minus)	US$1.00	US$1.00	1,000 bbls/d	1.00%	0.01
Cash flow from operations (thousands)	$7,700	$7,200	$8,100	$500	$2,600

BUSINESS

Overview

Harvest applies a two-pronged approach to increasing asset value and cash flow. First, Harvest seeks to make disciplined acquisitions of mature producing assets at prices that generate strong rates of return. Harvest's recent acquisitions of Storm and the EnCana assets built on the momentum created from its earlier transactions and result in longer reserve life and improved balance in Harvest's commodity portfolio, and we believe will result in stronger operating netbacks. Second, Harvest focuses on creating incremental value through active management and technical and operating expertise. For example, Harvest works to optimize production and reduce unit costs to improve efficiencies, to economically add production and reserves and to extend property life.

At September 30, 2004, Harvest had approximately 37,500 boe/d of daily production and for the nine months ended September 30, 2004 pro forma adjusted EBITDA of approximately $228.3 million.

The following table summarizes Harvest's proved reserves as at July 1, 2004 on a pro forma basis and pro forma daily production:

		Light and Medium Oil (mbbls)		Heavy Oil (mbbls)		Natural Gas (mmcf)		NGLs (mbbls)		Total (mboe)		PV10 Value⁽¹⁾
Total proved reserves		42,517.6		20,857.3		69,681.7		2,114.1		77,102.6		$	802 million
Daily production		18.5		13.2		29.1		0.9		37.5

(1): PV10 is the present value of Harvest's estimated future net cash flow before income taxes for total proved reserves, discounted at 10% per year, calculated using forecast pricing. PV10 is not necessarily indicative of actual future cash flow or the fair market value of Harvest's reserves. See "Business — Oil and Gas Reserves" for forecast pricing used to determine this value.

Business Strengths

Low Cost Structure. Harvest's finding and development costs for the last two years have averaged $6.00/boe on a total proved reserve basis, which it believes is below the industry average. Operating costs as reflected in the September 30, 2004 pro forma consolidated statement of income were $7.38/boe. In addition, some of the EnCana properties have no royalty associated with them, reducing Harvest's average royalty percentage to approximately 16%. The high ratio of proved producing reserves to total proved reserves (90%) also allows Harvest to realize value from its proved reserves more quickly and with fewer costs than would otherwise be the case. Managing costs allows Harvest to extend reserve life and mitigate the impact of a lower commodity price cycle.

Business Strategy

Harvest is focused on cash flow generation and increasing the value of its assets. The key elements of Harvest's strategy include the following:

Continue to Recruit Excellent People. Maximizing the value of Harvest's assets requires excellent technical, financial and managerial talent. Recruiting staff who share Harvest's goal of technical excellence, and institutionalizing a team oriented culture of value maximization and comprehensive risk management are key business principles for Harvest. Harvest has further strengthened its talent pool with selective personnel additions associated with asset acquisitions.

Recent Acquisitions

this acquisition through the issuance of $175 million of trust units and $100 million aggregate principal amount of convertible subordinated debentures, and borrowings of approximately $195 million under the revolving credit facility and $70 million under the bank bridge facility. The EnCana assets produced approximately 20,481 boe/d for the six months ended June 30, 2004 and are primarily concentrated in the Crossfield area of Alberta, southeast Alberta and east central Alberta. The Crossfield and southeast Alberta properties comprise Harvest's new southern Alberta core area, and the east central Alberta properties supplemented Harvest's existing properties in that core area. The acquisition of the EnCana assets added Harvest's first significant natural gas production.

CORPORATE STRUCTURE

Harvest Energy Trust is an open-ended, unincorporated investment trust established under the laws of the Province of Alberta and created pursuant to its trust indenture in July 2002. The head and principal office of Harvest is located at Suite 1900, 330 - 5th Avenue S.W., Calgary, Alberta, T2P 0L4. Harvest's general phone number is (403) 265-1178. Harvest's trust units and convertible debentures are listed and posted for trading on the Toronto Stock Exchange under the trading symbols "HTE.UN," "HTE.DB" and "HTE.DB.A." The notes and the subsidiary guarantees will be fully and unconditionally guaranteed on an unsecured, unsubordinated basis by Harvest Energy Trust. The notes will not trade on a public stock exchange and Harvest has no plans at this time to list any of its securities on a U.S. public stock exchange.

Harvest acquired a 60% interest in the Redearth Partnership when it purchased Storm. Harvest's interest in the Redearth Partnership at the time of the Storm acquisition was approximately $20 million. As the partnership is not wholly owned, it is not a guarantor of Harvest Operations' obligations under the notes. See "Risk Factors Risks Relating to the Notes — The notes and the guarantees will be structurally subordinate to the indebtedness of Harvest's subsidiaries that are not guarantors of the notes."

The structure of the Trust and the flow of cash from its properties to its subsidiaries, from its subsidiaries to the Trust, and from the Trust to Unitholders are set forth below:

Notes:

(1): All operations and management of the Trust and the Operating Subsidiaries are conducted through Harvest Operations Corp. The Trust holds all of the voting securities of Harvest Operations Corp. and of Harvest Sask. Energy Trust.
(2): The Harvest Operations Corp. and Harvest Sask. Energy Trust own these properties.
(3): In addition to the NPI, the Trust holds various direct royalties.
(4): The Trust receives regular monthly payments in accordance with the Notes and NPI Agreements as well as distributions and interest payments from Harvest Sask. Energy Trust and Harvest Breeze Trust No. 2.
(5): Harvest Breeze Trust No. 1 and Harvest Breeze Trust No. 2 have also issued priority units to Harvest Operations Corp.

Principal Properties

The following table summarizes the net daily production from Harvest's four core operating areas on a pro forma basis as at September 30, 2004.

	Light Oil and NGLs (bbls/d)	Medium Oil (bbls/d)	Heavy Oil (bbls/d)	Natural Gas (mcf/d)	Total (boe/d)
North Central Alberta	3,120	—	—	1,330	3,342
East Central Alberta	1,200	7,260	5,467	2,172	14,289
Southern Alberta	880	940	7,733	25,598	13,819
Southeast Saskatchewan	6,000	—	—	—	6,000

	11,200	8,200	13,200	29,100	37,450

Harvest's portfolio of significant properties is discussed below. In general, the properties include major oil accumulations which benefit from active pressure support due to an underlying regional aquifer. Generally, the properties have predictable decline rates with costs of production and oil price key to determining the economic limits of production. Harvest is actively engaged in cost reduction, production and reserve replacement optimization efforts directed at reserve addition through extending the economic life of these properties and developing new proven reserves previously not evaluated by Harvest's independent engineers.

East Central Alberta

The properties within the east central Alberta core area are located between T35-R1-W4 to T49-R2-W5M and produce primarily crude oil. The following summarizes the key characteristics of this core operating area:

Proved Reserves:
	Oil (mbbl)	29,149
	NGL (mbbl)	140
	Natural gas (mmcf)	4,422
	Total (mboe)	30,026
	PV10 ($000)	247,012
Pro forma Production (boe/d)		14,289
Producing wells		1,010
Ownership		85-90%
Operatorship		90%
Average area operating expenses ($/boe)		8.00

Viking-Kinsella/Wainwright

Harvest acquired the Viking-Kinsella/Wainwright property from EnCana in September 2004. Current production from this region is 2,503 boe/d of 20° API oil, producing from the Cretaceous Upper Mannville Wainwright B (Sparky) formation. Harvest has an average 96% working interest in this operated property. Original oil in place (OOIP) at Viking-Kinsella/Wainwright is estimated at 133 mmbbls on Harvest's working interest acreage.

Future development opportunities at this property may include 23 infill and step-out drilling locations, as well as field optimization in fluid handling and debottlenecking the water injection system, which Harvest believes will contribute to reduced operating expenses.

Hayter

Harvest acquired the Hayter property in November 2002. Current production at Hayter is 4,658 boe/d of 14.8° API oil, producing from the Lower Cretaceous Cummings/Dina formation. Harvest has an average 94% working interest in this operated property. OOIP at Hayter is estimated at 138 mmbbls of oil on Harvest's working interest acreage.

Future development at Hayter may include infill and step-out drilling at up to 13 identified locations. Operating expense reduction projects such as low pressure water disposal wells, horizontal disposal wells, and battery optimization have been identified. In addition to cost reduction initiatives, Harvest believes it can capitalize on condensate blending opportunities to increase oil price realizations.

Killarney

The Killarney property was acquired by Harvest in two transactions in April and June 2003. Current production from the property is 1,041 boe/d of 20° API oil, producing from the Lower Cretaceous Cummings/Dina formation. Harvest has an average 91% working interest in this operated property. OOIP at Killarney is estimated at 51 mmbbls on Harvest's working interest acreage.

Future development at Killarney will primarily be focused on low pressure water disposal to increase operating cost efficiencies through power reduction as well as increased fluid handling leading to increased oil production.

Thompson Lake

Thompson Lake was one of the first properties acquired by Harvest in July 2002. Current production from this property is 991 boe/d of 27° API oil, producing from the Glauconite A pool. Harvest has an average 99% working interest in this operated property. OOIP at Thompson Lake is estimated at 50 mmbbls on Harvest's working interest acreage.

Future development at Thompson Lake will be focused on ongoing operating expense reduction as well as increased fluid handling leading to increased oil production.

Southern Alberta

The properties within the Southern Alberta core area are located from T13-R6-W4M to T29-R29-W4M and produce both crude oil and natural gas. Harvest acquired all Southern Alberta properties from EnCana in September 2004, and formed a new core area. The following table summarizes the key characteristics of this core operating area:

Proved Reserves:
	Oil (mbbl)		14,180
	NGL (mbbl)		1,492
	Natural gas (mmcf)		57,940
	Total (mboe)		25,330
	PV10 ($000)		326,124
Pro forma Production (boe/d)			13,819
Producing wells			290
Ownership			85%
Operatorship			100%
Average area operating expenses ($/boe)		$	5.50

Suffield

Current production from this region is 7,600 boe/d of heavy oil, averaging 11-18° API from the Upper Mannville Glauconitic formation. Harvest has an average 96% working interest in this operated property. OOIP at Suffield is estimated at 170 mmbbls of oil on Harvest's working interest acreage.

Future development at Suffield may include step-out, extension and infill drilling, and increased waterflood at up to 65 identified locations. Pool optimization projects may target increased production and generate economic oil production with increased water cuts to outperform engineering reserve estimates.

Crossfield

Current production from this region is 3,325 boe/d from the Lower Cretaceous Basal Quartz formation. Harvest has an average 71% working interest in this operated property. Original Gas In Place (OGIP) at Crossfield is estimated at 555 bcf of natural gas on Harvest's working interest acreage.

Future development at Crossfield will include infill and step-out drilling at up to 12 identified locations and field compression to increase the recovery factor and accelerate production.

Cavalier

Current production from this region is 1,400 boe/d of primarily light crude oil averaging 30-36° API, and produced from the Upper Mannville Glauconitic formation. Harvest has an average 96% working interest in this operated property.

Future development at Cavalier may include waterflood/reservoir management and optimization, and infill drilling to increase the recovery factor and accelerate production.

Badger

Current production from this region is 900 boe/d of medium crude oil averaging 21° API and natural gas produced from the Upper Mannville Glauconitic formation. Harvest has an average 100% working interest in this operated property. OOIP at Badger is estimated at 14 mmbbls and OGIP is estimated at 6 bcf on Harvest's working interest acreage.

Future development at Badger may include infill drilling, waterflood optimization, and reservoir management to increase the recovery factor.

Southeast Saskatchewan

The properties within the southeast Saskatchewan core area are located from T5-R31-W1M to T13-R9-W2M and produce primarily light gravity crude oil. Harvest acquired the properties in southeast Saskatchewan in October 2003. The following table summarizes the key characteristics of this core operating area:

Proved Reserves:
	Oil (mbbl)		11,866
	NGL (mbbl)		79
	Natural gas (mmcf)		1,130
	Total (mboe)		12,133
	PV10 ($000)		102,752
Pro forma Production (boe/d)			6,000
Producing wells			398
Ownership			100%
Operatorship			100%
Average Operating Expenses ($/boe)		$	10.00

Hazelwood

Current production from Hazelwood is 2,850 boe/d of average 33° API crude oil produced from the Tilston formation. Harvest has an average 98% working interest in this operated property. OOIP at Hazelwood is estimated at 160 mmbbls on Harvest's working interest acreage.

Future development at Hazelwood may include step-out and horizontal infill drilling at up to 45 locations to increase the recovery factor and accelerate production. Harvest believes further drilling opportunities are possible through the continued pooling of landowner interests to drill under-exploited areas. Harvest's extensive proprietary 3D seismic coverage offers control of the opportunity. An extensive workover program is available to increase oil production.

Whitebear/Big Marsh

Current production from Whitebear/Big Marsh is 850 boe/d of average 34° API crude oil produced from the Tilston formation. Harvest has an average 100% working interest in this operated property. OOIP at Whitebear/Big Marsh is estimated at 85 mmbbls on Harvest's working interest acreage.

Future development at Whitebear/Big Marsh may include infill drilling at three identified locations, water handling upgrades and water control measures to increase the recovery factor. Harvest's extensive proprietary 3D seismic coverage offers control of the opportunity to increase oil production through horizontal infill drilling.

North Central Alberta

The properties within the north central Alberta core area are located from T83-R7-W5M to T89-R15-W5M and produce primarily light gravity crude oil and natural gas. Harvest acquired all north central Alberta

properties when it acquired Storm in June 2004, and formed a new core area. The following table summarizes the key characteristics of this core operating area:

Proved Reserves:
	Oil (mbbl)		8,154
	NGL (mbbl)		402
	Natural gas (mmcf)		6,350
	Total (mboe)		9,614
	PV10 ($000)		125,701
Pro forma Production (boe/d)			3,342
Producing wells			197
Ownership			50%
Operatorship			75%
Average operating expenses ($/boe)		$	5.00

Loon Lake Slave Point

Current production from this region is 690 boe/d of oil averaging 39° API from the Devonian Slave Point formation. Harvest has an average 42% working interest in this operated property. OOIP at Loon Lake Slave Point is estimated at 40 mmbbls on Harvest's working interest acreage.

Future development at Loon Lake Slave Point may include downspace drilling at up to 32 locations, as well as potential waterflood to increase the recovery factor and flatten production profiles.

Loon Granite Wash

Current production averages 40° API from the Granite Wash formation. Harvest has an average 45% working interest in this operated property. OOIP at Loon Granite Wash is estimated at over 15 mmbbls on Harvest's working interest acreage.

Future development at Loon Granite Wash may include utilization of Harvest's extensive 3D seismic inventory to identify future drilling locations, step-out and infill drilling up to 15 locations, as well as production optimization opportunities.

Oil and Natural Gas Reserves

Harvest has three independent engineering firms who have evaluated its various properties, including the Storm and EnCana assets. McDaniel & Associates Consultants Ltd. evaluated Harvest's properties to the end of 2003. McDaniel and Paddock Lindstrom and Associates evaluated the Storm assets and McDaniel and Gilbert Laustsen Jung Associates Ltd. evaluated the EnCana assets. Each of these firms has provided evaluations of the various properties as at July 1, 2004 (in some cases, mechanically updated from December 31, 2003 to July 1, 2004). McDaniel has prepared a consolidation of the separate engineering evaluations prepared for Harvest as of July 1, 2004. McDaniel did not review the reserve evaluations provided by Paddock or Gilbert Laustsen Jung for the purpose of preparing the consolidation. In connection with the review by the independent engineers, Harvest provided land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts, financial data and future operating plans. These firms have also obtained other engineering, geological or economic data required by them from public records, other operators and their non-confidential files. The engineering firms did not independently verify the factual information that Harvest provided to them or that they obtained from other sources and did not conduct a field inspection.

The following tables shows Harvest's oil and natural gas reserves, as evaluated by the independent qualified reserves evaluators, and consolidated by McDaniel. Oil and oil equivalent reserves are expressed in thousands of barrels and natural gas reserves in millions of cubic feet.

	July 1			December 31
	2004			2003			2002
	Liquids (mbbls)	Natural gas (mmcf)	MBOE	Liquids (mbbls)	Natural gas (mmcf)	MBOE	Liquids (mbbls)	Natural gas (mmcf)	MBOE
Proved developed reserves	59,259	60,436	69,331	25,552	1,910	25,870	9,759	1,377	9,989
Total proved reserves	65,489	69,682	77,103	26,885	1,988	27,216	11,707	1,808	12,008

The following table provides the present value, in thousands of dollars, of Harvest's estimated future cash flow before income taxes of its proved oil and natural gas reserves, discounted at 10%, using forecast pricing:

July 1
July 1	December 31
2004	December 31
2004	2003	2002
801,589	154,922	115,965

Estimated future cash flow should not be construed as the fair value of Harvest's reserves.

The forecast pricing used to determine estimated future cash flow as at July 1, 2004 was prepared by McDaniel & Associates Consultants Ltd. and is set forth in the tables below:

Summary of Oil and NGL Price Forecasts

as of July 1, 2004

Year	WTI Crude Oil $US/bbl	Brent Crude Oil $US/bbl	Edmonton Light Crude Oil $/bbl	Alberta Bow River Medium Crude Oil $/bbl	Alberta Heavy Crude Oil $/bbl	Sask Cromer Medium Crude Oil $/bbl	Edmonton Cond. & Natural Gasolines $/bbl	Edmonton Propane $/bbl	Edmonton Butanes $/bbl	Edmonton NGL Mix $/bbl	Inflation %	US/CAN Exchange Rate $US/$CAN
Forecast
2004 (last 6 months)	37.50	36.00	49.00	39.00	34.00	43.50	49.80	33.80	32.30	36.50	2.0	0.750
2005	32.00	30.50	41.60	34.00	28.90	37.00	42.40	29.10	27.40	31.20	2.0	0.750
2006	28.80	27.20	37.40	30.60	26.00	33.20	38.20	25.40	24.70	27.70	2.0	0.750
2007	27.10	25.50	35.10	28.20	23.40	30.90	35.90	23.20	23.10	25.70	2.0	0.750
2008	27.00	25.40	34.90	27.90	23.00	30.60	35.70	22.90	23.00	25.50	2.0	0.750
2009	27.50	25.80	35.60	28.40	23.50	31.20	36.40	23.20	23.50	25.90	2.0	0.750
2010	28.10	26.40	36.30	29.00	23.90	31.80	37.10	23.70	23.90	26.50	2.0	0.750
2011	28.70	27.00	37.10	29.60	24.50	32.50	38.00	24.30	24.50	27.10	2.0	0.750
2012	29.30	27.50	37.90	30.30	25.00	33.20	38.80	24.80	25.00	27.70	2.0	0.750
2013	29.90	28.10	38.70	30.90	25.60	33.90	39.60	25.40	25.50	28.30	2.0	0.750
2014	30.50	28.70	39.40	31.50	26.00	34.50	40.30	25.90	26.00	28.80	2.0	0.750
2015	31.10	29.20	40.20	32.10	26.50	35.20	41.10	26.30	26.50	29.30	2.0	0.750
2016	31.70	29.80	41.00	32.80	27.00	35.90	42.00	26.80	27.00	29.90	2.0	0.750
2017	32.30	30.40	41.80	33.40	27.60	36.60	42.80	27.40	27.60	30.60	2.0	0.750
2018	32.90	30.90	42.50	33.90	28.00	37.20	43.50	27.80	28.00	31.00	2.0	0.750
2019	33.60	31.60	43.50	34.80	28.70	38.10	44.50	28.40	28.70	31.70	2.0	0.750
2020	34.30	32.20	44.40	35.50	29.30	38.90	45.40	29.00	29.30	32.40	2.0	0.750
2021	35.00	32.90	45.30	36.20	29.90	39.70	46.40	29.60	29.90	33.10	2.0	0.750
2022	35.70	33.60	46.20	36.90	30.50	40.50	47.30	30.20	30.50	33.70	2.0	0.750
2023	36.40	34.20	47.10	37.60	31.10	41.30	48.20	30.90	31.10	34.40	2.0	0.750
Thereafter	36.40	34.20	47.10	37.60	31.10	41.30	48.20	30.90	31.10	34.40	0.0	0.750

Summary of Natural Gas Price Forecasts

July 1, 2004

Year	U.S. Henry Hub Gas Price $US/mmbtu	Alberta AECO Spot Price $/GJ	Alberta Average Plantgate $/mmbtu	Alberta Aggregator Plantgate $/mmbtu	Alberta Spot Sales Plantgate $/mmbtu	Sask. Prov. Gas Plantgate $/mmbtu	Sask. Spot Sales Plantgate $/mmbtu	British Columbia CanWest Plantgate $/mmbtu	British Columbia CanWest Wellhead $/mcf	B.C. Spot Sales Plantgate $/mmbtu
Forecast
2004 (last 6 months)	6.45	7.35	7.60	7.60	7.60	7.75	7.75	7.50	7.40	7.60
2005	5.65	6.45	6.65	6.65	6.65	6.80	6.80	6.55	6.40	6.65
2006	4.80	5.50	5.60	5.60	5.60	5.80	5.80	5.50	5.30	5.60
2007	4.25	4.90	4.95	4.95	4.95	5.15	5.15	4.85	4.60	4.95
2008	4.15	4.80	4.85	4.85	4.85	5.05	5.05	4.75	4.50	4.85
2009	4.20	4.85	4.90	4.90	4.90	5.10	5.10	4.80	4.55	4.90
2010	4.30	4.95	5.00	5.00	5.00	5.20	5.20	4.90	4.65	5.00
2011	4.40	5.05	5.15	5.15	5.15	5.35	5.35	5.05	4.75	5.15
2012	4.50	5.15	5.25	5.25	5.25	5.45	5.45	5.15	4.85	5.25
2013	4.60	5.30	5.40	5.40	5.40	5.60	5.60	5.30	5.00	5.40
2014	4.70	5.40	5.50	5.50	5.50	5.70	5.70	5.40	5.10	5.50
2015	4.75	5.45	5.55	5.55	5.55	5.75	5.75	5.45	5.15	5.55
2016	4.85	5.55	5.65	5.65	5.65	5.85	5.85	5.55	5.25	5.65
2017	4.95	5.70	5.80	5.80	5.80	6.00	6.00	5.70	5.40	5.80
2018	5.05	5.80	5.90	5.90	5.90	6.10	6.10	5.80	5.50	5.90
2019	5.15	5.95	6.00	6.00	6.00	6.25	6.25	5.90	5.60	6.00
2020	5.25	6.00	6.10	6.10	6.10	6.35	6.35	6.00	5.65	6.10
2021	5.35	6.15	6.25	6.25	6.25	6.50	6.50	6.15	5.80	6.25
2022	5.50	6.30	6.40	6.40	6.40	6.65	6.65	6.30	5.95	6.40
2023	5.60	6.45	6.55	6.55	6.55	6.80	6.80	6.45	6.10	6.55
Thereafter	5.60	6.45	6.55	6.55	6.55	6.80	6.80	6.45	6.10	6.55

Drilling Activity

The number of gross and net development wells Harvest drilled is shown below. These numbers do not reflect activity on the Storm or EnCana properties as they were not owned by Harvest for the periods indicated.

Development Wells

	Gross			Net
	Productive	Non- Productive	Total	Productive	Non- Productive	Total
Fiscal 2003	21	1	22	18.5	1	19.5
Nine months ended September 30, 2004	26	4	30	25.5	4	29.5

Productive Wells

The following table sets forth Harvest's gross and net interests in productive oil, natural gas and service wells as of September 30, 2004. Productive wells are producing wells and wells capable of production:

	Gross	Net
Oil wells	2,830	2,492
Natural gas wells	155	100

Total	2,985	2,592

Acreage

The following table provides information about the amount of undeveloped acreage Harvest owned as of September 30, 2004. Undeveloped acreage means acreage on which Harvest does not have a productive well and includes exploratory acreage. Harvest's strategy is not to drill exploratory wells, but to engage third parties to farm-in on its lands and drill wells to earn a working interest. This allows Harvest to participate in the potential for reserve and production appreciation from these properties while mitigating Harvest's capital risk. Some of the undeveloped properties can be developed by Harvest through infill drilling and other types of development activities.

	Gross (acres)	Net (acres)
Alberta	232,676	218,534
Saskatchewan	207,213	186,444

Total	439,889	404,978

Markets and Customers

Harvest sells its oil predominantly through short-term contracts to refiners and marketers of crude oil at market prices. Harvest markets its natural gas to a number of end users and marketers at prices tied to spot price indexes. In both cases Harvest actively monitors and makes decisions based on prices, transportation, blending and delivery options to ensure it receives a fair netback at the wellhead. Harvest's current portfolio has a majority of its oil production sold directly to refiners in western Canada under terms that include postings based prices and month to month flexibility with regards to crude oil grades and delivery points. These contracts allow Harvest to optimize its field and production infrastructure without incurring significant risk.

Competition

The oil and natural gas industry is intensely competitive. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Harvest's competitive position depends on its geological, geophysical and engineering expertise, its financial resources, its ability to develop its properties and its ability to select, acquire and develop its reserves. Harvest competes with a substantial number of other companies and energy trusts having larger technical staffs and greater financial and operational resources. Many such entities not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations and market refined products.

Harvest also competes with major and independent oil and natural gas companies and other industries supplying energy and fuel in the marketing and sale of oil and natural gas to transporters, distributors and end users, including industrial, commercial and individual consumers. Harvest also competes with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time. Finally, companies not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Such companies will also provide competition for Harvest.

Regulation

The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. Harvest does not expect that any of these controls or regulations will affect its operations in a manner materially different than they would affect other oil and gas industry participants of similar size.

Crude oil and natural gas located in Alberta and Saskatchewan are owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas under leases, licenses and permits with terms generally varying from two years to five years and on conditions contained in provincial legislation. Leases, licenses and permits may be continued indefinitely by producing

under the lease, license or permit. Some of the oil and natural gas located in these provinces is privately owned and rights to explore for and produce oil and natural gas are granted by the mineral owners on negotiated terms and conditions.

In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends in part on supply/demand balance, oil quality, prices of competing fuels, distance to market, access to downstream transportation and the value of refined products. Oil exports may be made under National Energy Board export orders having terms not exceeding one year in the case of oil other than heavy oil, and not exceeding two years in the case of heavy oil. Any oil export to be made pursuant to a contract of longer duration requires an exporter to obtain an export license from the National Energy Board and the issue of a license requires the approval of the Canadian federal government. The term of the license may not exceed 25 years.

In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on natural gas heating value, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, length of contract term, weather conditions, the supply/demand balance and other contractual terms. Natural gas exported from Canada is subject to regulation by the Government of Canada through the National Energy Board. Producers and exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet criteria prescribed by the National Energy Board. Natural gas exports for a term of two years or less, or for two to 20 years in quantities not more than 1.1 million cubic feet per day may be made under a National Energy Board order, or, in the case of exports for a longer duration or larger volumes, under a National Energy Board license and Canadian federal government approval.

The provincial governments of Alberta and Saskatchewan also regulate the removal of natural gas from those provinces for consumption elsewhere. They do so based on such factors as reserve availability, transportation arrangements and market considerations.

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than government lands are determined by negotiations between the mineral owner and the lessee. Royalties on government land are determined by government regulation and are generally calculated as a percentage of the value of gross production, and the rate of royalties payable generally depends upon prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time the governments of Canada, Alberta and Saskatchewan have established incentive programs which have included royalty rate deductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects although the trend is toward eliminating these types of programs in favor of long-term programs which enhance predictability for producers.

On October 13, 1992, the government of Alberta implemented major changes to its royalty structure and created incentives for exploring and developing oil and natural gas reserves. The incentives created include: (i) a one year royalty holiday on new oil discovered on or after October 1, 1992; (ii) incentives by way of royalty holidays and reduced royalties on reactivated, low productivity, vertical re-entry and horizontal wells; (iii) introduction of separate par pricing for light/medium and heavy oil; and (iv) a modification of the royalty formula structure through the implementation of a third tier royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%. These rate bases and caps pertain to typical production of up to 197.3 m³ per month for a well. The principal variables affecting the royalty are the monthly oil production of the particular well and the difference between specified monthly par prices and annual reference prices. In the case of low productivity wells (with less than 20 m³ per month production) the royalty is reduced below the 10% base, and in the case of third tier oil is zero, and in cases of very high productivity wells, the effective royalty rate may, in certain circumstances, marginally exceed the 25%, 30% or 35% rate, as applicable.

In Alberta, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 is eligible for a royalty exemption for a period of 12 months, up to a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the wells.

In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the government by virtue of the Alberta royalty tax credit program. The Alberta royalty tax credit program is based on a price sensitive formula, and ranges between 75%, for prices for oil at or below $100 per cubic meter ($15.90 per barrel), to 25%, for prices above $210 per cubic meter ($33.39 per barrel). In general, the Alberta royalty tax credit rate is applied to a maximum of $2,000,000 of government royalties payable for each producer or associated group of producers. Government royalties on production from producing properties acquired from corporations claiming maximum entitlement to Alberta royalty tax credit will generally not be eligible for Alberta royalty tax credit. The rate is established quarterly based on the average "par price," as determined by the Alberta Department of Energy for the previous quarterly period.

Crude oil and natural gas royalty holidays and reductions for specific wells reduce the amount of royalties paid to the government.

The North American Free Trade Agreement among the governments of Canada, the United States and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada-U.S. Free Trade Agreement. Subject to the General Agreement on Tariffs and Trade, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, so long as any export restrictions do not:

•: reduce the proportion of energy resources exported relative to total supply (based upon the proportion prevailing in the most recent 36 month period or another representative period agreed upon by the parties);
•: impose an export price higher than the domestic price (subject to an exception that applies to some measures that only restrict the value of exports); or
•: disrupt normal channels of supply.

All three countries are prohibited from imposing minimum or maximum export or import price requirements, with some limited exceptions.

Environmental

The oil and natural gas industry is governed by environmental regulation under Canadian federal and provincial laws, rules and regulations, which restrict and prohibit the release or emission and regulate the storage and transportation of various substances produced or utilized in association with oil and natural gas industry operations. In addition, applicable environmental laws require that well and facility sites be abandoned and reclaimed, to the satisfaction of provincial authorities, in order to remediate these sites to near natural conditions. Also, environmental laws may impose upon "responsible persons" remediation obligations on property designated as a contaminated site. Responsible persons include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any present or past owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures. A breach of environmental laws may result in the imposition of fines and penalties and suspension of production, in addition to the costs of abandonment and reclamation.

In Alberta, all applicable environmental laws are consolidated in the Alberta Environmental Protection and Enhancement Act. Under this Act, environmental standards and requirements applicable to compliance, cleanup and reporting have been made more strict. Also, the range of enforcement actions available and the

severity of penalties have been significantly increased. These changes will have an incremental increase in the cost of conducting oil and natural gas operations in Alberta.

In 1994, the United Nations' Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which requires, upon ratification, nations to reduce their emissions of carbon dioxide and other greenhouse gases. In December 2002, the Canadian federal government ratified the Kyoto Protocol. If certain conditions are met and the Kyoto Protocol enters into force internationally, Canada will be required to reduce its greenhouse gas (GHG) emissions. Currently the upstream crude oil and natural gas sector is in discussions with various provincial and federal levels of government regarding the development of greenhouse gas regulations for the industry. It is premature to predict what impact these potential regulations could have on Harvest but it is possible that Harvest would face increases in operating costs in order to comply with a GHG emissions target.

Harvest has established guidelines and management systems to ensure compliance with environmental laws, rules and regulations. Harvest has designated an individual responsible for compliance whose responsibility is to monitor regulatory requirements and their impact on us, to implement appropriate compliance procedures and to cause our operations to be carried out in accordance with applicable environmental guidelines and implementing adequate safety precautions. The existence of these controls cannot, however, guarantee total compliance with environmental laws, rules and regulations. Harvest believes that it is in material compliance with applicable environmental laws and regulations. Harvest also believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

Employees

As of September 30, 2004, Harvest employed or contracted 180 full time persons. Harvest considers its relations with its employees to be good.

Legal Proceedings

Harvest is a party to various legal actions in the ordinary course of business. In its opinion, none of these actions, either individually or in the aggregate, will have a material adverse effect on its financial condition or operating results.

MANAGEMENT

The following table sets forth the name, age as of the date of this prospectus and position held by each of Harvest's directors and executive officers:

Name	Age	Position Held
M. Bruce Chernoff	39	Chairman and Director
Jacob Roorda	47	President
J. A. Ralston	42	Vice President, Operations
James Campbell	47	Vice President, Geosciences
David J. Rain	40	Vice President, Chief Financial Officer and Corporate Secretary
John A. Brussa	47	Director
Verne G. Johnson	60	Director
Hector J. McFadyen	61	Director
Hank B. Swartout	53	Director

M. Bruce Chernoff, Chairman and Director

Mr. Chernoff initiated the formation of Harvest in June 2002 to pursue oil and natural gas development and acquisition opportunities. In March 2000, Mr. Chernoff joined Petrobank Energy and Resources Ltd. as Director and the Executive Vice President and Chief Financial Officer. Mr. Chernoff resigned as Chief Financial Officer of Petrobank in October 2001 to focus on other business interests, and resigned from the Board in November 2004. In June 1999, Mr. Chernoff initiated the formation of Caribou Capital Corp., of which he is the President and a Director, to make various investments. Prior to forming Caribou, Mr. Chernoff held various senior positions with Pacalta Resources Ltd., including Executive Vice-President and Chief Financial Officer. Mr. Chernoff was a director of Pacalta from 1992 until Pacalta was purchased by Alberta Energy Company in May 1999 for $1 billion.

Jacob Roorda, President

Mr. Roorda joined Harvest as its President in August 2002. From June 1999 to July 2002, Mr. Roorda was a Managing Director of Research Capital, an investment-banking firm, where he was responsible for the overall direction and operations of the Calgary investment banking office of the firm. In January 1996, Mr. Roorda co-founded PrimeWest Energy Trust and served as Vice President, Corporate and Director. From 1991 to 1996, Mr. Roorda was Manager, Business Development at Fletcher Challenge. From 1987 to 1991, Mr. Roorda was a Vice President in the equity research group and was a ranked oil and natural gas analyst at BZW Canada Ltd., in Toronto. Prior to joining BZW Canada, Mr. Roorda held a number of senior engineering positions with Dome Petroleum Ltd.

J. A. Ralston, Vice President, Operations

Mr. Ralston joined Harvest as its Vice President, Operations in June 2002. From July 1994 until June 2002, Mr. Ralston worked at Penn West Petroleum. Since 1997, Mr. Ralston served as Penn West's Production Manager, responsible for overseeing all of its production operations. Mr. Ralston was responsible for all areas of operations including engineering, exploitation, production optimization, capital management, planning, construction and budgeting. From 1980 through June 1994, Mr. Ralston was employed with Petro-Canada in a broad range of field operating positions of increasing responsibility. During his tenure at Petro-Canada, Mr. Ralston was responsible for construction of field facilities and pipelines, natural gas plant and field operations, procurement, reservoir management, drilling and workovers.

James Campbell, Vice President, Geosciences

Mr. Campbell joined Harvest as its Vice President, Geosciences in August 2002. From August 1997 to July 2002, Mr. Campbell was Vice President, Exploration for Navigo Energy Ltd. and its predecessors, overseeing all exploration activity. From 1985 through 1997, Mr. Campbell held various leadership positions with Conoco Canada Ltd., including Vice President, Exploration.

David J. Rain, Vice President, Chief Financial Officer and Corporate Secretary

Mr. Rain joined Harvest as Corporate Secretary in July 2002 and as Vice President, and Chief Financial Officer in August 2004. Prior to becoming Harvest's CFO, Mr. Rain was Vice President, Finance and Chief Financial Officer of Petrobank, a position he assumed in October 2001. In 1999, Mr. Rain joined Mr. Chernoff at Caribou, and then became Director, Corporate Finance at Petrobank in March 2000. Mr. Rain joined Pacalta Resources Ltd., an oil and natural gas exploration and production company with operations primarily in Ecuador, in May 1997 as Corporate Controller. Mr. Rain was the Chief Financial Officer of Trican Well Service Ltd, an oilfield service company with operations in Alberta and Saskatchewan, from October 1996 through April 1997, and served in senior financial positions at Nowsco Well Service Ltd., an oilfield service company with worldwide operations, from 1992 through August 1996. Mr. Rain articled at KPMG LLP Chartered Accountants and was a Manager in their audit group until he departed in 1992.

John A. Brussa, Director

Mr. Brussa joined Harvest's board of directors in August 2002. Mr. Brussa is a barrister and solicitor and has been a partner at Burnet, Duckworth & Palmer LLP in Calgary since 1987. He is recognized as a leading tax practitioner in Canada.

Verne G. Johnson, Director

Mr. Johnson joined Harvest's board of directors in August 2002. Mr. Johnson is President of his private family company, KristErin Resources Inc. From 2000 until February 2002, Mr. Johnson served as Senior Vice President of Funds Management for the Enerplus Resources Group. From 1999 until joining Enerplus, Mr. Johnson was President of AltaQuest Energy Corporation and from 1997 to 1999 he was President of Ziff Energy Group. In 1989, Mr. Johnson joined ELAN Energy Inc. (then Lasmo Canada Inc.) where he served as President and a Director until its sale in 1997. In 1982, he joined Roxy Petroleum Ltd. as Vice President, Production, remaining until 1987 when he joined Paragon Petroleum Ltd. as President. In 1981, he joined Liberty Petroleum Ltd. as President and Chief Executive Officer. Prior to joining Liberty Petroleum, Mr. Johnson worked at Imperial Oil Limited, including two years with Exxon Corporation in New York from 1977 to 1979.

Hector J. McFadyen, Director

Mr. McFadyen joined Harvest's board of directors in August 2002. Mr. McFadyen worked for Alberta Energy Company Ltd. (AEC), now EnCana Corporation, from 1976 until his retirement in 2002. From 1981 until his retirement, Mr. McFadyen served as a Vice President at AEC and was involved in recommending and implementing the strategic plan for the company. From 1981 to 1995, he also served as President of the Forest Products Division of AEC and was responsible for the development and implementation of the business strategy for an Alberta-based forest products business. From 1995 until his retirement, Mr. McFadyen served as the President of the Midstream Division of AEC and had responsibility for the company's pipelines and natural gas storage businesses. Prior to joining AEC, Mr. McFadyen was employed at the Alberta Energy and Utilities Board (formerly the Oil and natural gas Conservation Board) between 1969 and 1976, primarily within its Economics Department. Mr. McFadyen is a member of the board of directors of Hunting PLC, a UK-based public corporation engaged in oil services and oil and natural gas marketing and distribution activities internationally (including in North America through its wholly-owned subsidiary, Gibson Energy Ltd.). Mr. McFadyen is also a member of the Board of Directors of Computershare Trust Company of Canada, a private Canadian trust company, and Aluma Systems, a private Canadian industrial and concrete construction services company.

Hank B. Swartout, Director

Mr. Swartout joined Harvest's board of directors in December 2002. Mr. Swartout is the Chairman of the Board, President and Chief Executive Officer of Precision Drilling Corporation, the largest Canadian integrated oilfield and industrial services contractor and a global provider of products and services to the energy industry, a position he has held for at least the last 5 years.

RELATIONSHIPS AND RELATED TRANSACTIONS

On January 24, 2003 Caribou Capital Corp., a corporation controlled by M. Bruce Chernoff (a director and Chairman of Harvest Operations Corp.), exercised warrants to purchase 150,000 trust units for proceeds of $150,000. The warrants were granted in respect of debt financing provided by Caribou Capital Corp. to Harvest in 2002.

On July 28, 2003, Harvest entered into separate equity bridge note agreements with Mr. Chernoff and Caribou Capital Corp., (collectively, the "Equity Bridge Notes") which collectively provided for aggregate advances of up to $40,000,000 to Harvest to assist in connection with the acquisition of certain oil and natural gas properties. On July 29, 2003, Harvest received $11,000,000 in advances pursuant to the Equity Bridge Notes to fund the deposit relating to the purchase of such properties. On September 29, 2003, Harvest amended the Equity Bridge Notes to allow advances to be used to pay out Harvest Operations' then existing credit facility and entered into bridge notes (the "Bridge Notes") with Mr. Chernoff and Caribou Capital Corp. providing for advances of up to $30,000,000 to Harvest to assist with the payout of Harvest Operations' then existing credit facility and to assist in connection with the acquisition by Harvest Operations of certain oil and gas properties. On September 29, 2003, Harvest received additional advances under the Equity Bridge Notes in the amount of $22,500,000 and also received advances of $25,000,000 under the Bridge Notes. These amounts were advanced by Harvest to Harvest Operations on September 30, 2003, and used to payout, in part, the approximately $48,100,000 owing under Harvest Operations' then existing credit facility. On October 1, 2003, the $11,000,000 deposit with respect to the properties was refunded and this amount was used to partially repay $11,000,000 of principal in respect of the Bridge Notes. On October 16, 2003, Harvest repaid $8,500,000 of the Equity Bridge Notes and approximately $14,000,000 was used to repay in full the Bridge Notes. No further amounts are available under the Bridge Notes at this time. On January 2, 2004 Harvest paid $665,068 in accrued interest in respect of equity bridge principal outstanding during the fourth quarter of 2003. On January 26 and 29, 2004 Harvest repaid the remaining $25,000,000 of equity bridge principal amounts outstanding and paid $185,232 of interest accrued since December 31, 2003. The Equity Bridge Notes were amended on June 29, 2004, July 7, 2004 and July 9, 2004 to assist with the acquisition by Harvest Operations of Storm and the acquisition of the EnCana assets. The Equity Bridge Notes are secured by a fixed and floating charge on Harvest's assets, are subordinate to the security interests of the Senior Lenders, and mature on July 31, 2005 for the Equity Bridge with Caribou and January 1, 2005 for the Equity Bridge with Chernoff and bear interest at a rate of 10% per annum. No amounts are outstanding on the Equity Bridge Notes with Mr. Chernoff, and Harvest has undertaken not to borrow any amounts thereunder until changes are made to his Equity Bridge Notes to conform the maturity date to July 31, 2005 and until a further subordination is entered into with the Senior Lenders.

Caribou Capital Corp. sublets office space and is provided administrative services by Harvest on a cost recovery basis.

John A. Brussa, one of Harvest's directors, is a partner of Burnet, Duckworth & Palmer LLP. Burnet, Duckworth & Palmer LLP is passing upon Canadian legal matters relating to the offering of the notes. Mr. Brussa and Burnet, Duckworth & Palmer LLP have provided legal services to Harvest from time to time, including in connection with the offering of the notes and the preparation of this prospectus.

Hank Swartout, one of Harvest's directors, is Chairman, President and Chief Executive Officer of Precision Drilling Corporation, the largest Canadian integrated oilfield and industrial services contractor with operations in western Canada. Precision provides drilling and other oilfield services to Harvest at market prices.

PRINCIPAL UNITHOLDERS

The following table contains information provided by Harvest's unitholders, or contained in Harvest's trust unit ownership records with respect to beneficial ownership of Harvest's trust units as of September 30, 2004 by:

•: each person known by Harvest to be the beneficial owner of more than 10% of its outstanding trust units;
•: each named executive officer;
•: each director; and
•: all directors and executive officers as a group.

Each person has sole voting and investment power with respect to the trust units listed.

	Trust Units Beneficially Owned
Name	Trust Units Beneficially Owned
Name	Number	%
John A. Brussa	285,000	0.8
James Campbell	22,950	0.1
M. Bruce Chernoff	7,328,588	19.9
Verne G. Johnson	25,000	0.1
Hector J. McFadyen	30,000	0.1
David J. Rain	107,500	0.3
J.A. Ralston	116,705	0.3
Jacob Roorda⁽¹⁾	214,845	0.6
Hank B. Swartout	749,976	2.0
All directors and executive officers as a group (9 persons)	8,880,564	24.1

(1): Includes 61,996 units held by Mr. Roorda's spouse which are controlled by Mr. Roorda.

Incentive Rights Granted to Directors

The following table provides information relating to incentive rights held by Harvest's directors as of September 30, 2004.

Name	Number of Trust Units Underlying Incentive Rights Granted	Date of Grant	Exercise Price at Date of Grant		Expiry Date
John A. Brussa	25,000	February 14, 2003	$	10.75	February 14, 2008
M. Bruce Chernoff	Nil	N/A		N/A	N/A
Hank B. Swartout	25,000	November 25, 2002	$	8.00	November 25, 2007
Verne G. Johnson	25,000	November 25, 2002	$	8.00	November 25, 2007
Hector J. McFadyen	25,000	November 25, 2002	$	8.00	November 25, 2007

DESCRIPTION OF OTHER INDEBTEDNESS

Senior Credit Facilities

Revolving Credit Facility. Harvest Operations has a $325 million revolving credit facility with a Canadian chartered bank as agent and arranger and a syndicate of lenders (the "Bank Lenders") pursuant to a credit agreement with Harvest, Harvest Operations and their material subsidiaries. The revolving credit facility is available for general corporate purposes. The revolving facility matures on June 29, 2005. The revolving period may be extended on a year to year basis with the unanimous consent of all Bank Lenders, or if 66²/3% of the Bank Lenders agree and non-consenting Bank Lenders are replaced or repaid prior to the maturity date. If the Bank Lenders do not agree to extend the revolving period, the facility must be repaid in full on the then current maturity date. Included within this facility is a $15 million operating facility available in Canadian or U.S. dollars and by way of letters of credit or letters of guarantee. Availability of the revolving credit facility is subject to periodic reviews of the business and affairs of Harvest and its material subsidiaries with the next interim review to occur no later than March 31, 2005.

Under Harvest Operation's revolving credit facility, Harvest Operations' permitted borrowing base amount is established periodically by unanimous determination of the Bank Lenders. Updated engineering reports are required to be delivered by March 31 and September 30 of each year and a borrowing base redetermination is then made within 30 days of these dates. The permitted borrowings under the senior credit facilities are limited to the amount of the borrowing base. Amounts outstanding under this facility bear interest at a rate based on the prime rate of the Bank Lender that acts as administrative agent, or at the bankers' acceptance rate or LIBOR, plus a margin based on our ratio of total funded debt to cash flow, that ranges from 0% to 2.25% and a standby fee on undrawn amounts that range from .125% to .50%. The margin within the operating facility for letters of credit or letters of guarantee ranges from 1.00% to 3.00%. These facilities have customary covenants including, but not limited to, covenants with respect to:

•: creating liens to secure debt;
•: transfer and sale of assets;
•: making loans or investments or providing financial assistance;
•: amending material contracts;
•: mergers and amalgamations;
•: incurring additional debt;
•: maintaining a ratio of EBITDA to interest and ratio of current assets to current liabilities;
•: restricting payment by Harvest Operations or any material subsidiary of certain distributions (including dividends, redemptions and payments on account of indebtedness) out of the ordinary course of business, during default or if payment would materially impair the ability to fulfill obligations to the Bank Lenders; and
•: derivatives contracts.

Harvest Operations' senior credit facilities are secured by a floating charge, general assignment of book debts, assignment of certain specified contracts and security interest over all of its assets and undertakings and are guaranteed by Harvest and all of its other material subsidiaries. The Bank Lenders are entitled to proceed against any of those guarantors without proceeding first against Harvest Operations. The obligations of those guarantors to the Bank Lenders are similarly secured against all of their assets and undertakings. All of such security interests held by the Bank Lenders also secure all obligations under any Interest Rate Agreements, Currency Agreements or Commodity Agreements with any such Bank Lenders (or any affiliate of a Bank Lender) from time to time but obligations under those derivatives contracts are not included for purposes of calculating the borrowing base. The security interests include the right of the Bank Lenders to require specific fixed charges if the Bank Lenders determine that there has been a material adverse effect. In addition, subordination arrangements are in place which subordinate certain indebtedness of Harvest Operations or certain of its material subsidiaries owing to Harvest, to indebtedness to the Bank Lenders.

Under the terms of Harvest Operations' senior credit facilities, if Harvest experiences a change of control, all amounts outstanding will become immediately due. Unless Bank Lenders unanimously agree to waive their right to be immediately repaid, Harvest will be obligated to immediately repay all principal then outstanding, and accrued and unpaid fees and interest, if any, under the senior credit facilities. Other events of default include Harvest Operations ceasing to be the manager/administrator of Harvest and monetary defaults under derivatives contracts with the Bank Lenders at a threshold which is lower than that for cross default to third party indebtedness. An event of default also entitles a Bank Lender party to a derivative contract with Harvest or any of its material subsidiaries to terminate such contract. Security interests securing a Bank Lender or its affiliate for derivative contracts entered into with Harvest Trust or any of its material subsidiaries continue to secure such Persons for such obligations after the Lender ceases to be a Bank Lender under the senior facilities.

9% Convertible Unsecured Subordinated Debentures

Harvest issued $60 million of 9% convertible debentures due May 31, 2009, at a price of $1,000 per debenture in January 2004. The debentures bear interest at an annual rate of 9% payable semi-annually on May 31 and November 30 in each year. The debentures are redeemable by Harvest at a price of $1,050 per debenture after May 31, 2007 and on or before May 31, 2008 and at a price of $1,025 per debenture after May 31, 2008 and before maturity on May 31, 2009, in each case, plus accrued and unpaid interest thereon.

Each debenture is convertible into 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 Harvest for redemption of the debentures, at a conversion price of $14.00 per trust unit, subject to adjustment in certain events.

On redemption or at maturity, Harvest may, at its option, elect to satisfy its obligation to pay the redemption price or the principal amount of the debentures at maturity, as the case may be, by issuing and delivering that number of trust units obtained by dividing the principal amount of the outstanding debentures which are to be redeemed or which have matured by 95% of the weighted average trading price of the trust units on the Toronto Stock Exchange for the 20 consecutive trading days ending on the fifth trading day preceding the date fixed for redemption or the maturity date, as the case may be.

Harvest may elect to satisfy its obligation to pay interest on the debentures by delivering sufficient trust units to the debenture trustee to satisfy all or any part of the interest obligation. If the foregoing election is made, the sole right of a holder of debentures in respect of interest will be to receive cash from the debenture trustee out of the proceeds of sale of trust units delivered to the trustee and the holder will not be entitled to receive any trust units in satisfaction of the interest obligations.

The debentures are not redeemable on or before May 31, 2007. After May 31, 2007 and prior to maturity, the debentures may be redeemed in whole or in part from time to time at the option of Harvest on not more than 60 days and not less than 30 days prior notice, at a redemption price of $1,050 per debenture after May 31, 2007 and on or before May 31, 2008 and at a redemption price of $1,025 per debenture after May 31, 2008 and before maturity, in each case, plus accrued and unpaid interest thereon, if any. In the case of redemption of less than all of the debentures, the debentures to be redeemed will be selected by the debenture trustee on a pro rata basis or in such other manner as a debenture trustee deems equitable, subject to the consent of the Toronto Stock Exchange.

The payment of principal and interest on the debentures is subordinated in right of payment to the prior payment in full of all senior indebtedness of Harvest and effectively subordinated to claims of creditors of Harvest's subsidiaries except to the extent that Harvest is a creditor of such subsidiaries ranking at least pari passu with such other creditors.

Within 30 days following the occurrence of a change of control of Harvest involving the acquisition of voting control or direction over 66²/3% or more of the trust units, Harvest is required to make an offer in writing to purchase all of the debentures then outstanding at a price equal to 101% of the principal amount thereof plus accrued and unpaid interest. Harvest is required to give written notice to the debenture trustee of the occurrence of a change of control and the debenture trustee is required thereafter to provide notice of the change of control to the holders of debentures. If 90% or more of the aggregate principal amount of the

debentures outstanding on the date of the giving of notice of the change of control have been tendered to Harvest pursuant to the debenture offer, Harvest is required to redeem all of the remaining debentures at the debenture offer price.

The indenture in respect of the debentures provides for customary events of default. If an event of default has occurred and is continuing, the debenture trustee may, in its discretion, and shall upon request of holders of not less than 25% of the principal amount of debentures then outstanding, declare the principal of and interest on all outstanding debentures to be immediately due and payable. In certain cases, the holders of more than 50% of the principal amount of the debentures then outstanding may, on behalf of the holders of all debentures, waive any event of default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe.

The indenture in respect of the debenture provides that Harvest shall not issue additional convertible debentures of equal ranking if the principal amount of all issued and outstanding convertible debentures of the trust exceeds 25% of the total market capitalization (defined as the total principal amount of all issued and outstanding debentures of Harvest which are convertible at the option of the holder into trust units of Harvest plus the amount obtained by multiplying the number of issued and outstanding trust units of Harvest by the current market price of the trust units on the relevant date) of Harvest immediately after the issuance of such additional convertible debentures.

As at September 30, 2004, $24,915,000 aggregate principal amount of the 9% convertible debentures is outstanding following conversions to that date.

8% Convertible Unsecured Subordinated Debentures

Harvest issued $100 million of 8% convertible debentures due September 30, 2009, at a price of $1,000 per debenture in August 2004. The debentures bear interest at an annual rate of 8% payable semi-annually on March 31 and September 30 in each year. The debentures are redeemable by Harvest at a price of $1,050 per debenture after September 30, 2007 and on or before September 30, 2008 and at a price of $1,025 per debenture after September 30, 2008 and before maturity on September 30, 2009, in each case, plus accrued and unpaid interest thereon.

Each debenture is convertible into 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 Harvest for redemption of the debentures, at a conversion price of $16.25 per trust unit, subject to adjustment in certain events.

On redemption or at maturity, Harvest may, at its option, elect to satisfy its obligation to pay the redemption price or the principal amount of the debentures at maturity, as the case may be, by issuing and delivering that number of trust units obtained by dividing the principal amount of the outstanding debentures which are to be redeemed or which have matured by 95% of the weighted average trading price of the trust units on the Toronto Stock Exchange for the 20 consecutive trading days on the fifth trading day preceding the date fixed for redemption or the maturity date, as the case may be.

The debentures are not redeemable on or before September 30, 2007. After September 30, 2007 and prior to maturity, the debentures may be redeemed in whole or in part from time to time at the option of Harvest on not more than 60 days and not less than 40 days prior notice, at a redemption price of $1,050 per debenture after September 30, 2007 and on or before September 30, 2008 and at a redemption price of $1,025 per debenture after September 30, 2008 and before maturity, in each case, plus accrued and unpaid interest thereon, if any. In the case of the redemption of less than all of the debentures, the debentures to be redeemed will be selected by the debenture trustee on a pro rata basis or in such other manner as a debenture trustee deems equitable, subject to the consent of the Toronto Stock Exchange.

The indenture respecting the debentures also contains similar provisions to those set forth above under "— 9% Convertible Unsecured Subordinated Debentures" in respect of changes of control of Harvest, events of default and the issuance of additional convertible debentures.

As at September 30, 2004, $71,219,000 of these 8% convertible debentures is outstanding following conversions to that date.

Equity Bridge Notes

See "Relationships and Related Transactions" for a description of the outstanding amounts under the equity bridge notes. Under the terms of the applicable agreements, interest is paid quarterly in arrears and is calculated daily at a fixed rate of 10% per annum. Harvest has the option to settle the quarterly interest payments with cash or the issue of trust units. If Harvest elects to issue trust units, the number of trust units to be issued to settle a quarterly interest payment shall be the equivalent to the quarterly payment amount divided by 90% of the most recent ten-day weighted average trading price. The maximum principal available under the equity bridge notes of Caribou is $30 million, of which $10 million is advanced. The maximum principal amount available under the equity bridge notes of Mr. Chernoff is $20 million, of which no amount is advanced. Amounts repaid under the equity bridge notes can not be reborrowed under the terms thereof without the agreement of the lender.

Harvest also has the option to repay the principal amounts outstanding at any time. If Harvest chooses to partially repay the outstanding principal amount, such payment is to be made in cash. Harvest has the option at maturity of the full principal amount to settle its 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. Harvest is not entitled to settle any principal or interest by way of trust units during an event of default. The outstanding principal portion and all accrued and unpaid interest on the equity bridge note agreements of Caribou is due and payable on July 31, 2005. No amounts are to be drawn by Harvest under the equity bridge notes of Mr. Chernoff until his equity bridge notes have been amended as required by the Bank Lenders, including to confirm a July 31, 2005 maturity. The equity bridge lenders have agreed to subordinate their interests to any claims of the Bank Lenders. Security has been provided in the form of second-priority fixed and floating debentures on all of Harvest Energy Trust's assets. The equity bridge lenders may demand payment of the full amount if specified events of default under the equity bridge note agreements occur, including cross default to any other indebtedness of Harvest, an unacceptable change in Harvest management or trustee, a change in control of Harvest, suspension or cease trading of the trust units of Harvest on any stock exchange or if the lender believes there has been a material adverse change or that repayment or the collateral security has been impaired or is in jeopardy. Covenants include a negative covenant not to make distributions during an event of default or if it would materially limit its ability to meet obligations under the equity bridge notes. On September 29, 2003, the equity bridge note agreements were amended to extend the uses permitted under the previous agreements, to include repayment of bank debt. However, current purposes are limited to obligations in relation to its net profits interest with Harvest Operations and to assist in acquisitions.

THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

On October 14, 2004, Harvest sold its old notes in a private placement exempt from the registration requirements of the Securities Act, and Morgan Stanley & Co. Incorporated, TD Securities (USA) Inc., NFB Securities (USA) Corp. and WestLB AG London Branch as initial purchasers of these old notes then resold them in reliance on other exemptions from the registration requirements of the Securities Act. Consequently, the old notes are subject to transfer restrictions under the Securities Act. Pursuant to the terms of a registration rights agreement entered into by Harvest, the Guarantors and the initial purchasers on October 14, 2004, Harvest and the Guarantors agreed, among other things, to deliver this prospectus and to keep the exchange offer open for no less than 20 business days (or longer if required by applicable law) after the date notice of the exchange offer is mailed to the holders of the old notes. In addition, Harvest and the Guarantors agreed in the event that (i) the Company and the Guarantors determine that the Exchange Offer Registration is not available or may not be consummated as soon as practicable after the Exchange Date because it would violate applicable law or the applicable interpretations of the Staff of the SEC, (ii) the exchange offer is not for any other reason completed by 210 days from the Closing Date or (iii) the exchange offer has been completed and in the opinion of counsel for the Initial Purchasers a Registration Statement must be filed and a prospectus must be delivered by the Initial Purchasers in connection with any offering or sale of Registrable Securities, they shall use their commercially reasonable efforts to cause to be filed as soon as practicable after such determination, date or notice of such opinion of counsel is given to the Company and the Guarantors, as the case may be, a Shelf Registration Statement providing for the sale by the Holders of all of the Registrable Securities and to have such Shelf Registration Statement declared effective by the SEC.

If required by the terms of the Registration Rights Agreement, we will file with the SEC a shelf registration statement to cover resales of the old notes by the holders thereof who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. We will use our reasonable best efforts to cause the applicable registration statement to be declared effective as promptly as possible by the SEC.

A holder selling old notes or new notes pursuant to a Shelf Registration Statement would be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with these sales and will be bound by the applicable provisions of the Registration Rights Agreement (including certain indemnification obligations).

Pursuant to the Registration Rights Agreement, we will be required to pay additional interest of 0.25% if a registration default exists. A registration default will exist if:

•: we fail to file any of the prospectuses or registration statements required by the Registration Rights Agreement within 210 days after the Closing Date;
•: the Shelf Registration Statement or the Exchange Offer Registration Statement is declared effective but thereafter ceases to be effective or usable in connection with resales or exchanges of old notes during the periods specified in the Registration Rights Agreement.

Following the cure of all registration defaults, the accrual of additional interest will cease.

We are conducting the exchange offer to satisfy our obligations under the Registration Rights Agreement. If you participate in the exchange offer, you will, with limited exceptions, receive new notes that are freely tradable and not subject to special interest or transfer restrictions. You should read the discussion under "— Resale of the New Notes" for more information regarding your ability to transfer the new notes.

The exchange offer is not being made to, nor will we accept tenders for exchange from, holders of old notes in any jurisdiction in which the exchange offer or the acceptance of the exchange offer would not be in compliance with the securities laws or blue sky laws of such jurisdiction.

Terms of the Exchange Offer

We are offering, upon the terms and subject to the conditions set forth in this prospectus and the accompanying letter of transmittal, to exchange up to US$250,000,000 aggregate principal amount of the new notes for a like aggregate principal amount of outstanding old notes. We will accept for exchange any and all old notes that are properly tendered on or prior to 5 p.m., New York City time, on February 11, 2005, or such later time and date to which we extend the exchange offer. We will issue US$1,000 principal amount of the new notes in exchange for each US$1,000 principal amount of outstanding old notes accepted in the exchange offer. You may tender some or all of your old notes pursuant to the exchange offer; however, old notes may be tendered only in integral multiples of US$1,000 in principal amount.

As of the date of this prospectus, US$250,000,000 in aggregate principal amount of the old notes were outstanding. This prospectus, together with the letter of transmittal, is being sent to all holders of the old notes known to us. Our obligation to accept old notes for exchange pursuant to the exchange offer is subject to certain conditions as set forth below under "— Conditions to the Exchange Offer."

The Exchange Agent will act as agent for the tendering holders for the purpose of receiving the new notes from us. If any tendered old notes are not accepted for exchange because of an invalid tender or otherwise, certificates for the unaccepted old notes will be returned, without expense, to the tendering holder as promptly as practicable after the expiration date. Holders of the old notes do not have appraisal or dissenters' rights under the laws of the State of New York or the indenture. We intend to conduct the exchange offer in accordance with the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations under the Securities Act and the Exchange Act.

None of us, our board of directors and our management recommends that you tender or not tender your old notes in the exchange offer. In addition, no one has been authorized to make any such recommendation. You must make your own decision whether to participate in the exchange offer and, if you choose to participate, the aggregate principal amount of your old notes to tender, after carefully reading this prospectus and the letter of transmittal. We urge you to consult your financial and tax advisors in making your decision on what action to take.

Conditions to the Exchange Offer

You must tender your old notes in accordance with the requirements of this prospectus and the letter of transmittal to participate in the exchange offer. Notwithstanding any other provision of the exchange offer, or any extension of the exchange offer, we are not required to accept for exchange any old notes, and, we may terminate or amend the exchange offer, if we determine at any time prior to the expiration date, that the exchange offer violates applicable law or any applicable interpretation by the staff of the SEC of applicable law.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us:

•: the representations described under "— Procedures for Tendering Old Notes — Representations Made by Tendering Holders of Old Notes" and "Plan of Distribution;" and
•: any other representations reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the new notes under the Securities Act.

The foregoing conditions are for our sole benefit, and we may assert them regardless of the circumstances giving rise to any such condition, or we may waive the conditions, completely or partially, whenever or as many times as we may choose, in our sole discretion. Our failure at any time to exercise any of the above rights will not be a waiver of those rights, and each right will be deemed an ongoing right that may be asserted at any time. Any determination by us concerning the events described above will be final and binding upon all parties. If we determine that a waiver of conditions materially changes the exchange offer, this prospectus will be amended or supplemented, and the exchange offer extended, if appropriate, as described under "— Expiration Date; Extensions; Amendments."

In addition, at any time when any stop order is threatened or in effect with respect to the registration statement that includes this prospectus or with respect to the qualification of the indenture under the Trust

Indenture Act, we will not accept for exchange any old notes tendered, and no new notes will be issued in exchange for any such old notes.

Expiration Date; Extensions; Amendments

The expiration date of the exchange offer will be 5:00 p.m., New York City time, on February 11, 2005, unless we, in our sole discretion, extend the expiration date of the exchange offer. If we extend the expiration date of the exchange offer, the expiration date of the exchange offer will be the latest time and date to which the exchange offer is extended. We will notify the Exchange Agent by oral or written notice of any extension of the expiration date and make a public announcement of this extension no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

In addition, we expressly reserve the right, at any time or from time to time, at our sole discretion:

•: to delay the acceptance of the old notes;
•: to extend the exchange offer;
•: if we determine any condition to the exchange offer has not occurred or has not been satisfied, to terminate the exchange offer; and
•: to waive any condition or amend the terms of the exchange offer in any manner.

If the exchange offer is amended in a manner we deem to constitute a material change, we will as promptly as practicable distribute to the registered holders of the old notes a prospectus supplement that discloses the material change. If we take any of the actions described in the previous paragraph, we will as promptly as practicable give oral or written notice of this action to the Exchange Agent and will make a public announcement of this action.

During any extension of the exchange offer, all old notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any old notes not accepted for exchange for any reason will be returned without expense to the tendering holder as promptly as practicable after the expiration or termination of the exchange offer.

Procedures for Tendering Old Notes

Valid Tender

The tender of a holder's old notes and our acceptance of those old notes will constitute a binding agreement between the tendering holder and us upon the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal. Except as set forth below, if you wish to tender old notes pursuant to the exchange offer, you must, on or prior to the expiration date:

•: transmit a properly completed and duly executed letter of transmittal, together with all other documents required by the letter of transmittal, to the Exchange Agent at one of the addresses set forth below under "— Exchange Agent;"
•: arrange with DTC to cause an agent's message to be transmitted with the required information (including a book-entry confirmation) to the Exchange Agent at one of the addresses set forth below under "— Exchange Agent;" or
•: comply with the guaranteed delivery procedures described below.

In addition, on or prior to the expiration date:

•: the Exchange Agent must receive the certificates for the old notes, together with the properly completed and duly executed letter of transmittal;
•: the Exchange Agent must receive a timely confirmation of a book-entry transfer of the old notes being tendered into the Exchange Agent's account at DTC, together with the properly completed and duly executed letter of transmittal or an agent's message; or

•: the holder must comply with the guaranteed delivery procedures described below.

The letter of transmittal or agent's message may be delivered by mail, facsimile, hand delivery or overnight carrier to the Exchange Agent.

The term "agent's message" means a message transmitted to the Exchange Agent by DTC that states that DTC has received an express acknowledgment from a tender holder that it agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this tendering holder. The agent's message forms a part of book-entry transfer.

If you beneficially own old notes and those notes are registered in the name of a broker-dealer, commercial bank, trust company or other nominee or custodian, and you wish to tender your old notes in the exchange offer, you should contact the registered holder as soon as possible and instruct it to tender the old notes on your behalf and comply with the instructions set forth in this prospectus and the letter of transmittal.

If you tender fewer than all of your old notes, you should fill in the amount of the old notes tendered in the appropriate box in the letter of transmittal. If you do not indicate the amount tendered in the appropriate box, we will assume you are tendering all old notes that you hold.

The method of delivery of the certificates for the old notes, the letter of transmittal and all other documents is at your sole election and risk. Instead of delivery by mail, it is recommended that you use an overnight or hand delivery service. If delivery is by mail, it is recommended that you use registered mail, properly insured, with return receipt requested. In all cases, sufficient time should be allowed to assure timely delivery. No letters of transmittal or old notes should be sent directly to us. Delivery is complete when the Exchange Agent actually receives the items to be delivered. Delivery of documents to DTC in accordance with DTC' s procedures does not constitute delivery to the Exchange Agent.

Signature Guarantees

Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed unless the old notes surrendered for exchange are tendered:

•: by a registered holder of the old notes who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the letter of transmittal; or
•: for the account of an eligible institution.

An eligible institution is a firm or other entity that is a member of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States or any other "eligible guarantor institution" as this term is defined in Rule 17Ad under the Exchange Act.

If a signature on a letter of transmittal or a notice of withdrawal is required to be guaranteed, this guarantee must be by an eligible institution.

If the letter of transmittal is signed by a person other than the registered holder of the old notes, the old notes surrendered for exchange must be endorsed by, or be accompanied by a written instrument of transfer or exchange, in form satisfactory to us in our sole discretion, duly executed by, the registered holder, with the signature guaranteed by an eligible institution.

If the letter of transmittal is signed by a trustee, executor, administrator, guardian, attorney-in-fact, officer of a corporation or other person acting in a fiduciary or representative capacity, this person should sign in that capacity when signing. In addition, this person must submit to us, together with the letter of transmittal, evidence satisfactory to us in our sole discretion of his or her authority to act in this capacity, unless we waive this requirement.

Book-Entry Transfer

For tenders by book-entry transfer of old notes cleared through DTC, the Exchange Agent will make a request to establish an account at DTC with respect to the old notes for purposes of the exchange offer. Any

financial institution that is a DTC participant may make book-entry delivery of old notes by causing DTC to transfer the old notes into the Exchange Agent's account at DTC in accordance with DTC's procedures for transfer. The Exchange Agent and DTC have confirmed that any financial institution that is a participant in DTC may use the Automated Tender Offer Program procedures to tender old notes pursuant to the exchange offer. Accordingly, any DTC participant may make book-entry delivery of the old notes by causing DTC to transfer those old notes into the Exchange Agent's account in accordance with DTC's Automated Tender Offer Program procedures for transfer.

Although delivery of the old notes pursuant to the exchange offer may be effected through book-entry transfer at DTC, you will not have validly tendered your old notes pursuant to the exchange offer until, on or prior to the expiration date, either:

•: the properly completed and duly executed letter of transmittal, or an agent's message, together with any required signature guarantees and any other required documents, has been transmitted to and received by the Exchange Agent at one of the addresses set forth below under "— Exchange Agent;" or
•: the guaranteed delivery procedures described below have been complied with.

Guaranteed Delivery Procedures

If you wish to tender your old notes and:

•: your old notes are not immediately available;
•: time will not permit your old notes or other required documents to reach the Exchange Agent before the expiration date; or
•: you cannot complete the procedure for book-entry transfer on a timely basis;

you may tender your old notes according to the guaranteed delivery procedures described in the letter of transmittal.

Those procedures require that:

•: tender be made by and through an eligible institution;
•: on or prior to the expiration date, the Exchange Agent receive from this eligible institution a properly completed and duly executed letter of transmittal, or an agent's message, with any required signature guarantees, and a properly completed and duly executed notice of guaranteed delivery, substantially in the form provided:
•: setting forth the name and address of the holder of the old notes being tendered;
•: stating that the tender is being made; and
•: guaranteeing that within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery, the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, and any other documents required by the letter of transmittal, will be deposited by the eligible institution with the Exchange Agent; and
•: the Exchange Agent receives the certificates for the old notes, in proper form for transfer, or a book-entry confirmation, and all other documents required by the letter of transmittal, are received by the Exchange Agent within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery.

If you wish to tender your old notes pursuant to the guaranteed delivery procedures, you must ensure that the Exchange Agent receives a properly completed and duly executed letter of transmittal, or agent's message, and notice of guaranteed delivery before the expiration date.

Determination of Validity of Tender

We will resolve in our sole discretion all questions as to the validity, form, eligibility (including time of receipt) and acceptance of any old notes tendered for exchange. Our determination of these questions and our interpretation of the terms and conditions of the exchange offer, including without limitation the letter of transmittal and its instructions, shall be final and binding on all parties. A tender of old notes is invalid until all defects and irregularities have been cured or waived. Each holder must cure any and all defects or irregularities in connection with his, her or its tender of old notes within the reasonable period of time determined by us, unless we waive these defects or irregularities. None of us, our affiliates and assigns, the Exchange Agent and any other person is under any duty or obligation to give notice of any defect or irregularity with respect to any tender of the old notes, and none of them shall incur any liability for failure to give any such notice.

We reserve the absolute right in our sole and absolute discretion to:

•: reject any and all tenders of old notes determined to be in improper form or unlawful;
•: waive any condition of the exchange offer; and
•: waive any condition, defect or irregularity in the tender of old notes by any holder, whether or not we waive similar conditions, defects or irregularities in the case of other holders.

Representations Made by Tendering Holders of Old Notes

By tendering, you will represent to us that, among other things:

•: you are acquiring the new notes in the ordinary course of business;
•: you do not have any arrangement or understanding with any person or entity to participate in the distribution of the new notes;
•: if you are not a broker-dealer, you are not engaged in and do not intend to engage in a distribution of the new notes;
•: if you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will deliver a prospectus, as required by law, in connection with any resale of the new notes (see "Plan of Distribution"); and
•: you are not our "affiliate" as defined in Rule 405 of the Securities Act.

If you are our "affiliate," as defined under Rule 405 of the Securities Act, or are engaged in or intend to engage in or have an arrangement or understanding with any person to participate in a distribution of the new notes, you will represent and warrant that you (i) may not rely on the applicable interpretations of the staff of the SEC and (ii) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

In addition, in tendering old notes, you must warrant in the letter of transmittal or in an agent's message that:

•: you have full power and authority to tender, exchange, sell, assign and transfer old notes;
•: we will acquire good, marketable and unencumbered title to the tendered old notes, free and clear of all liens, restrictions, charges and other encumbrances; and
•: the old notes tendered for exchange are not subject to any adverse claims or proxies.

You must also warrant and agree that you will, upon request, execute and deliver any additional documents requested by us or the Exchange Agent to complete the exchange, sale, assignment and transfer of the old notes.

Acceptance of Old Notes; Delivery of New Notes

Upon satisfaction or waiver of all of the conditions to the exchange offer, we will accept all old notes validly tendered, and not withdrawn, on or prior to the expiration date. We will issue the new notes to the Exchange Agent as promptly as practicable after acceptance of the old notes. See "— Terms of the Exchange Offer."

For purposes of the exchange offer, we shall be deemed to have accepted validly tendered old notes for exchange when, as and if we have given oral or written notice of our acceptance to the Exchange Agent, with written confirmation of any oral notice to be given promptly thereafter.

Withdrawal Rights

You may withdraw tenders of your old notes at any time prior to the expiration date.

For a withdrawal to be effective, the Exchange Agent must receive a written notice of withdrawal from you. A notice of withdrawal must:

•: specify the name of the person tendering the old notes to be withdrawn;
•: identify the old notes to be withdrawn, including the total principal amount of these old notes; and
•: where certificates for the old notes have been transmitted, specify the name of the registered holder of the old notes, if different from the person withdrawing the tender of these old notes.

If you delivered or otherwise identified certificates representing old notes to the Exchange Agent, then you must also submit the serial numbers of the particular certificates to be withdrawn and, unless you are an eligible institution, the signature on the notice of withdrawal must be guaranteed by an eligible institution. If you tendered old notes as a book-entry transfer, your notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn old notes and otherwise comply with the procedures of DTC. You may not withdraw or rescind any notice of withdrawal; however, old notes properly withdrawn may again be tendered at any time on or prior to the expiration date.

We will determine, in our sole discretion, all questions as to the validity, form and eligibility (including time of receipt) of any and all notices of withdrawal, and our determination of these questions shall be final and binding on all parties. Any old notes properly withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offer and will be returned to the holder without cost as soon as practicable after their withdrawal.

Exchange Agent

The U.S. Bank National Association is the Exchange Agent for the exchange offer. You should direct all tendered old notes, executed letters of transmittal and other related documents to the Exchange Agent. You should direct all questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery to the Exchange Agent at the following addressed and telephone numbers:

By Mail, Hand or
Overnight Delivery:
U.S. Bank National Association
EP-MN-WS3C
60 Livingston Avenue
St. Paul, MN 55107
Attention: Richard H. Prokosch

By Facsimile for
Eligible Institutions:
Fax to: (651) 495-8097
Confirm by Telephone: (651) 495-3918

If you deliver executed letters of transmittal and any other required documents to an address or facsimile number other than those set forth above, your tender is invalid.

Fees and Expenses

We will bear the expenses of soliciting old notes for exchange. The principal solicitation is being made by mail by the Exchange Agent. Additional solicitations may be made by facsimile, telephone or in person by officers and regular employees of our company and our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to any broker, dealer, nominee or other person, other than the Exchange Agent, for soliciting tenders of the old notes pursuant to the exchange offer. We will pay the Exchange Agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

•: registration and filing fees;
•: fees and expenses of the Exchange Agent and trustee; and
•: accounting and legal fees and printing costs.

Your Failure to Participate in the Exchange Offer will Have Adverse Consequences

Following the consummation of the exchange offer, we will have fulfilled most of our obligations under the Registration Rights Agreement. Unless you are an initial purchaser or a holder of old notes who is prohibited by applicable law or SEC policy from participating in the exchange offer or who may not resell the new notes acquired in the exchange offer without delivering a prospectus and this prospectus is not appropriate or available for such resales by you, if you do not tender your old notes in the exchange offer or if we do not accept your old notes because you did not tender them properly, you will not have any further registration rights with respect to your old notes, and you will not have the right to receive any special interest on your old notes. In addition, your old notes will continue to be subject to restrictions on their transfer. In general, any old notes that are not exchanged for new notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

We may in the future seek to acquire unexchanged old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans, however, to acquire any unexchanged old notes or to file with the SEC a shelf registration statement to permit resales of any unexchanged old notes.

Resale of the new notes

Based on interpretations by the SEC staff set forth in no-action letters issued to third parties in similar transactions, such as Exxon Capital Holding Corporation and Morgan Stanley & Co. Incorporated, we believe that a holder of the new notes may offer the new notes for resale or resell or otherwise transfer the new notes without compliance with the registration and prospectus delivery requirements of the Securities Act, unless this holder:

•: is our "affiliate" within the meaning of Rule 405 under the Securities Act;
•: is a broker-dealer who purchased old notes directly from us for resale under Rule 144A or any other available exemption under the Securities Act;
•: acquired the new notes other than in the ordinary course of this holder's business; or
•: is participating, intends to participate or has an arrangement or understanding with any person to participate in the distribution of the new notes.

Accordingly, holders wishing to participate in the exchange offer must make the applicable representations described in "— Procedures for Tendering Old Notes — Representations Made by Tendering Holders of Old Notes" above.

Although we are making the exchange offer in reliance on the interpretations by the SEC staff set forth in these no-action letters, we do not intend to seek our own no-action letter from the SEC. Consequently, we cannot assure you that the SEC staff would make a similar determination with respect to the exchange offer as it did in its no-action letters to third parties. If this interpretation is inapplicable and you resell or otherwise transfer any new notes without complying with the registration and prospectus delivery requirements of the Securities Act, you may incur liability under the Securities Act. We do not assume or indemnify you against this liability.

You may not rely on the interpretations of the SEC staff in the above-described no-action letters if you are a holder of old notes who:

•: is our "affiliate" as defined in Rule 405 under the Securities Act;
•: does not acquire the new notes in the ordinary course of business;
•: tenders in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of the new notes; or
•: is a broker-dealer that purchased old notes from us to resell them pursuant to Rule 144A under the Securities Act or any other available exemption under the Securities Act, and

in the absence of an exemption, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale or other transfer of the new notes.

In addition, each broker-dealer that receives new notes for its own account in exchange for old notes that were acquired by it as a result of market-making activities or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of those new notes (see "Plan of Distribution"). Under the Registration Rights Agreement, we will be required to use our best efforts to keep the registration statement that includes this prospectus effective to allow these participating broker-dealers and other persons, if any, with similar prospectus delivery requirements to use this prospectus in connection with the resale of the new notes for the period that ends on the sooner of 180 days after the effectiveness of the registration statement that includes this prospectus and the date on which participating broker-dealers are no longer required to deliver a prospectus in connection with market-making or other trading activities.

In order to comply with state securities laws, the new notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification is available and is complied with.

The new notes are not being offered for sale and may not be offered or sold, directly or indirectly in Canada, or to any resident thereof, except in accordance with the securities laws of the provinces and territories of Canada. We are not required, and do not intend, to qualify by prospectus in Canada (other than in the province of Alberta) the new notes, and accordingly, the new notes will be subject to applicable restrictions on resale in Canada (other than in the province of Alberta).

DESCRIPTION OF THE NOTES

Harvest Operations Corp. issued the old notes under an Indenture, dated as of October 14, 2004, among Harvest Operations Corp., as issuer, Harvest Energy Trust, as guarantor, the Initial Subsidiary Guarantors, as guarantors, and U.S. Bank National Association, as trustee. The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended.

The following is a summary of the material provisions of the Indenture but does not restate the Indenture in its entirety. You can find the definitions of certain capitalized terms used in the following summary under the subheading "Definitions." We urge you to read the Indenture because it, and not this description, defines your rights as holders of the notes. A copy of the proposed form of Indenture is available upon request from Harvest Energy Trust. For purposes of this "Description of the Notes," the term "Trust" means Harvest Energy Trust and its successors under the Indenture and the term the "Issuer" means Harvest Operations Corp. and its successors under the Indenture, in each case excluding their subsidiaries.

General

The new notes will be issued by the Issuer, a wholly owned subsidiary of the Trust.

The new notes will be unsecured unsubordinated obligations of the Issuer, initially limited to US$250,000,000 aggregate principal amount. The new notes will mature on October 15, 2011. Subject to the covenants described below under "Certain Covenants" and applicable law, the Issuer may issue additional notes ("Additional Notes") under the Indenture. The new notes offered hereby are treated as a single class for all purposes under the Indenture.

Each new note will initially bear interest at the rate per annum shown on the cover page of this prospectus from the Closing Date or from the most recent interest payment date to which interest has been paid. Interest on the notes will be payable semiannually on April 15 and October 15 of each year, commencing April 15, 2005. Interest will be paid to Holders of record at the close of business on the April 1 or October 1 immediately preceding the Interest Payment Date. Interest is computed on the basis of a 360-day year of twelve 30-day months on a U.S. corporate bond basis.

The new notes will be issued only in fully registered form, without coupons, in denominations of US$1,000 of principal amount and multiples of US$1,000. See "Book-Entry; Delivery and Form." No service charge will be made for any registration of transfer or exchange of notes, but the Issuer may require payment of a sum sufficient to cover any transfer tax or other similar governmental charge payable in connection therewith.

Optional Redemption

The Issuer may redeem the notes at any time on or after October 15, 2008. The redemption price for the notes (expressed as a percentage of principal amount), will be as follows, plus accrued and unpaid interest to the redemption date:

If Redeemed During the 12-month period commencing		Redemption Price
October 15, 2008		103.938%
October 15, 2009		101.969%
October 15, 2010 and thereafter		100.000%

In addition, at any time prior to October 15, 2007, the Issuer may redeem up to 35% of the principal amount of the notes with the Net Cash Proceeds of one or more sales of Capital Stock (other than Disqualified Stock) of the Trust at a redemption price (expressed as a percentage of principal amount) of 107.875%, plus accrued and unpaid interest to the redemption date; provided that at least 65% of the aggregate principal amount of notes originally issued on the Closing Date remains outstanding after each such redemption and notice of any such redemption is mailed within 90 days of each such sale of Capital Stock.

In addition, before October 15, 2008, the Issuer may also redeem the notes at a redemption price equal to 103.938% plus accrued and unpaid interest to the redemption date, if, in the opinion of counsel, such

redemption is necessary to prevent the Trust from being disqualified as a unit trust or a mutual fund trust for the purposes of the Income Tax Act (Canada). If such redemption would result in less than 65% of the aggregate principal amount of notes originally issued under the indenture being outstanding, the Issuer shall be required to redeem all of the outstanding notes on the same terms.

The notes will also be subject to redemption in whole, but not in part, at the option of the Issuer at any time at 100% of the principal amount thereof, together with accrued and unpaid interest on the notes to the redemption date, if the Issuer has become or would become obligated to pay, on the next date on which any amount would be payable with respect to the notes, any Additional Amounts as a result of a change in the laws (including any regulations promulgated thereunder) of Canada (or any political subdivision or taxing authority thereof or therein), or any change in any official position regarding the application or interpretation of such laws or regulations, which change is announced or becomes effective on or after the date of this prospectus.

The Issuer will give not less than 30 days' nor more than 60 days' notice of any redemption. If less than all of the notes are to be redeemed, selection of the notes for redemption will be made by the Trustee:

•: in compliance with the requirements of the principal national securities exchange, if any, on which the notes are listed, or,
•: if the notes are not listed on a national securities exchange, by lot or by such other method as the Trustee in its sole discretion shall deem to be fair and appropriate.

However, no Note of US$1,000 in principal amount or less shall be redeemed in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount to be redeemed. A new Note in principal amount equal to the unredeemed portion will be issued upon cancellation of the original Note.

Guarantees

Payment of the principal of, premium, if any, and interest on the notes will be fully and unconditionally Guaranteed, jointly and severally, on an unsecured unsubordinated basis by each Wholly Owned Restricted Subsidiary (other than the Issuer) existing on the Closing Date. The Trust will fully and unconditionally Guarantee on an unsecured unsubordinated basis all obligations of the Issuer under the notes and each Subsidiary Guarantor under its Note Guarantee.

The obligations of the Trust under the Trust Guarantee and each Subsidiary Guarantor under its Note Guarantee will be limited so as not to constitute a fraudulent conveyance under applicable federal, provincial or state laws. Each Subsidiary Guarantor that makes a payment or distribution under its Note Guarantee will be entitled to contribution from any other Subsidiary Guarantor.

The Note Guarantee issued by any Subsidiary Guarantor will be automatically and unconditionally released and discharged upon (1) any sale, exchange or transfer to any Person (other than an Affiliate of the Trust) of all of the Capital Stock of such Subsidiary Guarantor, (2) the designation of such Subsidiary Guarantor as an Unrestricted Subsidiary or (3) such Subsidiary Guarantor expressly assuming as co-obligor all of the obligations of the Issuer under the Indenture, in each case in compliance with the terms of the Indenture.

Ranking

The notes will be equal in right of payment with all existing and future unsubordinated indebtedness of the Issuer and senior in right of payment to all future subordinated indebtedness of the Issuer. The Trust Guarantee will be equal in right of payment with all existing and future unsubordinated indebtedness of the Trust and senior in right of payment to all existing and future subordinated indebtedness of the Trust (other than the Caribou Debt). The Note Guarantees will be equal in right of payment with all existing and future unsubordinated indebtedness of the Subsidiary Guarantors and senior in right of payment to all future subordinated indebtedness of the Subsidiary Guarantors.

Claims of creditors of Subsidiaries of the Trust that are not Subsidiary Guarantors, including trade creditors and creditors holding Indebtedness or guarantees issued by such Subsidiaries, and claims of holders of preferred stock (if any) of such Subsidiaries generally, will have priority with respect to the assets and earnings of such

Subsidiaries over the claims of our creditors, including Holders. Accordingly, the notes will be effectively subordinated to creditors (including trade creditors) and holders of Preferred Stock, if any, of the Trust's Subsidiaries that are not Subsidiary Guarantors. The Trust's interest in the assets of the Redearth Partnership, which is not a Subsidiary Guarantor, was approximately $20 million as at September 30, 2004. In the future, the Company may have additional Subsidiaries that are not Subsidiary Guarantors.

As at September 30, 2004, (1) the Issuer would have had $418 million of Indebtedness, $83 million of which would have been secured indebtedness under the Credit Agreement; (2) the Trust would have had approximately $540 million of consolidated indebtedness outstanding, $83 million of which would have been secured guarantees outstanding under the Credit Agreement and $10.0 million of which would have been secured indebtedness outstanding under the Caribou Debt; (3) the Initial Subsidiary Guarantors would have had $418 million of indebtedness outstanding, $83 million of which would have been secured guarantees outstanding under the Credit Agreement; and (4) the Trust's interest in its only Subsidiary that is not guaranteeing the notes would not have had any indebtedness other than Indebtedness under the Credit Agreement on that date. The Credit Agreement is secured by substantially all of the assets of the Trust and its subsidiaries. The notes will be effectively subordinated to such indebtedness to the extent of such security interests.

The net proceeds from the issuance of the old notes was used to repay outstanding secured debt of Harvest Operations. On a pro forma basis, as at September 30, 2004 and after reflecting partial repayment of Harvest Operations' senior credit facility, the Trust had approximately $104.6 million of secured debt outstanding and the subsidiary guarantors had approximately $94.6 million secured debt outstanding.

Additional Amounts for Canadian Withholding Taxes

All payments made by the Issuer under or with respect to the notes, by the Trust pursuant to the Trust Guarantee or by any Subsidiary Guarantor pursuant to the Note Guarantees, will be made free and clear of and without withholding or deduction for or on account of any present or future tax, duty, levy, impost, assessment or other governmental charge (including penalties, interest and other liabilities related thereto) imposed or levied by or on behalf of the Government of Canada or of any province or territory thereof or by any authority or agency therein or thereof having power to tax (hereinafter, the "Taxes"), unless the Issuer, the Trust or such Subsidiary Guarantor, as the case may be, is required to withhold or deduct Taxes by law or by the interpretation or administration thereof. If the Issuer, the Trust or a Subsidiary Guarantor is required to withhold or deduct any amount for or on account of Taxes from any payment made under or with respect to the notes, the Issuer, the Trust or such Subsidiary Guarantor will pay such additional amounts (the "Additional Amounts") as may be necessary so that the net amount received by each Holder of notes (including Additional Amounts) after such withholding or deduction will not be less than the amount such Holder would have received if such Taxes had not been withheld or deducted; provided, however, that no Additional Amounts will be payable with respect to a payment made to a Holder (an "Excluded Holder") (i) with which the Issuer, the Trust or such Subsidiary Guarantor does not deal at arm's length (within the meaning of the Income Tax Act (Canada)) at the time of making such payment, (ii) which is subject to such Taxes by reason of its being connected with Canada or any province or territory thereof otherwise than solely by reason of the Holder's activity in connection with purchasing the notes, by the mere holding of notes or by reason of the receipt of payments thereunder, or (iii) which failed to duly and timely comply with a timely reasonable written request by the Trust, the Issuer or such Subsidiary Guarantor to provide documents required by law, if and to the extent that due and timely compliance with such request would have resulted in the reduction or elimination of any Taxes as to which Additional Amounts would have otherwise been payable to such Holder but for this clause (iii). The Issuer, the Trust or such Subsidiary Guarantor will also (a) make such withholding or deduction and (b) remit the full amount deducted or withheld to the relevant authority in accordance with applicable law.

The Issuer or the Trust will furnish the Holders of the notes, within 30 days after the date the payment of any Taxes is due pursuant to applicable law, certified copies of tax receipts evidencing such payment by the Issuer, the Trust or such Subsidiary Guarantor, or if receipts are not available, obtain other evidence of payment. The Issuer, the Trust or such Subsidiary Guarantor will, upon written request of each Holder (other than an Excluded Holder), reimburse each such Holder for the amount of (x) any Taxes so levied or imposed and paid by such Holder as a result of payments made under or with respect to the notes, and (y) any Taxes so levied or imposed with respect to any reimbursement under the foregoing clause (x) but excluding any such Taxes on such

Holder's net income so that the net amount received by such Holder (net of payments made under or with respect to the notes) after such reimbursement will not be less than the net amount the Holder would have received if Taxes on such reimbursement had not been imposed.

At least 30 days prior to each date on which any payment under or with respect to the notes is due and payable, if the Issuer will be obligated to pay Additional Amounts with respect to such payment, the Issuer will deliver to the Trustees an Officers' Certificate stating the fact that such Additional Amounts will be payable and the amounts so payable and will set forth such other information necessary to enable the Trustee to pay such Additional Amounts to Holders on the payment date. Whenever in the Indenture or in this "Description of the Notes" there is mentioned, in any context, the payment of principal, premium, if any, redemption price, purchase price, interest or any other amount payable under or with respect to any Note, such mention shall be deemed to include mention of the payment of Additional Amounts to the extent that, in such context, Additional Amounts are, were or would be payable in respect thereof.

Sinking Fund

There will be no sinking fund payments for the notes.

Certain Covenants

Overview

In the Indenture, the Trust will agree to covenants that limit its and its Restricted Subsidiaries' ability, among other things, to:

•: incur additional debt;
•: pay dividends, acquire capital stock, make payments on subordinated debt or make investments;
•: place limitations on distributions from Restricted Subsidiaries;
•: issue or sell capital stock of Restricted Subsidiaries;
•: issue guarantees;
•: sell or exchange assets;
•: enter into transactions with unitholders, shareholders and affiliates;
•: create liens; and
•: effect mergers.

In addition, if a Change of Control occurs, the Issuer will be obligated to make an offer to each Holder of notes to repurchase all or a part of the Holder's notes at a price equal to 101% of their principal amount, plus any accrued and unpaid interest to the date of repurchase.

Covenant Suspension

During any period of time that (a) the notes have Investment Grade Ratings and (b) no Default or Event of Default has occurred and is continuing under the Indenture, the Trust and its Restricted Subsidiaries will not be subject to

(1)

the provisions of the Indenture described under:

•: "— Limitation on Indebtedness;"
•: "— Limitation on Restricted Payments" (except to the extent applicable under the definition of "Unrestricted Subsidiary");
•: "— Limitation on Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries;"
•: "— Limitation on the Issuance and Sale of Capital Stock of Restricted Subsidiaries;"

•: "— Limitation on Transactions with Shareholders and Affiliates;"
•: "— Limitation on Asset Sales;"
•: "— Repurchase of Notes upon a Change of Control;" and
•: clauses (3) and (4) of "Consolidation, Amalgamation, Merger and Sale of Assets;" or

(2): clauses (c) and (d) under the caption "Events of Default" to the extent that such clauses apply to the covenants described in clause (1) above.

If the Trust and its Restricted Subsidiaries are not subject to these covenants for any period of time as a result of the previous sentence (a "Fall-Away Period") and, subsequently, the ratings assigned to the notes are withdrawn or downgraded so the notes no longer have Investment Grade Ratings or an Event of Default (other than with respect to a suspended covenant) occurs and is continuing, then the Trust and its Restricted Subsidiaries will thereafter again be subject to these covenants. The ability of the Trust and its Restricted Subsidiaries to make Restricted Payments after the time of such withdrawal, downgrade or Event of Default will be calculated as if the covenant governing Restricted Payments had been in effect during the entire period of time from the Closing Date. Notwithstanding the foregoing, the continued existence after the end of the Fall-Away Period of facts and circumstances or obligations arising from transactions which occurred during a Fall-Away Period shall not constitute a breach of any covenant set forth in the Indenture or cause an Event of Default thereunder; provided that (1) the Trust and its Restricted Subsidiaries did not incur or otherwise cause such facts and circumstances or obligations to exist in anticipation of (i) a ratings withdrawal or downgrade below Investment Grade Ratings or (ii) an Event of Default and (2) the Trust and its Restricted Subsidiaries did not reasonably believe that such transactions would result in such withdrawal or downgrade or Event of Default.

Limitation on Indebtedness

(a): The Trust will not, and will not permit any of its Restricted Subsidiaries to, Incur any Indebtedness (other than the notes, the Trust Guarantee, the Note Guarantees and other Indebtedness existing on the Closing Date after giving effect to the application of the proceeds of the notes); provided that the Trust, the Issuer or any Subsidiary Guarantor may Incur Indebtedness, if, after giving effect to the Incurrence of such Indebtedness and the receipt and application of the proceeds therefrom, the Interest Coverage Ratio would be greater than 2.5:1.

Notwithstanding the foregoing, the Trust and any Restricted Subsidiary (except as specified below) may Incur each and all of the following:

(1): Indebtedness under Credit Facilities of the Trust, the Issuer or any Restricted Subsidiary outstanding at any time in an aggregate principal amount (together with refinancings thereof) not to exceed the greater of (a) $275.0 million, less any amount of such Indebtedness permanently repaid as provided under the "Limitation on Asset Sales" covenant and (b) the Borrowing Base;
(2): Indebtedness owed (A) to the Trust, the Issuer or any Subsidiary Guarantor evidenced by an unsubordinated promissory note or (B) to any other Restricted Subsidiary; provided that (x) any event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any subsequent transfer of such Indebtedness (other than to the Trust or another Restricted Subsidiary) shall be deemed, in each case, to constitute an Incurrence of such Indebtedness not permitted by this clause (2) and (y) if the Trust, the Issuer or any Subsidiary Guarantor is the obligor on such Indebtedness, such Indebtedness must be subordinate in right of payment to the Trust Guarantee, in the case of the Trust, the notes, in the case of the Issuer, or the Note Guarantee, in the case of a Subsidiary Guarantor;
(3): Indebtedness issued in exchange for, or the net proceeds of which are used to refinance or repay, then outstanding Indebtedness (other than Indebtedness outstanding under clause (2), (5) or (9)) and any refinancings thereof in an amount not to exceed the amount so refinanced or repaid (plus premiums, accrued interest, fees and expenses); provided that (a) Indebtedness the proceeds of which are used to refinance or repay the notes or Indebtedness that is pari passu with, or subordinated in right of payment to, the notes, the Trust Guarantee or a Note Guarantee shall only be permitted under this clause (3) if (x) in case the notes are refinanced in part or the Indebtedness to be refinanced is pari passu with the notes, the

Trust Guarantee or a Note Guarantee, such new Indebtedness, by its terms or by the terms of any agreement or instrument pursuant to which such new Indebtedness is outstanding, is pari passu with, or subordinate in right of payment to, the remaining notes, the Trust Guarantee or the Note Guarantee, or (y) in case the Indebtedness to be refinanced is subordinated in right of payment to the notes, the Trust Guarantee or a Note Guarantee, such new Indebtedness, by its terms or by the terms of any agreement or instrument pursuant to which such new Indebtedness is issued or remains outstanding, is subordinate in right of payment to the notes, the Trust Guarantee or the Note Guarantee at least to the extent that the Indebtedness to be refinanced is subordinated to the notes, the Trust Guarantee or the Note Guarantee, (b) such new Indebtedness, determined as of the date of Incurrence of such new Indebtedness, does not mature prior to the Stated Maturity of the Indebtedness to be refinanced or repaid, and the Average Life of such new Indebtedness is at least equal to the remaining Average Life of the Indebtedness to be refinanced or repaid and (c) such new Indebtedness is Incurred by the Trust, the Issuer or a Subsidiary Guarantor or by the Restricted Subsidiary that is not a Subsidiary Guarantor who is the obligor on the Indebtedness to be refinanced or repaid;

(4)

Indebtedness of the Issuer or the Trust, to the extent the net proceeds thereof are promptly (A) used to purchase notes tendered in an Offer to Purchase made as a result of a Change in Control or (B) deposited to defease the notes as described under "Defeasance;"

(5)

(a) Guarantees of the notes and (b) Guarantees of Indebtedness of the Trust, the Issuer or any Subsidiary Guarantor by any Restricted Subsidiary provided the Guarantee of such Indebtedness is permitted by and made in accordance with the "Limitation on Issuance of Guarantees by Restricted Subsidiaries" covenant;

(6)

Indebtedness of the Trust, the Issuer or any Subsidiary Guarantor (in addition to Indebtedness permitted under clauses (1) through (5) above and (7) through (10) below) in an aggregate principal amount outstanding at any time (together with refinancings thereof) not to exceed $30.0 million;

(7)

Indebtedness of the Trust or the Issuer Incurred to satisfy the Trust's obligation to repurchase its trust units at the option of the holders thereof; provided that such Indebtedness shall be subordinate in right of payment to the Trust Guarantee or the notes, as applicable, and shall mature after the Stated Maturity of the notes;

(8)

Indebtedness incurred by the Trust, the Issuer or any Restricted Subsidiary represented by Capitalized Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of the Trust or such Restricted Subsidiary, in an aggregate principal amount outstanding at any time (together with refinancings thereof) not to exceed $15.0 million;

(9)

Indebtedness of the Trust or any of its Restricted Subsidiaries arising from the honoring by a bank of other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business; provided, however, that such Indebtedness is extinguished within five business days after receipt of notice of its incurrence; and

(10)

Indebtedness under the notes by a Subsidiary Guarantor Incurred upon such Subsidiary Guarantor assuming as co-obligor the obligations of the Issuer under the notes.

(b): Notwithstanding any other provision of this "Limitation on Indebtedness" covenant, the maximum amount of Indebtedness that may be Incurred pursuant to this "Limitation on Indebtedness" covenant will not be deemed to be exceeded, with respect to any outstanding Indebtedness due solely to the result of fluctuations in the exchange rates of currencies.
(c): For purposes of determining any particular amount of Indebtedness under this "Limitation on Indebtedness" covenant, (x) Indebtedness Incurred under the Credit Agreement on or prior to the Closing Date shall be treated as Incurred pursuant to clause (1) of the second paragraph of clause (a) of this "Limitation on Indebtedness" covenant, (y) Guarantees, Liens or obligations with respect to letters of credit supporting Indebtedness otherwise included in the determination of such particular amount shall not be included as Indebtedness and (z) any Liens granted pursuant to the equal and ratable provisions referred to in the "Limitation on Liens" covenant shall not be treated as

Indebtedness. For purposes of determining compliance with this "Limitation on Indebtedness" covenant, in the event that an item of Indebtedness meets the criteria of more than one of the types of Indebtedness described above (other than Indebtedness referred to in clause (x) of the preceding sentence), including under the first paragraph of part (a), the Trust, in its sole discretion, shall classify, and from time to time may reclassify, such item of Indebtedness.

(d): The Trust will not, and will not permit the Issuer to, Incur any Indebtedness (other than the Caribou Debt) if such Indebtedness is subordinate in right of payment to any other Indebtedness unless such Indebtedness is also subordinate in right of payment to the notes, in the case of the Issuer, or the Trust Guarantee, in the case of the Trust, to the same extent. The Trust will not permit a Subsidiary Guarantor to Incur any Indebtedness if such Indebtedness is subordinate in right of payment to any other Indebtedness unless such Indebtedness is also subordinate in right of payment to such Subsidiary Guarantor's Note Guarantee. For purposes of the foregoing, no Indebtedness (including the notes) will be deemed to be subordinate in right of payment to any other Indebtedness of the Trust, the Issuer or any Subsidiary Guarantor, as applicable, solely by virtue of being unsecured or by virtue of the fact that the holders of any secured Indebtedness have entered into intercreditor agreements giving one or more of such holders priority over the other holders in the collateral held by them.

Limitation on Restricted Payments

The Trust will not, and will not permit any Restricted Subsidiary to, directly or indirectly, (1) declare or pay any dividend or make any distribution on or with respect to its Capital Stock (other than (x) dividends or distributions payable solely in its Capital Stock (other than Disqualified Stock) or in options, warrants or other rights to acquire such Capital Stock and (y) pro rata dividends or distributions on Common Stock of Restricted Subsidiaries (other than the Issuer or Subsidiary Guarantors) held by minority equityholders) held by Persons other than the Trust or any of its Restricted Subsidiaries, (2) purchase, call for redemption or redeem, retire or otherwise acquire for value any Capital Stock of the Trust, the Issuer or any Subsidiary Guarantor (including options, warrants or other rights to acquire such Capital Stock) held by any Person (other than the Trust, the Issuer or a Subsidiary Guarantor), (3) make any voluntary or optional principal payment, or voluntary or optional redemption, repurchase, defeasance, or other voluntary or optional acquisition or retirement for value, of any Indebtedness of (i) the Issuer that is subordinated in right of payment to the notes, (ii) the Trust that is subordinated in right of payment to the Trust Guarantee, or (iii) a Subsidiary Guarantor that is subordinated in right of payment to a Note Guarantee or (4) make any Investment, other than a Permitted Investment, in any Person (such payments or any other actions described in clauses (1) through (4) above being collectively "Restricted Payments") unless, at the time of, and after giving effect to, the proposed Restricted Payment:

(A): no Default or Event of Default shall have occurred and be continuing, and
(B): the Trust could Incur at least $1.00 of Indebtedness under the first paragraph of part (a) of the "Limitation on Indebtedness" covenant, the Consolidated Leverage Ratio is less than 3.0:1 and the Restricted Payment, together with the aggregate of all other Restricted Payments made during the fiscal quarter during which the Restricted Payment is made, shall not exceed 80% of Available Cash for the immediately preceding fiscal quarter.

The foregoing provision shall not be violated by reason of:

(1): the payment of any dividend, distribution on or redemption of any Capital Stock within 60 days after the related date of declaration of a dividend or distribution or call for redemption if, at said date of declaration of a dividend or distribution or call for redemption, such payment or redemption would comply with the preceding paragraph;
(2): the redemption, repurchase, defeasance or other acquisition or retirement for value of Indebtedness that is subordinated in right of payment to the notes, the Trust Guarantee or any Note Guarantee including premium, if any, and accrued interest, with the proceeds of, or in exchange for, Indebtedness Incurred under clause (3) of the second paragraph of part (a) of the "Limitation on Indebtedness" covenant;

(3): the repurchase, redemption or other acquisition of Capital Stock of the Trust, the Issuer or a Subsidiary Guarantor (or options, warrants or other rights to acquire such Capital Stock) in exchange for, or out of the proceeds of a capital contribution or a substantially concurrent offering of, Capital Stock (other than Disqualified Stock) of the Trust (or options, warrants or other rights to acquire such Capital Stock); provided that such options, warrants or other rights are not redeemable at the option of the holder, or required to be redeemed, prior to the Stated Maturity of the notes;
(4): the making of any principal payment at its Stated Maturity or the repurchase, redemption, retirement, defeasance or other acquisition for value prior to its Stated Maturity of Indebtedness which is subordinated in right of payment to the notes, the Trust Guarantee or any Note Guarantee in exchange for, or out of the proceeds of a capital contribution or a substantially concurrent offering of, Capital Stock (other than Disqualified Stock) of the Trust (or options, warrants or other rights to acquire such Capital Stock); provided that such options, warrants or other rights are not redeemable at the option of the holder, or required to be redeemed, prior to the Stated Maturity of the notes;
(5): payments or distributions to dissenting unitholders pursuant to applicable law, pursuant to or in connection with a consolidation, amalgamation, merger or transfer of assets of the Trust that complies with the provisions of the Indenture applicable to mergers, consolidations, amalgamations and transfers of all or substantially all of the property and assets of the Trust;
(6): Investments acquired as a capital contribution to, or in exchange for, Capital Stock (other than Disqualified Stock) of the Trust;
(7): the repurchase of Capital Stock deemed to occur upon the exercise of options or warrants if such Capital Stock represents all or a portion of the exercise price thereof;
(8): the redemption of the Trust's trust units at the option of the holders thereof; provided that (a) in any calendar month, the Trust shall not redeem units for more than $100,000 in cash and (b) such other redemptions shall be in exchange for Indebtedness of the Trust or the Issuer that shall be subordinate in right of payment to the Trust Guarantee or the notes, as applicable, and shall mature after the Stated Maturity of the notes;
(9): the making of any Restricted Payment which, together with the aggregate amount of Restricted Payments made after the Closing Date pursuant to this clause (9) or the next paragraph, shall not exceed an amount equal to the Unpaid Restricted Payments Basket plus the aggregate Net Cash Proceeds received by the Trust after the Closing Date as a capital contribution or from the issuance and sale of its Capital Stock (other than Disqualified Stock) to a Person who is not a Subsidiary of the Trust, including an issuance or sale permitted by the Indenture of Indebtedness of the Trust for cash subsequent to the Closing Date upon the conversion of such Indebtedness into Capital Stock (other than Disqualified Stock) of the Trust, or from the issuance to a Person who is not a Subsidiary of the Trust of any options, warrants or other rights to acquire Capital Stock of the Trust (in each case, exclusive of any Disqualified Stock or any options, warrants or other rights that are redeemable at the option of the holder, or are required to be redeemed, prior to the Stated Maturity of the notes); and
(10): the repurchase, redemption or other defeasance of Disqualified Stock pursuant to its terms, utilizing the cash proceeds from the sale of such Disqualified Stock that have been held on a segregated basis for the benefit of the purchasers of such Disqualified Stock from the date of the sale pending such repurchase, redemption or other defeasance;

provided that, except in the case of clauses (1) and (3), no Default or Event of Default shall have occurred and be continuing or occur as a consequence of the actions or payments set forth therein.

Each Restricted Payment permitted pursuant to the preceding paragraph (other than the Restricted Payment referred to in clause (2) or (10) thereof, an exchange of Capital Stock for Capital Stock or Indebtedness referred to in clause (3) or (4) thereof and an Investment acquired as a capital contribution or in exchange for Capital Stock referred to in clause (6) thereof), and the Net Cash Proceeds from any issuance of Capital Stock referred to in clauses (3), (4) or (6), shall be included in calculating whether the conditions of clause (B) of the first paragraph or clause (9) of the second paragraph of this "Limitation on Restricted

Payments" covenant have been met with respect to any subsequent Restricted Payments. In the event the proceeds of an issuance of Capital Stock of the Trust are used for the redemption, repurchase or other acquisition of Indebtedness that is pari passu with the notes, the Trust Guarantee or any Subsidiary Guarantee, then the Net Cash Proceeds of such issuance shall be included in clause (9) of the second paragraph of this "Limitation on Restricted Payments" covenant only to the extent such proceeds are not used for such redemption, repurchase or other acquisition of Indebtedness.

For purposes of determining compliance with this "Limitation on Restricted Payments" covenant, the amount, if other than in cash, of any Restricted Payment shall be determined in good faith by the Board of Directors of the Issuer, whose determination shall be conclusive and evidenced by a Board Resolution.

Limitation on Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

The Trust will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or suffer to exist or become effective any consensual encumbrance or restriction of any kind on the ability of any Restricted Subsidiary to (1) pay dividends or make any other distributions permitted by applicable law on any Capital Stock of such Restricted Subsidiary owned by the Trust or any other Restricted Subsidiary, (2) pay any Indebtedness owed to the Trust or any other Restricted Subsidiary, (3) make loans or advances to the Trust or any other Restricted Subsidiary or (4) transfer any of its property or assets to the Trust or any other Restricted Subsidiary.

The foregoing provisions shall not restrict any encumbrances or restrictions:

(1)

existing on the Closing Date in the Credit Agreement, the Indenture or any other agreements in effect on the Closing Date, and any extensions, refinancings, renewals or replacements of such agreements; provided that the encumbrances and restrictions in any such extensions, refinancings, renewals or replacements taken as a whole are no less favorable in any material respect to the Holders than those encumbrances or restrictions that are then in effect and that are being extended, refinanced, renewed or replaced as determined in good faith by the Board of Directors of the Issuer;

(2)

under or by reason of applicable law;

(3)

with respect to any Person or the property or assets of such Person acquired by the Trust or any Restricted Subsidiary, existing at the time of such acquisition and not incurred in contemplation thereof, which encumbrances or restrictions are not applicable to any Person or the property or assets of any Person other than such Person or the property or assets of such Person so acquired and any extensions, refinancings, renewals or replacements of thereof; provided that the encumbrances and restrictions in any such extensions, refinancings, renewals or replacements taken as a whole are no less favorable in any material respect to the Holders than those encumbrances or restrictions that are then in effect and that are being extended, refinanced, renewed or replaced as determined in good faith by the Board of Directors of the Issuer;

(4)

in the case of clause (4) of the first paragraph of this "Limitation on Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries" covenant:

(A): that restrict in a customary manner the subletting, assignment or transfer of any property or asset that is a lease, license, conveyance or contract or similar property or asset,
(B): existing by virtue of any transfer of, agreement to transfer, option or right with respect to, or Lien on, any property or assets of the Trust or any Restricted Subsidiary not otherwise prohibited by the Indenture or
(C): arising or agreed to in the ordinary course of business, not relating to any Indebtedness, and that do not, individually or in the aggregate, detract from the value of property or assets of the Trust or any Restricted Subsidiary in any manner material to the Trust or any Restricted Subsidiary;

(5)

with respect to a Restricted Subsidiary and imposed pursuant to an agreement that has been entered into for the sale or disposition of all or substantially all of the Capital Stock of, or property and assets of, such Restricted Subsidiary; or

(6)

contained in the Exchangeable Shares.

Limitation on the Issuance and Sale of Capital Stock of Restricted Subsidiaries

The Trust will not sell, and will not permit any Restricted Subsidiary, directly or indirectly, to issue or sell, any Capital Stock of a Restricted Subsidiary (including options, warrants or other rights to purchase such Capital Stock) except:

(1): to the Trust or a Wholly Owned Restricted Subsidiary;
(2): issuances of director's qualifying shares or sales to foreign nationals of Capital Stock of foreign Restricted Subsidiaries, to the extent required by applicable law;
(3): with respect to a Restricted Subsidiary, if, immediately after giving effect to such issuance or sale, such Restricted Subsidiary would no longer constitute a Restricted Subsidiary and any Investment in such Person remaining after giving effect to such issuance or sale would have been permitted to be made under the "Limitation on Restricted Payments" covenant if made on the date of such issuance or sale;
(4): issuances of Capital Stock by a non-Wholly Owned Restricted Subsidiary to all holders of its Capital Stock on a pro rata basis; or
(5): issuances of Exchangeable Shares by the Issuer.

Limitation on Issuances of Guarantees by Restricted Subsidiaries

The Trust will not permit any Restricted Subsidiary (other than the Issuer or a Subsidiary Guarantor), directly or indirectly, to Guarantee any Indebtedness ("Guaranteed Indebtedness") of the Trust or any other Restricted Subsidiary (other than Indebtedness permitted to be Incurred under clause (1) of the second paragraph of the "Limitation on Indebtedness" covenant), unless (a) such Restricted Subsidiary simultaneously executes and delivers a supplemental indenture to the Indenture providing for a Guarantee of payment of the notes by such Restricted Subsidiary and (b) such Restricted Subsidiary waives and will not in any manner whatsoever claim or take the benefit or advantage of, any rights of reimbursement, indemnity or subrogation or any other rights against the Trust or any other Restricted Subsidiary as a result of any payment by such Restricted Subsidiary under its Note Guarantee until the notes have been paid in full.

If the Guaranteed Indebtedness is (A) pari passu in right of payment with the notes or any Note Guarantee, then the Guarantee of such Guaranteed Indebtedness shall be pari passu in right of payment with, or subordinated to, the Note Guarantee or (B) subordinated in right of payment to the notes or any Note Guarantee, then the Guarantee of such Guaranteed Indebtedness shall be subordinated in right of payment to the Note Guarantee at least to the extent that the Guaranteed Indebtedness is subordinated to the notes or the Note Guarantee.

Notwithstanding the foregoing, any Note Guarantee by a Restricted Subsidiary may provide by its terms that it shall be automatically and unconditionally released and discharged upon

(1): any sale, exchange or transfer, to any Person not an Affiliate of the Trust, of all of the Trust's and each Restricted Subsidiary's Capital Stock in such Restricted Subsidiary (which sale, exchange or transfer is not prohibited by the Indenture) or upon the designation of such Restricted Subsidiary as an Unrestricted Subsidiary in accordance with the terms of the Indenture;
(2): the release or discharge of the Guarantee which resulted in the creation of such Note Guarantee, except a discharge or release by or as a result of payment under such Guarantee; or
(3): the execution of a supplemental indenture to the Indenture by such Subsidiary Guarantor expressly assuming as co-obligor all of the obligations of the Issuer under the Indenture and the notes.

Limitation on Transactions with Shareholders and Affiliates

The Trust will not, and will not permit any Restricted Subsidiary to, directly or indirectly, enter into, renew or extend any transaction (including, without limitation, the purchase, sale, lease or exchange of property or assets, or the rendering of any service) with any holder (or any Affiliate of such holder) of 5% or more of any class of Capital Stock of the Trust or with any Affiliate of the Trust or any Restricted Subsidiary, except upon fair

and reasonable terms no less favorable to the Trust or such Restricted Subsidiary than could be obtained, at the time of such transaction or, if such transaction is pursuant to a written agreement, at the time of the execution of the agreement providing therefor, in a comparable arm's-length transaction with a Person that is not such a holder or an Affiliate.

The foregoing limitation does not limit, and shall not apply to:

(1): transactions (A) approved by a majority of the disinterested members of the Board of Directors or (B) for which the Trust or a Restricted Subsidiary delivers to the Trustee a written opinion of a nationally recognized investment banking, accounting, valuation or appraisal firm in Canada or the United States stating that the transaction is fair to the Trust or such Restricted Subsidiary from a financial point of view;
(2): any transaction solely between the Trust and any of its Restricted Subsidiaries or solely among Restricted Subsidiaries;
(3): the payment of reasonable and customary regular fees to trustees and directors of the Trust or the Issuer who are not employees of the Trust or the Issuer and indemnification arrangements entered into by the Trust or the Issuer consistent with past practices of the Trust or the Issuer;
(4): any sale of Capital Stock (other than Disqualified Stock) of the Trust;
(5): any transaction pursuant to any agreement in existence on the Closing Date and disclosed in the Offering Prospectus, or any amendment, replacement or refinancing thereof that, taken in its entirety, is no less favorable to the Trust and its Restricted Subsidiaries than such agreement in effect on the Closing Date;
(6): any sale of securities (other than Capital Stock but including Disqualified Stock) made on substantially the same terms as available to the public; or
(7): Restricted Payments not prohibited by the "Limitation on Restricted Payments" covenant.

Notwithstanding the foregoing, any transaction or series of related transactions covered by the first paragraph of this "Limitation on Transactions with Shareholders and Affiliates" covenant and not covered by clauses (2) through (7) of this paragraph, (a) the aggregate amount of which is up to $10.0 million in value, need not be approved or determined to be fair in the manner provided for in clause (1)(A) or (B) above; (b) the aggregate amount of which exceeds $10.0 million in value, must be approved or determined to be fair in the manner provided for in clause (1)(A) or (B) above and (C) the aggregate amount of which exceeds $25.0 million in value, must be determined to be fair in the manner provided for in clause (1)(B) above.

Limitation on Liens

The Trust will not, and will not permit any Restricted Subsidiary to, create, incur, assume or suffer to exist any Lien on any of its assets or properties of any character, or any Capital Stock or Indebtedness of any Restricted Subsidiary, without making effective provision for all of the notes and all other amounts due under the Indenture to be directly secured equally and ratably with (or, if the obligation or liability to be secured by such Lien is subordinated in right of payment to the notes, prior to) the obligation or liability secured by such Lien.

The foregoing limitation does not apply to:

(1): Liens existing on the Closing Date (other than Liens securing Indebtedness under the Credit Agreement or the Caribou Debt);
(2): Liens granted after the Closing Date on any assets or Capital Stock of the Trust or its Restricted Subsidiaries created in favor of the Holders;
(3): Liens securing Indebtedness which is Incurred to refinance secured Indebtedness which is permitted to be Incurred under clause (3) of the second paragraph of the "Limitation on Indebtedness" covenant; provided that such Liens do not extend to or cover any property or assets of the Trust or any Restricted Subsidiary other than the property or assets securing the Indebtedness being refinanced;

(4): Liens to secure Indebtedness which is permitted to be Incurred under clause (1) of the second paragraph of the "Limitation on Indebtedness" covenant;
(5): Liens (including extensions and renewals thereof) upon real or personal property acquired after the Closing Date; provided that (a) such Lien is created solely for the purpose of securing Indebtedness Incurred, in accordance with the "Limitation on Indebtedness" covenant, to finance the cost (including the cost of improvement or construction) of the item of property or assets subject thereto and such Lien is created prior to, at the time of or within six months after the later of the acquisition, the completion of construction or the commencement of full operation of such property (b) the principal amount of the Indebtedness secured by such Lien does not exceed 100% of such cost and (c) any such Lien shall not extend to or cover any property or assets other than such item of property or assets and any improvements on such item;
(6): Liens on cash set aside at the time of the Incurrence of any Indebtedness, or government securities purchased with such cash, in either case to the extent that such cash or government securities pre-fund the payment of interest on such Indebtedness and are held in a collateral or escrow account or similar arrangement to be applied for such purpose;
(7): Liens securing Indebtedness permitted by clause (9) of the definition of "Permitted Investment", provided that such Liens shall not extend beyond the interest in the Redearth Partnership of, and an undivided interest in assets of the Redearth Partnership corresponding to such interests of, a partner that is not the Trust or a Restricted Subsidiary; or
(8): Permitted Liens.

Limitation on Sale-Leaseback Transactions

The Trust will not, and will not permit any Restricted Subsidiary to, enter into any sale-leaseback transaction involving any of its assets or properties whether now owned or hereafter acquired, whereby the Trust or a Restricted Subsidiary sells or transfers such assets or properties and then or thereafter leases such assets or properties or any part thereof or any other assets or properties which the Trust or such Restricted Subsidiary, as the case may be, intends to use for substantially the same purpose or purposes as the assets or properties sold or transferred.

The foregoing restriction does not apply to any sale-leaseback transaction if:

(1): the lease is for a period, including renewal rights, of not in excess of three years;
(2): the lease secures or relates to industrial revenue or pollution control bonds;
(3): the transaction is solely between the Trust and any Wholly Owned Restricted Subsidiary or solely between Wholly Owned Restricted Subsidiaries;
(4): the Trust or such Restricted Subsidiary, within 12 months after the sale or transfer of any assets or properties is completed, applies an amount not less than the net proceeds (net of any pro rata payment of proceeds to other holders of Capital Stock of a non-Wholly Owned Restricted Subsidiary) received from such sale in accordance with clause (A) or (B) of the second paragraph of the "Limitation on Asset Sales" covenant; or
(5): it relates to any single transaction or series of related transactions that involve assets having a fair market value of less than $5.0 million or the Trust or the Restricted Subsidiary receives aggregate consideration of less than $5.0 million.

Limitation on Asset Sales

The Trust will not, and will not permit any Restricted Subsidiary to, consummate any Asset Sale, unless (1) the consideration received by the Trust or such Restricted Subsidiary is at least equal to the fair market value of the assets sold or disposed of and (2) at least 75% of the consideration received consists of (a) cash or Temporary Cash Investments, (b) the assumption of unsubordinated Indebtedness of the Trust, the Issuer or any Subsidiary Guarantor or Indebtedness of any other Restricted Subsidiary (in each case, other than Indebtedness

owed to the Trust or any Affiliate of the Trust), provided that the Trust, the Issuer, such Subsidiary Guarantor or such other Restricted Subsidiary is irrevocably and unconditionally released from all liability under such Indebtedness or (c) Replacement Assets.

In the event and to the extent that the Net Cash Proceeds received by the Trust or any of its Restricted Subsidiaries from one or more Asset Sales occurring on or after the Closing Date in any period of 12 consecutive months exceed 10% of the Borrowing Base (determined as of the date closest to the commencement of such 12-month period for which a consolidated balance sheet of the Trust and its Subsidiaries has been filed with the SEC or provided to the Trustee), then the Trust shall or shall cause the relevant Restricted Subsidiary to:

(1)

within twelve months after the date Net Cash Proceeds so received exceed 10% of the Borrowing Base,

(A): apply an amount equal to such excess Net Cash Proceeds to permanently repay Indebtedness of the Trust, the Issuer or any Subsidiary Guarantor under the Credit Agreement or Indebtedness of any other Restricted Subsidiary, in each case owing to a Person other than the Trust or any Affiliate of the Trust, or
(B): invest an equal amount, or the amount not so applied pursuant to clause (A) (or enter into a definitive agreement committing to so invest within 12 months after the date of such agreement), in Replacement Assets, and

(2)

apply (no later than the end of the 12-month period referred to in clause (1)) such excess Net Cash Proceeds (to the extent not applied pursuant to clause (1)) as provided in the following paragraphs of this "Limitation on Asset Sales" covenant.

The amount of such excess Net Cash Proceeds required to be applied (or to be committed to be applied) during such 12-month period as set forth in clause (1) of the preceding sentence and not applied as so required by the end of such period shall constitute "Excess Proceeds."

If, as of the first day of any calendar month, the aggregate amount of Excess Proceeds not theretofore subject to an Offer to Purchase pursuant to this "Limitation on Asset Sales" covenant totals at least US$20.0 million, the Issuer (and the Trust with respect to any Pari Passu Indebtedness of the Trust) must commence, not later than the fifteenth Business Day of such month, and consummate an Offer to Purchase from the Holders (and if required by the terms of any Indebtedness that is pari passu with the notes or the Trust Guarantee ("Pari Passu Indebtedness"), from the holders of such Pari Passu Indebtedness) on a pro rata basis an aggregate principal amount of notes (and Pari Passu Indebtedness) equal to the Excess Proceeds on such date, at a purchase price equal to 100% of their principal amount, plus, in each case, accrued and unpaid interest (if any) to the Payment Date.

Repurchase of Notes upon a Change of Control

The Issuer must commence, within 30 days of the occurrence of a Change of Control, and thereafter complete an Offer to Purchase for all notes then outstanding, at a purchase price equal to 101% of their principal amount, plus accrued interest (if any) to the Payment Date.

There can be no assurance that the Issuer will have sufficient funds available at the time of any Change of Control to make any debt payment (including repurchases of notes) required by the foregoing covenant (as well as may be contained in other securities of the Issuer which might be outstanding at the time).

The above covenant requiring the Issuer to repurchase the notes will, unless consents are obtained, require the Trust to repay, or cause to be repaid, all indebtedness then outstanding which by its terms would prohibit such Note repurchase, either prior to or concurrently with such Note repurchase.

The Issuer will not be required to make an Offer to Purchase upon the occurrence of a Change of Control, if a third party makes an offer to purchase the notes in the manner, at the times and price and otherwise in compliance with the requirements of the Indenture applicable to an Offer to Purchase for a Change of Control and purchases all notes validly tendered and not withdrawn in such offer to purchase.

SEC Reports and Reports to Holders

Whether or not required by the SEC, so long as any notes are outstanding, the Trust will furnish, or cause the trustee to furnish, to the Holders, within the time periods specified in the SEC's rules and regulations:

(1)

(a) all annual financial information that would be required to be contained in a filing with the SEC on Forms 20-F or 40-F, as applicable (or any successor forms), containing the information required therein (or required in such successor form) including a report on the annual financial statements by the Trust's certified independent accountants; and

(b): for the first three quarters of each year, all quarterly financial information that would be required to be contained in quarterly reports under the laws of Canada or any province thereof or provided to securityholders of a company with securities listed on the Toronto Stock Exchange, whether or not the Company has any of its securities so listed,

in each case including a "Management's Discussion and Analysis of Financial Condition and Results of Operations"; and

(2): all information that would otherwise be required to be filed with the SEC on Form 6-K if the Trust were required to file such reports and the Trust were a reporting issuer under the securities laws of Alberta or Ontario.

If, at any time after the Registration, the Trust is no longer subject to the periodic reporting requirements of the Securities Exchange Act of 1934 for any reason, the Trust will nevertheless continue filing the reports specified in the preceding paragraph with the SEC within the time periods specified above unless the SEC will not accept such a filing. The Trust agrees that it will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the forgoing, the SEC will not accept the Trust's filings for any reason, the Trust will post the reports and other information referred to in the preceding paragraph on its website within the time periods that would apply if the Trust were required to file those reports with the SEC. In addition, at all times prior to the Registration, upon the request of any Holder or any prospective purchaser of the notes designated by a Holder, the Trust shall supply to such Holder or such prospective purchaser the information required under Rule 144A under the Securities Act.

Events of Default

The following events will be defined as "Events of Default" in the Indenture:

(a): default in the payment of principal of (or premium, if any, on) any Note when the same becomes due and payable at maturity, upon acceleration, redemption or otherwise;
(b): default in the payment of interest on any Note when the same becomes due and payable, and such default continues for a period of 30 days;
(c): default in the performance or breach of the provisions of the Indenture applicable to mergers, consolidations, amalgamations and transfers of all or substantially all of the assets of the Trust or the failure by the Issuer to make or consummate an Offer to Purchase in accordance with the "Limitation on Asset Sales" or "Repurchase of Notes upon a Change of Control" covenant;
(d): the Trust, the Issuer or any Subsidiary Guarantor defaults in the performance of or breaches any other covenant or agreement in the Indenture or under the notes (other than a default specified in clause (a), (b) or (c) above) and such default or breach continues for a period of 60 consecutive days after written notice by the Trustee or the Holders of 25% or more in aggregate outstanding principal amount of the notes;
(e): there occurs with respect to any issue or issues of Indebtedness of the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary having an outstanding principal amount of $20.0 million or more in the aggregate for all such issues of all such Persons, whether such Indebtedness now exists or shall hereafter be created, (I) an event of default that has caused the holder thereof to declare such Indebtedness to be due and payable prior to its Stated Maturity and such Indebtedness has not been discharged in full or such acceleration has not been rescinded or

annulled within 30 days of such acceleration and/or (II) the failure to make a principal payment at the final (but not any interim) fixed maturity and such defaulted payment shall not have been made, waived or extended within 30 days of such payment default;

(f): any final judgment or order (not covered by insurance) for the payment of money in excess of $20.0 million in the aggregate for all such final judgments or orders against all such Persons (treating any deductibles, self-insurance or retention as not so covered) shall be rendered against the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary and shall not be paid, bonded or discharged, and there shall be any period of 30 consecutive days following entry of the final judgment or order that causes the aggregate amount for all such final judgments or orders outstanding and not paid, bonded or discharged against all such Persons to exceed $20.0 million during which a stay of enforcement of such final judgment or order, by reason of a pending appeal or otherwise, shall not be in effect;
(g): a court having jurisdiction in the premises enters a decree or order for (A) relief in respect of the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary in an involuntary case under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect, (B) appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official of the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or for all or substantially all of the property and assets of the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or (C) the winding up or liquidation of the affairs of the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary and, in each case, such decree or order shall remain unstayed and in effect for a period of 30 consecutive days;
(h): the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary (A) commences a voluntary case under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect, or consents to the entry of an order for relief in an involuntary case under any such law, (B) consents to the appointment of or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official of the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or for all or substantially all of the property and assets of the Trust, the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or (C) effects any general assignment for the benefit of creditors; or
(i): the Trust repudiates its obligations under the Trust Guarantee, any Subsidiary Guarantor repudiates its obligations under its Note Guarantee or, except as permitted by the Indenture, any Note Guarantee is determined to be unenforceable or invalid or shall for any reason cease to be in full force and effect and, with respect to a Subsidiary Guarantor that is not, or a group of Restricted Subsidiaries that are not Subsidiary Guarantors that together would constitute, a Significant Subsidiary, such default continues for a period of 30 days.

If an Event of Default (other than an Event of Default specified in clause (g) or (h) above that occurs with respect to the Trust, the Issuer or any Subsidiary Guarantor) occurs and is continuing under the Indenture, the Trustee or the Holders of at least 25% in aggregate principal amount of the notes, then outstanding, by written notice to the Issuer (and to the Trustee if such notice is given by the Holders), may, and the Trustee at the request of such Holders shall, declare the principal of, premium, if any, and accrued interest on the notes to be immediately due and payable. Upon a declaration of acceleration, such principal of, premium, if any, and accrued interest shall be immediately due and payable. In the event of a declaration of acceleration because an Event of Default set forth in clause (e) or (f) above has occurred and is continuing, such declaration of acceleration shall be automatically rescinded and annulled if the event of default triggering such Event of Default pursuant to clause (e) or (f) shall be remedied or cured by the Trust, the Issuer, the relevant Subsidiary Guarantor or the relevant Significant Subsidiary or waived by the applicable holders of the relevant Indebtedness within 60 days after the declaration of acceleration with respect thereto. If an Event of Default specified in clause (g) or (h) above occurs with respect to the Trust, the Issuer or any Subsidiary Guarantor, the principal of, premium, if any, and accrued interest on the notes then outstanding shall automatically become and be immediately due and payable without any declaration or other act on the part of the Trustee or any Holder. The Holders of at least a majority in principal amount of the outstanding notes by written notice to the Issuer

and to the Trustee, may waive all past Defaults and rescind and annul a declaration of acceleration and its consequences if (x) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the notes that have become due solely by such declaration of acceleration, have been cured or waived and (y) the rescission would not conflict with any judgment or decree of a court of competent jurisdiction. For information as to the waiver of defaults, see "Modification and Waiver."

The Holders of at least a majority in aggregate principal amount of the outstanding notes may direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee. However, the Trustee may refuse to follow any direction that conflicts with applicable law or the Indenture, that may involve the Trustee in personal liability, or that the Trustee determines in good faith may be unduly prejudicial to the rights of Holders of notes not joining in the giving of such direction and may take any other action it deems proper that is not inconsistent with any such direction received from Holders of notes. A Holder may not pursue any remedy with respect to the Indenture or the notes unless:

(1): the Holder gives the Trustee written notice of a continuing Event of Default;
(2): the Holders of at least 25% in aggregate principal amount of outstanding notes make a written request to the Trustee to pursue the remedy;
(3): such Holder or Holders offer the Trustee indemnity satisfactory to the Trustee against any costs, liability or expense;
(4): the Trustee does not comply with the request within 60 days after receipt of the request and the offer of indemnity; and
(5): during such 60-day period, the Holders of a majority in aggregate principal amount of the outstanding notes do not give the Trustee a direction that is inconsistent with the request.

However, such limitations do not apply to the right of any Holder of a Note to receive payment of the principal of, premium, if any, or interest on, such Note or to bring suit for the enforcement of any such payment, on or after the due date expressed in the notes, which right shall not be impaired or affected without the consent of the Holder.

Officers of the Issuer must certify, on or before a date not more than 90 days after the end of each fiscal year, that a review has been conducted of the activities of the Trust and its Restricted Subsidiaries and the Trust's and its Restricted Subsidiaries' performance under the Indenture and that the Trust has fulfilled all obligations thereunder, or, if there has been a default in the fulfillment of any such obligation, specifying each such default and the nature and status thereof. The Trust will also be obligated to notify the Trustee of any default or defaults in the performance of any covenants or agreements under the Indenture.

Consolidation, Amalgamation, Merger and Sale of Assets

Neither the Issuer nor the Trust will consolidate with, amalgamate with, merge with or into, or sell, convey, transfer, lease or otherwise dispose of all or substantially all of its property and assets (as an entirety or substantially an entirety in one transaction or a series of related transactions) to, any Person or permit any Person to merge with or into it unless:

(1): it shall be the continuing Person, or the Person (if other than it) formed by such consolidation or amalgamation or into which it is merged or that acquired or leased such property and assets of (the "Surviving Person") shall be a corporation, partnership, limited liability company or trust organized and validly existing under the laws of Canada, the United States of America or any jurisdiction thereof and shall expressly assume, by a supplemental indenture to the Indenture, executed and delivered to the Trustee, all of the Issuer's or the Trust's obligations under the Indenture and the notes or the Trust Guarantee, as applicable; provided that if the Surviving Person of the Issuer is not a corporation, a Restricted Subsidiary that is a corporation expressly assumes as co-obligor all of the obligations of the Issuer under the Indenture and the notes pursuant to a supplemental indenture to the Indenture executed and delivered to the Trustee;

(2): immediately after giving effect to such transaction, no Default or Event of Default shall have occurred and be continuing;
(3): immediately after giving effect to such transaction on a pro forma basis, the Trust or the Surviving Person, as the case may be, shall have a Consolidated Net Worth equal to or greater than the Consolidated Net Worth of the Trust immediately prior to such transaction;
(4): immediately after giving effect to such transaction on a pro forma basis the Trust, or the Surviving Person, as the case may be, could Incur at least $1.00 of Indebtedness under the first paragraph of the "Limitation on Indebtedness" covenant; provided that this clause (4) shall not apply to a consolidation, amalgamation, merger or sale of all (but not less than all) of the assets of the Trust if all Liens and Indebtedness of the Trust or the Surviving Person, as the case may be, and its Restricted Subsidiaries outstanding immediately after such transaction would have been permitted (and all such Liens and Indebtedness, other than Liens and Indebtedness of the Trust and its Restricted Subsidiaries outstanding immediately prior to the transaction, shall be deemed to have been Incurred) for all purposes of the Indenture;
(5): it delivers to the Trustee an Officers' Certificate (attaching the arithmetic computations to demonstrate compliance with clauses (3) and (4)) and Opinion of Counsel, in each case stating that such consolidation, amalgamation, merger or transfer and such supplemental indenture complies with this provision and that all conditions precedent provided for herein relating to such transaction have been complied with; and
(6): the Trust (in a transaction involving the Issuer) and each Subsidiary Guarantor, unless such Subsidiary Guarantor is the Person with which the Issuer or the Trust has entered into a transaction under this "Consolidation, Amalgamation, Merger and Sale of Assets" paragraph, shall have by amendment to its Trust Guarantee or Note Guarantee confirmed that its Guarantee shall apply to the obligations of the Issuer, the Trust or the Surviving Person in accordance with the notes or the Trust Guarantee, as applicable, and the Indenture;

provided, however, that clauses (3) and (4) above do not apply (a) between or among the Trust, the Issuer and any Restricted Subsidiary or (b) if, in the good faith determination of the Board of Directors of the Trust, whose determination shall be evidenced by a Board Resolution, the principal purpose of such transaction is to change the jurisdiction of formation of the Trust and any such transaction shall not have as one of its purposes the evasion of the foregoing limitations.

For purposes of the foregoing, the transfer (by sale, conveyance, lease or otherwise, in a single transaction or series of transactions) of all or substantially all of the property and assets of a Person or of one or more of its Restricted Subsidiaries that constitutes all or substantially all of the property and assets of such Person on a consolidated basis, will be deemed to be the transfer of all or substantially all of the property and assets of such Person.

Defeasance

Defeasance and Discharge. The Indenture will provide that the Issuer will be deemed to have paid and will be discharged from any and all obligations in respect of the notes on the 123rd day after the deposit referred to below, and the provisions of the Indenture will no longer be in effect with respect to the notes (except for, among other matters, certain obligations to register the transfer or exchange of the notes, to replace stolen, lost or mutilated notes, to maintain paying agencies and to hold monies for payment in trust) if, among other things:

(A): The Issuer has deposited with the Trustee, in trust, money and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued interest on the notes on the Stated Maturity of such payments in accordance with the terms of the Indenture and the notes,
(B): The Issuer has delivered to the Trustee (1) either (x) an Opinion of Counsel to the effect that Holders will not recognize income, gain or loss for federal income tax purposes as a result of the Issuer's

exercise of its option under this "Defeasance" provision and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred, which Opinion of Counsel must be based upon (and accompanied by a copy of) a ruling of the Internal Revenue Service to the same effect unless there has been a change in applicable federal income tax law after the Closing Date such that a ruling is no longer required or (y) a ruling directed to the Trustee received from the Internal Revenue Service to the same effect as the aforementioned Opinion of Counsel and (2) an Opinion of Counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940 and after the passage of 123 days following the deposit, the trust fund will not be subject to the effect of Section 547 of the United States Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law,

(C): The Issuer has delivered to the Trustee an Opinion of Counsel in Canada to the effect that Holders will not recognize income, gain or loss for Canadian federal or provincial income tax or other tax purposes as a result of such deposit, defeasance and discharge, and will be subject to Canadian federal or provincial income tax and other tax on the same amounts, in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred (which condition may not be waived by any Holder or the Trustee),
(D): immediately after giving effect to such deposit on a pro forma basis, no Event of Default, or event that after the giving of notice or lapse of time or both would become an Event of Default, shall have occurred and be continuing on the date of such deposit or during the period ending on the 123rd day after the date of such deposit, and such deposit shall not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which the Issuer, the Trust or any of its Subsidiaries is a party or by which the Issuer, the Trust or any of its Subsidiaries is bound and
(E): if at such time the notes are listed on a national securities exchange, the Issuer has delivered to the Trustee an Opinion of Counsel to the effect that the notes will not be delisted as a result of such deposit, defeasance and discharge.

Defeasance of Certain Covenants and Certain Events of Default. The Indenture further will provide that the provisions of the Indenture will no longer be in effect with respect to the covenant under "Repurchase of Notes upon a Change of Control," clauses (3) and (4) under the first paragraph of "Consolidation, Amalgamation, Merger and Sale of Assets" and all the covenants described herein under "Certain Covenants," clause (c) under "Events of Default" with respect to such clauses (3) and (4) under the first paragraph of "Consolidation, Amalgamation, Merger and Sale of Assets," clause (d) under "Events of Default" with respect to such other covenants and clauses (e) and (f) under "Events of Default" shall be deemed not to be Events of Default upon, among other things, the deposit with the Trustee, in trust, of money and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued interest on the notes on the Stated Maturity of such payments in accordance with the terms of the Indenture and the notes, the satisfaction of the provisions described in clauses (B)(2), (C), (D) and (E) of the preceding paragraph and the delivery by the Issuer to the Trustee of an Opinion of Counsel to the effect that, among other things, the Holders will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance of certain covenants and Events of Default and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred.

Defeasance and Certain Other Events of Default. In the event the Issuer exercises its option to omit compliance with certain covenants and provisions of the Indenture with respect to the notes as described in the immediately preceding paragraph and the notes are declared due and payable because of the occurrence of an Event of Default that remains applicable, the amount of money and/or U.S. Government Obligations on deposit with the Trustee will be sufficient to pay amounts due on the notes at the time of their Stated Maturity but may not be sufficient to pay amounts due on the notes at the time of the acceleration resulting from such Event of Default. However, the Issuer will remain liable for such payments and the Trust Guarantee and any Subsidiary Guarantor's Subsidiary Guarantee with respect to such payments will remain in effect.

Modification and Waiver

The Indenture may be amended, without the consent of any Holder, to:

(1): cure any ambiguity, defect or inconsistency in the Indenture;
(2): comply with the provisions described under "Consolidation, Amalgamation, Merger and Sale of Assets" or "Limitation on Issuances of Guarantees by Restricted Subsidiaries;"
(3): comply with any requirements of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;
(4): evidence and provide for the acceptance of appointment by a successor Trustee; or
(5): make any change that, in the good faith opinion of the Board of Directors of the Issuer, does not materially and adversely affect the rights of any Holder.

Modifications and amendments of the Indenture, the notes, the Note Guarantees and the Trust Guarantee may be made by the Trust, the Issuer, the Subsidiary Guarantors and the Trustee with the consent of the Holders of not less than a majority in aggregate principal amount of the outstanding notes; provided, however, that no such modification or amendment may, without the consent of each Holder affected thereby:

(1): change the Stated Maturity of the principal of, or any installment of interest on, any Note;
(2): reduce the principal amount of, or premium, if any, or interest on, any Note;
(3): change the optional redemption dates or optional redemption prices of the notes from that stated under the caption "Optional Redemption;"
(4): change the place or currency of payment of principal of, or premium, if any, or interest on, any Note;
(5): impair the right to institute suit for the enforcement of any payment on or after the Stated Maturity (or, in the case of a redemption, on or after the Redemption Date) of any Note;
(6): waive a default in the payment of principal of, premium, if any, or interest on the notes;
(7): release the Trust from the Trust Guarantee or any Subsidiary Guarantor from its Note Guarantee, except as provided in the Indenture; or
(8): reduce the percentage or aggregate principal amount of outstanding notes the consent of whose Holders is necessary for waiver of compliance with certain provisions of the Indenture or for waiver of certain defaults.

No Personal Liability of Incorporators, Unitholders, Officers, Directors or Employees

No recourse for the payment of the principal of, premium, if any, or interest on any of the notes or for any claim based thereon or otherwise in respect thereof, and no recourse under or upon any obligation, covenant or agreement of the Issuer or the Trust in the Indenture, or in any of the notes or the Trust Guarantee or because of the creation of any Indebtedness represented thereby, shall be had against any incorporator, unitholder, officer, director, employee or controlling person of the Trust or of any successor Person thereof. In addition, recourse against the trustee of the Trust in any manner in respect of any Indebtedness, liability or obligation of the Trust in respect of the notes, the Indenture or the Trust Guarantee or arising in connection therewith, or from matters to which any of the foregoing relate, including, without limitation, claims based on negligence or other tortious behavior, shall be limited to and satisfied only out of the Trust Fund (as defined in the trust indenture of the Trust). Each Holder, by accepting the notes, waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the notes and the Trust Guarantee. Such waiver may not be effective to waive liabilities under the federal securities laws.

Concerning the Trustee

Except during the continuance of a Default, the Trustee will not be liable, except for the performance of such duties as are specifically set forth in the Indenture. If an Event of Default has occurred and is continuing,

the Trustee will use the same degree of care and skill in its exercise of the rights and powers vested in it under the Indenture as a prudent person would exercise under the circumstances in the conduct of such person's own affairs.

The Indenture and provisions of the Trust Indenture Act of 1939, as amended, incorporated by reference therein contain limitations on the rights of the Trustee, should it become a creditor of the Issuer, to obtain payment of claims in certain cases or to realize on certain property received by it in respect of any such claims, as security or otherwise. The Trustee is permitted to engage in other transactions; provided, however, that if it acquires any conflicting interest, it must eliminate such conflict or resign.

Governing Law

The Indenture, the notes, the Trust Guarantee and the Note Guarantees will be governed by New York law.

Enforceability of Judgments

Since a substantial portion of the Trust's, the Issuer's and the Subsidiary Guarantors' assets are outside the United States, any judgment obtained in the United States against the Trust's, the Issuer's or the Subsidiary Guarantors', including judgments with respect to the payment of principal, premium, if any, or interest on the notes may not be collectible within the United States.

The Trust has been informed by its Alberta counsel, Burnet, Duckworth & Palmer LLP, that the laws of the Province of Alberta and the federal laws of Canada applicable therein permit an action to be brought against the Trust, the Issuer or a Subsidiary Guarantors in a court of competent jurisdiction in such Province on any final and conclusive judgment in personam of any federal or state court located in the Borough of Manhattan in The City of New York ("New York Court") with respect to the Indenture or the notes that has not been stayed, that is subsisting and unsatisfied and is not impeachable as void or voidable under the internal laws of the State of New York and that is for a sum certain if (1) the New York Court rendering such judgment had jurisdiction over the judgment debtor, as recognized by the courts of the Province of Alberta; (2) such judgment was not obtained by fraud or in a manner contrary to natural justice and the enforcement thereof would not be inconsistent with public policy, as such term is understood under the laws of the Province of Alberta, for example because that would be contrary to any order made by the Attorney General of Canada under the Foreign Extraterritorial Measures Act (Canada or the Competition Tribunal under the Competition Act (Canada) in respect of certain judgments, laws and directives having effects on competition in Canada), or the enforcement of such judgment would constitute, directly or indirectly, the enforcement of foreign revenue, expropriatory or penal laws; (3) no new admissible evidence relevant to the action is discovered prior to the rendering of judgment by an Alberta court; (4) there is no manifest error on the face of the judgment; and (5) the action to enforce such judgment is commenced within the applicable limitation period. The Trust has been advised by such counsel that they do not know of any reason under present laws of the Province of Alberta and the federal laws of Canada applicable therein for avoiding enforcement of such judgments of New York Courts under either the Indenture or the notes based upon public policy.

Consent to Jurisdictions and Service

Each of the Trust, the Issuer and the Subsidiary Guarantors has appointed, and any non-U.S. Subsidiary Guarantors will each appoint, CT Corporation System as its agent for service of process in any suit, action or proceeding with respect to the Indenture, the notes, the Trust Guarantee or the Subsidiary Guarantees and for actions brought under federal or state securities laws brought in any federal or state court located in The City of New York and each of the Trust, the Issuer and the Subsidiary Guarantors will submit to such jurisdiction.

Book-Entry; Delivery and Form

Global Note

The following description of the operations and procedures of DTC is provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to

changes by them from time to time. The Issuer and the Trust take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC will credit, on its internal system, the respective principal amount of the individual beneficial interests represented by such Global Note to the accounts with DTC ("participants") or persons who hold interests through participants. Ownership or beneficial interests in the Global Note will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of participants) and the records of participants (with respect to interest of persons other than participants).

As long as DTC, or its nominee, is the registered Holder of a Global Note, DTC or such nominee, as the case may be, will be considered the sole owner and Holder of the notes represented by such Global Note for all purposes under the indenture and the notes. Except in the limited circumstances described above under "— Exchanges of Book-Entry Notes for Certificated Notes," owners of beneficial interests in a Global Note will not be entitled to have portions of such Global Note registered in their names, will not receive or be entitled to receive physical delivery of notes in definitive form and will not be considered the owners or Holders of the Global Note (or any notes presented thereby) under the indenture or the notes. In addition, no beneficial owner of an interest in a Global Note will be able to transfer that interest except in accordance with DTC's applicable procedures (in addition to those under the indenture referred to herein and, if applicable, those of Euroclear and Clearstream). In the event that owners of beneficial interests in a Global Note become entitled to receive notes in definitive form, such notes will be issued only in registered form in denominations of US$1,000 and integral multiples thereof.

The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons may be limited to that extent. Because DTC can act only on behalf of participants, which in turn act on behalf of indirect participants and certain banks, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons or entities that do not participate in the DTC system, or otherwise take action in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Payments of the principal of and interest on Global Note will be made to DTC or its nominee as the registered owner thereof. Neither the Issuer, the Trust, the Trustee nor any of their respective agents will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the Global Note or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

Beneficial interests in the Global Note will trade in DTC's Same-Day Funds Settlement System, and secondary market trading activity in such interests will therefore settle in immediately available funds. The Issuer expects that DTC or its nominee, upon receipt of any payment of principal or interest in respect of a Global Note representing any notes held by it or its nominee, will immediately credit participants' accounts with payment in amounts proportionate to their respective beneficial interests in the principal amount of such notes as shown on the records of DTC or its nominee. The Issuer also expects that payments by participants to owners of beneficial interests in such Global Note held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in "street name." Such payments will be the responsibility of such participants.

Transfers between participants in DTC will be effected in accordance with DTC's procedures, and will be settled in same-day funds.

DTC has advised the Issuer and the Trust that it will take any action permitted to be taken by a Holder of notes (including the presentation of notes for exchange as described below) only at the direction of one or more participants to whose account with DTC interests in the Global Note are credited and only in respect of such portion of the aggregate principal amount of the notes as to which such participant or participants has or have given such direction. However, if there is an Event of Default (as defined below) under the notes, DTC reserves the right to exchange the Global Note for legended notes in certificated form, and to distribute such notes to its participants.

DTC has advised the Issuer and the Trust as follows: DTC is

•: a limited purpose trust company organized under the laws of the State of New York,
•: a "banking organization" within the meaning of New York Banking law,
•: a member of the Federal Reserve System,
•: a "clearing corporation" within the meaning of the Uniform Commercial Code, as amended, and
•: a "Clearing Agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participants and facilitate the clearance and settlement of securities transactions between participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical transfer and delivery of certificates. Participants include securities brokers and dealers, banks, trust companies and clearing corporations and may include certain other organizations. Indirect access to the DTC system is available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly ("indirect participants").

Although DTC has agreed to the foregoing procedures in order to facilitate transfers of beneficial ownership interests in the Global Note among participants of DTC, Euroclear and Clearstream, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. None of the Issuer, the Trust, the Trustee nor any of their respective agents will have any responsibility for the performance by DTC its Euroclear and Clearstream, their participants or indirect participants of their respective obligations under the rules and procedures governing their operations, including maintaining, supervising or reviewing the records relating to, or payments made on account of, beneficial ownership interests in Global Note.

Definitions

Set forth below are defined terms used in the covenants and other provisions of the Indenture. Reference is made to the Indenture for other capitalized terms used in this "Description of the Notes" for which no definition is provided.

"Adjusted Consolidated Net Income" means, for any period, the aggregate net income (or loss) of the Trust and its Restricted Subsidiaries for such period determined on a consolidated basis in conformity with GAAP; provided that the following items shall be excluded in computing Adjusted Consolidated Net Income (without duplication):

(1): the net income (or loss) of any Person that is not a Restricted Subsidiary;
(2): the net income (or loss) of any Person accrued prior to the date it becomes a Restricted Subsidiary or is merged into or consolidated with the Trust or any of its Restricted Subsidiaries or all or substantially all of the property and assets of such Person are acquired by the Trust or any of its Restricted Subsidiaries;
(3): the net income of any Restricted Subsidiary to the extent that the declaration or payment of dividends or similar distributions by such Restricted Subsidiary of such net income is not at the time permitted by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to such Restricted Subsidiary;
(4): any gains or losses (on an after-tax basis) attributable to sales of assets outside the ordinary course of business of the Trust and its Restricted Subsidiaries;
(5): solely for purposes of calculating the amount of Restricted Payments that may be made pursuant to clause (B) of the first paragraph of the "Limitation on Restricted Payments" covenant, any amount paid or accrued as dividends on Preferred Stock of the Trust owned by Persons other than the Trust and any of its Restricted Subsidiaries; and
(6): all extraordinary gains and extraordinary losses.

"Affiliate" means, as applied to any Person, any other Person directly or indirectly controlling, controlled by, or under direct or indirect common control with, such Person. For purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as applied to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

"Asset Acquisition" means (1) an investment by the Trust or any of its Restricted Subsidiaries in any other Person pursuant to which such Person shall become a Restricted Subsidiary or shall be merged into or consolidated with the Trust or any of its Restricted Subsidiaries; provided that such Person's primary business is the Oil and Gas Business or (2) an acquisition by the Trust or any of its Restricted Subsidiaries of the property and assets of any Person other than the Trust or any of its Restricted Subsidiaries; provided that the property and assets acquired are in the Oil and Gas Business.

"Asset Disposition" means the sale or other disposition by the Trust or any of its Restricted Subsidiaries (other than to the Trust or another Restricted Subsidiary) of (1) all or substantially all of the Capital Stock of any Restricted Subsidiary or (2) all or substantially all of the assets that constitute a division or line of business of the Trust or any of its Restricted Subsidiaries.

"Asset Sale" means any sale, transfer or other disposition (including by way of merger, consolidation, amalgamation or sale-leaseback transaction) in one transaction or a series of related transactions by the Trust or any of its Restricted Subsidiaries to any Person other than the Trust or any of its Restricted Subsidiaries of:

(1): all or any of the Capital Stock of any Restricted Subsidiary,
(2): all or substantially all of the property and assets of an operating unit or business of the Trust or any of its Restricted Subsidiaries or
(3): any other property and assets of the Trust or any of its Restricted Subsidiaries outside the ordinary course of business of the Trust or such Restricted Subsidiary and,

in each case, that is not governed by the provisions of the Indenture applicable to mergers, consolidations, amalgamations and sales of assets of the Trust; provided that "Asset Sale" shall not include:

(a): sales or other dispositions of inventory, receivables and other current assets,
(b): sales, transfers or other dispositions of assets constituting a Permitted Investment or Restricted Payment permitted to be made under the "Limitation on Restricted Payments" covenant,
(c): sales, transfers or other dispositions of assets with a fair market value not in excess of $5.0 million in any transaction or series of related transactions, or
(d): any sale, transfer, assignment or other disposition of any property or equipment that has become damaged, worn out, obsolete or otherwise unsuitable for use in connection with the business of the Trust or its Restricted Subsidiaries.

"Available Cash" means, for any period, Consolidated EBITDA for such period minus (1) the sum of (a) cash tax expense, (b) cash interest expense, and (c) extraordinary cash charges, plus (2) the sum of (a) cash tax refunds received and (b) extraordinary cash gains, in each case, for or in such period.

"Average Life" means, at any date of determination with respect to any debt security, the quotient obtained by dividing (1) the sum of the products of (a) the number of years from such date of determination to the dates of each successive scheduled principal payment of such debt security and (b) the amount of such principal payment by (2) the sum of all such principal payments.

"Board of Directors" means, with respect to any Person, the board of directors (or the board or committee serving a similar function) of such Person or any duly authorized committee of such Board of Directors.

"Borrowing Base" means 65% of the present value of future net revenues discounted at an annual rate of 10% from proved oil and gas reserves of the Trust and its Restricted Subsidiaries calculated using forecast

pricing in accordance with National Instrument 51-101 promulgated by the Canadian Securities Administrators, as confirmed by a Canadian or United States nationally recognized firm of independent petroleum engineers in a reserve report prepared as of the end of the Trust's most recently completed fiscal year for which audited financial statements are available, as (1) increased at the option of the Trust by, as of the date of determination, the present value of future net revenues discounted at an annual rate of 10% of (a) estimated proved oil and gas reserves acquired since the date of such year-end reserve report, and (b) estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves since the date of such year-end reserve report due to exploration, development or exploitation activities, in each case, calculated using forecast pricing in accordance with National Instrument 51-101(utilizing the current market prices published by the same engineering firm referred to above), and (2) decreased by, as of the date of determination, the present value of future net revenues discounted at an annual rate of 10% of (a) estimated proved oil and gas reserves produced or disposed of since the date of such year-end reserve report and (b) reductions in estimated proved oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since the date of such year-end reserve report due to changes in geological conditions or other factors that would, in accordance with standard industry practice, cause such revisions, in each case calculated using forecast pricing in accordance with National Instrument 51-101 (utilizing the current market prices published by the same engineering firm referred to above), provided that, in the case of each of the determinations made pursuant to clauses (1)(a), (1) (b), (2) (a) and (2)(b), such increases and decreases shall be as estimated by the Trust's petroleum engineers, unless there is a Material Change as a result of such acquisitions, dispositions or revisions, in which case the discounted future net revenues utilized for this definition shall be confirmed in a written report of a Canadian or United States nationally recognized firm of independent petroleum engineers delivered to the Trustee.

"Capital Stock" means, with respect to any Person, any and all shares, trust units, interests, participations or other equivalents (however designated, whether voting or non-voting) in equity of such Person, whether outstanding on the Closing Date or issued thereafter, including, without limitation, all Common Stock and Preferred Stock.

"Capitalized Lease" means, as applied to any Person, any lease of any property (whether real, personal or mixed) of which the discounted present value of the rental obligations of such Person as lessee, in conformity with GAAP, is required to be capitalized on the balance sheet of such Person.

"Capitalized Lease Obligations" means the discounted present value of the rental obligations under a Capitalized Lease.

"Caribou Debt" means the secured subordinated debt of the Trust in an aggregate principal amount not to exceed $50.0 million at any one time outstanding to Caribou Capital Corp. and/or Bruce Chernoff issued from time to time having substantially the same terms (other than with respect to interest rate and maturity) as the Third Amended and Restated Equity Bridge Note Agreement dated July 9, 2004 between Caribou Capital Corp. and Harvest Energy Trust (the "Caribou Bridge") and the Second Amended and Restated Equity Bridge Note Agreement dated July 7, 2004 between M. Bruce Chernoff and the Trust (as amended to reflect conforming changes to those included in the Caribou Bridge).

"Change of Control" means such time as:

(1): a "person" or "group" (within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act) becomes the ultimate "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act) of more than 50% of the total voting power of the Voting Stock of the Trust on a fully diluted basis;
(2): individuals who on the Closing Date constitute the Board of Directors (together with any new directors whose election by the Board of Directors or whose nomination by the Board of Directors for election by the Trust's stockholders was approved by a vote of more than 50% of the members of the Board of Directors then in office who either were members of the Board of Directors on the Closing Date or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the members of the Board of Directors then in office; or
(3): the Issuer ceases to be a Subsidiary of the Trust.

"Closing Date" means the date on which the old notes were originally issued under the Indenture.

"Commodity Agreement" means any commodity forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement, including such agreements relating to electricity.

"Common Stock" of any Person means Capital Stock of such Person that does not rank prior, as to the payment of distributions or dividends or as to the distribution of assets upon any voluntary or involuntary liquidation, dissolution or winding-up of such Person, to Capital Stock of any other class of such Person.

"Consolidated EBITDA" means, for any period, Adjusted Consolidated Net Income for such period plus, to the extent such amount was deducted in calculating such Adjusted Consolidated Net Income:

(1): Consolidated Interest Expense;
(2): income taxes;
(3): depletion, depreciation, accretion and amortization expense; and
(4): all other non-cash items reducing Adjusted Consolidated Net Income (other than items that will require cash payments and for which an accrual or reserve is, or is required by GAAP to be, made), less all non-cash items increasing Adjusted Consolidated Net Income (other than items that will result in cash payments in a future period), all as determined on a consolidated basis for the Trust and its Restricted Subsidiaries in conformity with GAAP;

provided that, if any Restricted Subsidiary is not a Wholly Owned Restricted Subsidiary, Consolidated EBITDA shall be reduced (to the extent not otherwise reduced in accordance with GAAP) by an amount equal to (A) the amount of the Adjusted Consolidated Net Income attributable to such Restricted Subsidiary multiplied by (B) the percentage ownership interest in the income of such Restricted Subsidiary not owned on the last day of such period by the Trust or any of its Restricted Subsidiaries.

"Consolidated Interest Expense" means, for any period, the aggregate amount of interest in respect of Indebtedness (including, without limitation, amortization of original issue discount on any Indebtedness and the interest portion of any deferred payment obligation, calculated in accordance with the effective interest method of accounting; all commissions, discounts and other fees and charges owed with respect to letters of credit and bankers' acceptance financing; the net costs associated with Interest Rate Agreements; and Indebtedness that is Guaranteed or secured by the Trust or any of its Restricted Subsidiaries, net of amortization of bond premium) and all but the principal component of rentals in respect of Capitalized Lease Obligations and the amount charged to shareholders' (or unitholders') equity in respect of interest on Indebtedness, in each case paid, accrued or scheduled to be paid or to be accrued by the Trust and its Restricted Subsidiaries during such period; excluding, however, (1) any amount of such interest of any Restricted Subsidiary if the net income of such Restricted Subsidiary is excluded in the calculation of Adjusted Consolidated Net Income pursuant to clause (3) of the definition thereof (but only in the same proportion as the net income of such Restricted Subsidiary is excluded from the calculation of Adjusted Consolidated Net Income pursuant to clause (3) of the definition thereof) and (2) any premiums, fees and expenses (and any amortization thereof) payable in connection with the offering of the notes, all as determined on a consolidated basis (without taking into account Unrestricted Subsidiaries) in conformity with GAAP.

"Consolidated Leverage Ratio" means, on any Transaction Date, the ratio of (1) the aggregate amount of all Indebtedness of the Trust and its Restricted Subsidiaries on a consolidated basis outstanding on such Transaction Date to (2) the aggregate amount of Consolidated EBITDA for the then most recent four fiscal quarters prior to such Transaction Date for which reports have been filed with the SEC or provided to the Trustee determined on a pro forma basis as described under "Interest Coverage Ratio."

"Consolidated Net Worth" means, at any date of determination, stockholders' (or unitholders') equity as set forth on the most recently available quarterly or annual consolidated balance sheet of the Trust and its Restricted Subsidiaries (which shall be as of a date not more than 90 days prior to the date of such computation, and which shall not take into account Unrestricted Subsidiaries), plus, to the extent not included, any Preferred Stock of the Trust, less any amounts attributable to Disqualified Stock or any equity security convertible into or exchangeable for Indebtedness, the cost of treasury stock and the principal amount of any promissory notes

receivable from the sale of the Capital Stock of the Trust or any of its Restricted Subsidiaries, each item to be determined in conformity with GAAP (excluding the effects of foreign currency exchange adjustments).

"Credit Agreement" means the credit agreement in effect on the Closing Date among the Issuer, as borrower, the Trust and its material Subsidiaries, the lenders named therein, National Bank of Canada, as administrative agent, and the other agents named therein including any related notes, debentures, pledges, Guarantees, security documents, instruments and agreements executed from time to time in connection therewith, and in each case as amended, restated, renewed, replaced, refinanced, extended, substituted, assigned by the agent or any lender, restructured, supplemented or otherwise modified from time to time, including, without limitation, any successive amendments, renewals, extensions, substitutions, assignments, restatements, refinancings, restructuring, supplements or other modifications of the foregoing (including increasing the amount of available borrowings thereunder, provided that such increase in borrowings is permitted by the "Limitation on Indebtedness" covenant above, or adding Subsidiaries as additional borrowers or guarantors thereunder) of all or any portion of the Indebtedness under such agreement or agreements or any successor or replacement agreement or any agreements, and whether by the same or any other agent, lender or group of lenders.

"Credit Facilities" means, one or more credit or debt facilities (including, without limitation, the Credit Agreement) or commercial paper facilities, in each case with banks or other institutional lenders providing for, among other things, revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, extended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time.

"Currency Agreement" means any foreign exchange contract, currency swap agreement or other similar agreement or arrangement.

"Default" means any event that is, or after notice or passage of time or both would be, an Event of Default.

"Disqualified Stock" means any class or series of Capital Stock of any Person that by its terms or otherwise is (1) required to be redeemed prior to the Stated Maturity of the notes, (2) redeemable at the option of the holder of such class or series of Capital Stock at any time prior to the Stated Maturity of the notes or (3) convertible into or exchangeable for Capital Stock referred to in clause (1) or (2) above or Indebtedness having a scheduled maturity prior to the Stated Maturity of the notes; provided that any Capital Stock that would not constitute Disqualified Stock but for provisions thereof giving holders thereof the right to require such Person to repurchase or redeem such Capital Stock upon the occurrence of an "asset sale" or "change of control" occurring prior to the Stated Maturity of the notes shall not constitute Disqualified Stock if the "asset sale" or "change of control" provisions applicable to such Capital Stock are no more favorable to the holders of such Capital Stock than the provisions contained in "Limitation on Asset Sales" and "Repurchase of Notes upon a Change of Control" covenants and such Capital Stock specifically provides that such Person will not repurchase or redeem any such stock pursuant to such provision prior to the Issuer's repurchase of such notes as are required to be repurchased pursuant to the "Limitation on Asset Sales" and "Repurchase of Notes upon a Change of Control" covenants; provided further that the trust units of the Trust which are Common Stock shall not be deemed Disqualified Stock by virtue of the repurchase obligations in effect on the Closing Date or amended repurchase obligations that are no more adverse to the Trust than those in effect on the Closing Date.

"Exchangeable Shares" means the non-voting exchangeable shares of the Issuer as constituted on the Closing Date or as amended provided that the terms of such shares (other than adjustments in the exchange ratio) are no more adverse to the Trust or the Issuer than those in effect on the Closing Date.

"fair market value" means the price that would be paid in an arm's-length transaction between an informed and willing seller under no compulsion to sell and an informed and willing buyer under no compulsion to buy, as determined in good faith by the Board of Directors of the Issuer, whose determination shall be conclusive if evidenced by a Board Resolution.

"GAAP" means generally accepted accounting principles in Canada. All ratios and computations contained or referred to in the Indenture shall be computed in conformity with GAAP applied on a consistent basis, except that calculations made for purposes of determining compliance with the terms of the covenants and with other

provisions of the Indenture shall be made without giving effect to the amortization of any expenses incurred in connection with the offering of the notes.

"Guarantee" means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and, without limiting the generality of the foregoing, any obligation, direct or indirect, contingent or otherwise, of such Person (1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services (unless such purchase arrangements are on arm's-length terms and are entered into in the ordinary course of business), to take-or-pay, or to maintain financial statement conditions or otherwise) or (2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part); provided that the term "Guarantee" shall not include endorsements for collection or deposit in the ordinary course of business. The term "Guarantee" used as a verb has a corresponding meaning.

"Incur" means, with respect to any Indebtedness, to incur, create, issue, assume, Guarantee or otherwise become liable for or with respect to, or become responsible for, the payment of, contingently or otherwise, such Indebtedness; provided that (1) any Indebtedness of a Person existing at the time such Person becomes a Restricted Subsidiary will be deemed to be incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary and (2) neither the accrual of interest nor the accretion of original issue discount shall be considered an Incurrence of Indebtedness.

"Indebtedness" means, with respect to any Person at any date of determination (without duplication):

(1): all indebtedness of such Person for borrowed money;
(2): all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;
(3): all obligations of such Person in respect of letters of credit or other similar instruments (including reimbursement obligations with respect thereto, but excluding obligations with respect to letters of credit (including trade letters of credit) securing obligations (other than obligations described in (1) or (2) above or (5), (6) or (7) below) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if drawn upon, to the extent such drawing is reimbursed no later than the third Business Day following receipt by such Person of a demand for reimbursement);
(4): all obligations of such Person to pay the deferred and unpaid purchase price of property or services, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto or the completion of such services, except Trade Payables;
(5): all Capitalized Lease Obligations;
(6): all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided that the amount of such Indebtedness shall be the lesser of (A) the fair market value of such asset at such date of determination and (B) the amount of such Indebtedness;
(7): all Indebtedness of other Persons to the extent such Indebtedness is Guaranteed by such Person; and
(8): to the extent not otherwise included in this definition, obligations under Commodity Agreements, Currency Agreements and Interest Rate Agreements (other than Commodity Agreements, Currency Agreements and Interest Rate Agreements designed solely to protect the Trust or its Restricted Subsidiaries against fluctuations in commodity prices (including electricity prices), foreign currency exchange rates or interest rates and that do not increase the Indebtedness of the obligor outstanding at any time other than as a result of fluctuations in commodity prices, foreign currency exchange rates or interest rates or by reason of fees, indemnities and compensation payable thereunder).

The amount of Indebtedness of any Person at any date shall be the outstanding balance at such date of all unconditional obligations as described above and, with respect to contingent obligations, the maximum liability upon the occurrence of the contingency giving rise to the obligation, provided

(A)

that the amount outstanding at any time of any Indebtedness issued with original issue discount is the face amount of such Indebtedness less the remaining unamortized portion of the original issue discount of such Indebtedness at such time as determined in conformity with GAAP,

(B)

that money borrowed and set aside at the time of the Incurrence of any Indebtedness in order to prefund the payment of the interest on such Indebtedness shall not be deemed to be "Indebtedness" so long as such money is held to secure the payment of such interest and

(C)

that Indebtedness shall not include:

(x): any liability for federal, state, local or other taxes,
(y): performance, surety or appeal bonds provided in the ordinary course of business or
(z): agreements providing for indemnification, adjustment of purchase price or similar obligations, or Guarantees or letters of credit, surety bonds or performance bonds securing any obligations of the Trust or any of its Restricted Subsidiaries pursuant to such agreements, in any case Incurred in connection with the disposition of any business, assets or Restricted Subsidiary (other than Guarantees of Indebtedness Incurred by any Person acquiring all or any portion of such business, assets or Restricted Subsidiary for the purpose of financing such acquisition), so long as the principal amount does not to exceed the gross proceeds actually received by the Trust or any Restricted Subsidiary in connection with such disposition.

Notwithstanding the foregoing, Indebtedness Guaranteed by the Redearth Partnership permitted by clause (9) of the definition of Permitted Investment shall not constitute Indebtedness.

"Initial Subsidiary Guarantors" means each Restricted Subsidiary of the Trust on the Closing Date other than the Issuer and the Redearth Partnership.

"Interest Coverage Ratio" means, on any Transaction Date, the ratio of (1) the aggregate amount of Consolidated EBITDA for the then most recent four fiscal quarters prior to such Transaction Date for which reports have been filed with the SEC or provided to the Trustee (the "Four Quarter Period") to (2) the aggregate Consolidated Interest Expense during such Four Quarter Period. In making the foregoing calculation:

(A): pro forma effect shall be given to any Indebtedness Incurred or repaid during the period (the "Reference Period") commencing on the first day of the Four Quarter Period and ending on the Transaction Date (other than Indebtedness Incurred or repaid under a revolving credit or similar arrangement to the extent of the commitment thereunder (or under any predecessor revolving credit or similar arrangement) in effect on the last day of such Four Quarter Period unless any portion of such Indebtedness is projected, in the reasonable judgment of the senior management of the Issuer, to remain outstanding for a period in excess of 12 months from the date of the Incurrence thereof), in each case as if such Indebtedness had been Incurred or repaid on the first day of such Reference Period
(B): Consolidated Interest Expense attributable to interest on any Indebtedness (whether existing or being Incurred) computed on a pro forma basis and bearing a floating interest rate shall be computed as if the rate in effect on the Transaction Date (taking into account any Interest Rate Agreement applicable to such Indebtedness if such Interest Rate Agreement has a remaining term in excess of 12 months or, if shorter, at least equal to the remaining term of such Indebtedness) had been the applicable rate for the entire period;
(C): pro forma effect shall be given to Asset Dispositions and Asset Acquisitions (including giving pro forma effect to the application of proceeds of any Asset Disposition) that occur during such Reference Period

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as if they had occurred and such proceeds had been applied on the first day of such Reference Period; and

(D): pro forma effect shall be given to asset dispositions and asset acquisitions (including giving pro forma effect to the application of proceeds of any asset disposition) that have been made by any Person that has become a Restricted Subsidiary or has been merged with or into the Trust or any Restricted Subsidiary during such Reference Period and that would have constituted Asset Dispositions or Asset Acquisitions had such transactions occurred when such Person was a Restricted Subsidiary as if such asset dispositions or asset acquisitions were Asset Dispositions or Asset Acquisitions that occurred on the first day of such Reference Period; provided that to the extent that clause (C) or (D) of this sentence requires that pro forma effect be given to an Asset Acquisition or Asset Disposition, such pro forma calculation shall be based upon the four full fiscal quarters immediately preceding the Transaction Date of the Person, or division or line of business of the Person, that is acquired or disposed for which financial information is available.

"Interest Rate Agreement" means any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement, option or future contract or other similar agreement or arrangement.

"Investment" in any Person means any direct or indirect advance, loan or other extension of credit (including, without limitation, by way of Guarantee or similar arrangement; but excluding advances to customers, suppliers or operators in the ordinary course of business that are, in conformity with GAAP, recorded as accounts receivable, prepaid expenses or deposits on the balance sheet of the Trust or its Restricted Subsidiaries and endorsements for collection or deposit arising in the ordinary course of business) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, bonds, notes, debentures or other similar instruments issued by, such Person and shall include (1) the designation of a Restricted Subsidiary as an Unrestricted Subsidiary and (2) the retention of the Capital Stock (or any other Investment) by the Trust or any of its Restricted Subsidiaries, of (or in) any Person that has ceased to be a Restricted Subsidiary, including without limitation, by reason of any transaction permitted by clause (3) of the "Limitation on the Issuance and Sale of Capital Stock of Restricted Subsidiaries" covenant. For purposes of the definition of "Unrestricted Subsidiary" and the "Limitation on Restricted Payments" covenant, (a) the amount of or a reduction in an Investment shall be equal to the fair market value thereof at the time such Investment is made or reduced and (b) in the event the Trust or a Restricted Subsidiary makes an Investment by transferring assets to any Person and as part of such transaction receives Net Cash Proceeds, the amount of such Investment shall be the fair market value of the assets less the amount of Net Cash Proceeds so received, provided the Net Cash Proceeds are applied in accordance with clause (A) or (B) of the "Limitation on Asset Sales" covenant.

"Investment Grade Ratings" means a rating equal to or higher than BBB (or its equivalent), in the case of S&P, and Baa3 (or its equivalent), in the case of Moody's.

"Lien" means any mortgage, pledge, security interest, encumbrance, lien or charge of any kind (including, without limitation, any conditional sale or other title retention agreement or lease in the nature thereof or any agreement to give any security interest).

"Material Change" means an increase or decrease (excluding changes that result solely from changes in prices) of more than 30% during the fiscal quarter in the estimated discounted future net cash flow from proved oil and gas reserves of the Trust and its Restricted Subsidiaries, calculated in accordance with the definition of Borrowing Base; provided, however, that there will be excluded from the calculation of Material Change any estimated future net cash flow from:

(1): any acquisitions during the fiscal quarter of oil and gas reserves that have been audited by a Canadian or United States nationally recognized firm of independent petroleum engineers and on which a report or reports exist; and;

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(2): any disposition of properties held at the beginning of such quarter that have been disposed of as provided in the "Limitation on Asset Sales" covenant.

"Moody's" means Moody's Investors Service, Inc. and its successors.

"Net Cash Proceeds" means:

(a)

with respect to any Asset Sale, the proceeds of such Asset Sale in the form of cash or cash equivalents, including payments in respect of deferred payment obligations (to the extent corresponding to the principal, but not interest, component thereof) when received in the form of cash or cash equivalents and proceeds from the conversion of other property received when converted to cash or cash equivalents, net of

(1): brokerage commissions and other fees and expenses (including fees and expenses of counsel and investment bankers) related to such Asset Sale;
(2): provisions for all taxes (whether or not such taxes will actually be paid or are payable) as a result of such Asset Sale without regard to the consolidated results of operations of the Trust and its Restricted Subsidiaries, taken as a whole;
(3): payments made to repay Indebtedness or any other obligation outstanding at the time of such Asset Sale that either (x) is secured by a Lien on the property or assets sold or (y) is required to be paid as a result of such sale;
(4): pro rata payments of proceeds to other holders of Capital Stock of a non-Wholly Owned Restricted Subsidiary;
(5): appropriate amounts to be provided by the Trust or any Restricted Subsidiary as a reserve against any liabilities associated with such Asset Sale, including, without limitation, pension and other post-employment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale, all as determined in conformity with GAAP; and

(b)

with respect to any issuance or sale of Capital Stock, the proceeds of such issuance or sale in the form of cash or cash equivalents, including payments in respect of deferred payment obligations (to the extent corresponding to the principal, but not interest, component thereof) when received in the form of cash or cash equivalents and proceeds from the conversion of other property received when converted to cash or cash equivalents, net of attorney's fees, accountants' fees, underwriters' or placement agents' fees, discounts or commissions and brokerage, consultant and other fees and expenses incurred in connection with such issuance or sale and net of taxes paid or payable as a result thereof.

"Note Guarantee" means any Guarantee by any Subsidiary Guarantor of the obligations of the Issuer under the Indenture and the notes.

"Oil and Gas Business" means:

(1): the acquisition, exploration, development, operation and disposition of interests in oil, gas and other hydrocarbon properties;
(2): the gathering, marketing, treating, processing, storage, selling and transporting of any production from such interests or properties;
(3): the exploration for or development, production, treatment, processing, storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith;
(4): evaluating, participating in or pursuing any other activity or opportunity that is primarily related to clauses (1) through (3) above; and

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(5): any activity that is ancillary or complementary to or necessary or appropriate for the activities described in clauses (1) through (4) of this definition.

"Oil and Gas Investments" means any Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing or transporting oil and gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including, without limitation:

(1): ownership interests in oil and gas properties, processing facilities or gathering systems or ancillary real property interests; and
(2): Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements with third parties.

"Offer to Purchase" means an offer to purchase notes by the Issuer from the Holders commenced by mailing a notice to the Trustee and each Holder stating:

(1): the covenant pursuant to which the offer is being made and that all notes validly tendered will be accepted for payment on a pro rata basis;
(2): the purchase price and the date of purchase (which shall be a Business Day no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the "Payment Date");
(3): that any note not tendered will continue to accrue interest pursuant to its terms;
(4): that, unless the Issuer defaults in the payment of the purchase price, any note accepted for payment pursuant to the Offer to Purchase shall cease to accrue interest on and after the Payment Date;
(5): that Holders electing to have a note purchased pursuant to the Offer to Purchase will be required to surrender the note, together with the form entitled "Option of the Holder to Elect Purchase" on the reverse side of the note completed, to the Paying Agent at the address specified in the notice prior to the close of business on the Business Day immediately preceding the Payment Date;
(6): that Holders will be entitled to withdraw their election if the Paying Agent receives, not later than the close of business on the third Business Day immediately preceding the Payment Date, a telegram, facsimile transmission or letter setting forth the name of such Holder, the principal amount of notes delivered for purchase and a statement that such Holder is withdrawing his election to have such notes purchased; and
(7): that Holders whose notes are being purchased only in part will be issued new notes equal in principal amount to the unpurchased portion of the notes surrendered; provided that each Note purchased and each new Note issued shall be in a principal amount of US$1,000 or integral multiples of US$1,000.

On the Payment Date, the Issuer shall (a) accept for payment on a pro rata basis notes or portions thereof tendered pursuant to an Offer to Purchase; (b) deposit with the Paying Agent money sufficient to pay the purchase price of all notes or portions thereof so accepted; and (c) deliver, or cause to be delivered, to the Trustee all notes or portions thereof so accepted together with an Officers' Certificate specifying the notes or portions thereof accepted for payment by the Issuer. The Paying Agent shall promptly mail to the Holders of notes so accepted payment in an amount equal to the purchase price, and the Trustee shall promptly authenticate and mail to such Holders a new Note equal in principal amount to any unpurchased portion of the Note surrendered; provided that each Note purchased and each new Note issued shall be in a principal amount of US$1,000 or integral multiples of US$1,000. The Issuer will publicly announce the results of an Offer to Purchase as soon as practicable after the Payment Date. The Trustee shall act as the Paying Agent for an Offer

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to Purchase. The Issuer will comply with Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable, in the event that the Issuer is required to repurchase notes pursuant to an Offer to Purchase.

"Permitted Investment" means:

(1): an Investment in the Trust or a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary or be merged, consolidated or amalgamated with or into or transfer or convey all or substantially all its assets to, the Trust or a Restricted Subsidiary; provided that such person's primary business is the Oil and Gas Business;
(2): Temporary Cash Investments;
(3): payroll, travel and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses in accordance with GAAP;
(4): stock, obligations or securities received in satisfaction of judgments;
(5): an Investment in an Unrestricted Subsidiary consisting solely of an Investment in another Unrestricted Subsidiary;
(6): Commodity Agreements, Interest Rate Agreements and Currency Agreements designed solely to protect the Trust or its Restricted Subsidiaries against fluctuations in commodity prices, interest rates or foreign currency exchange rates;
(7): Oil and Gas Investments having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (7) since the Closing Date, not to exceed $20.0 million;
(8): any Investments received in compromise of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; and
(9): a Guarantee by the Redearth Partnership existing on the Closing Date of Indebtedness of its partners (other than the Trust or an Affiliate of the Trust) and any Indebtedness incurred to refund, replace or refinance such Indebtedness, or any successive refunding, replacement or refinancing; provided that recourse under such Guarantee is limited to the interest in the Redearth Partnership of, and an undivided interest in the assets of the Redearth Partnership corresponding to such interest of, a partner that is not the Trust or a Restricted Subsidiary.

"Permitted Liens" means:

(1): Liens for taxes, assessments, governmental charges or claims that are not delinquent or that are being contested in good faith by appropriate legal proceedings promptly instituted and diligently conducted and for which a reserve or other appropriate provision, if any, as shall be required in conformity with GAAP shall have been made;
(2): statutory and common law Liens of landlords and carriers, warehousemen, mechanics, suppliers, materialmen, repairmen or other similar Liens arising in the ordinary course of business and with respect to amounts not yet delinquent or being contested in good faith by appropriate legal proceedings promptly instituted and diligently conducted and for which a reserve or other appropriate provision, if any, as shall be required in conformity with GAAP shall have been made;
(3): Liens incurred or deposits made in the ordinary course of business in connection with workers' compensation, unemployment insurance and other types of social security;
(4): Liens incurred or deposits made to secure the performance of tenders, bids, leases, statutory or regulatory obligations, bankers' acceptances, surety and appeal bonds, government contracts,

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performance and return-of-money bonds and other obligations of a similar nature incurred in the ordinary course of business (exclusive of obligations for the payment of borrowed money);

(5): easements, rights-of-way, municipal and zoning ordinances and similar charges, encumbrances, title defects or other irregularities that do not materially interfere with the ordinary course of business of the Trust or any of its Restricted Subsidiaries;
(6): leases or subleases granted to others that do not materially interfere with the ordinary course of business of the Trust and its Restricted Subsidiaries, taken as a whole;
(7): Liens encumbering property or assets under construction arising from progress or partial payments by a customer of the Trust or its Restricted Subsidiaries relating to such property or assets;
(8): any interest or title of a lessor in the property subject to any Capitalized Lease or operating lease;
(9): Liens arising from filing Uniform Commercial Code or Personal Property Security Act financing statements regarding leases;
(10): Liens on property of, or Capital Stock or Indebtedness of, any Person existing at the time such Person becomes, or becomes a part of the Trust or any of its Restricted Subsidiaries; provided that such Liens do not extend to or cover any property or assets of the Trust or any Restricted Subsidiary other than the property or assets acquired;
(11): Liens in favor of the Trust or any Restricted Subsidiary;
(12): Liens arising from the rendering of a final judgment or order against the Trust or any Restricted Subsidiary that does not give rise to an Event of Default;
(13): Liens securing reimbursement obligations with respect to letters of credit that encumber documents and other property relating to such letters of credit and the products and proceeds thereof;
(14): Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods;
(15): Liens encumbering customary initial deposits and margin deposits, and other Liens that are within the general parameters customary in the industry and incurred in the ordinary course of business, in each case, under Commodity Agreements, Interest Rate Agreements and Currency Agreements designed solely to protect the Trust or any of its Restricted Subsidiaries from fluctuations in interest rates, currencies or the price of commodities;
(16): Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into by the Trust or any of its Restricted Subsidiaries in the ordinary course of business in accordance with the past practices of the Trust and its Restricted Subsidiaries prior to the Closing Date;
(17): Liens on Capital Stock of any Unrestricted Subsidiary to secure Indebtedness of such Unrestricted Subsidiary;
(18): Liens on or sales of receivables;
(19): Liens on property existing at the time of acquisition of the property by the Trust or any of its Restricted Subsidiaries, provided that such Liens were in existence prior to the contemplation of such acquisition and do not extend to any property of the Trust or any Restricted Subsidiary other than the property so acquired by the Trust or such Restricted Subsidiary;
(20): Liens incurred in the ordinary course of business of the Trust or any Restricted Subsidiary of the Trust with respect to obligations that do not in the aggregate exceed $10.0 million at any one time outstanding;

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(21): Liens in pipelines or pipeline facilities that arise by operation of law;
(22): Liens under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements, including in each case Liens for penalties arising under such agreements area of mutual interest agreements and other agreements, or arising by operation of law, that are customary in the Oil and Gas Business; provided that such Liens are not created or incurred in connection with any Indebtedness;
(23): Liens to secure payment of royalties, revenue interests, net profits interests and preferential rights of purchase incurred in the ordinary course of business to the extent of the security interest in those underlying assets; provided that such Liens are not created or incurred in connection with any Indebtedness;
(24): Liens in oil, gas or other mineral property or products derived from such property to secure obligations incurred or Guarantees of obligations incurred in connection with or necessarily incidental to commitments of purchase or sale of, or the transportation, storage or distribution of, such property or the products derived from such property; provided that such Liens are not created or incurred in connection with any Indebtedness;
(25): any right of first refusal in favor of any Person granted in the ordinary course of business with respect to the interests of the Trust or any Restricted Subsidiary in any oil, gas or other hydrocarbon properties; provided that such Liens are not created or incurred in connection with any Indebtedness; and
(26): Liens securing the Caribou Debt.

"Preferred Stock" of a Person means any Capital Stock of such Person that has preferential rights to any other Capital Stock of such Person with respect to distributions, dividends or redemptions upon liquidation.

"Replacement Assets" means, on any date, property or assets (other than current assets) of a nature or type or that are used in the Oil and Gas Business (or an Investment in a company having property or assets of a nature or type, or engaged in the Oil and Gas Business) similar or related to the nature or type of the property and assets of, or the business of, the Trust and its Restricted Subsidiaries existing on such date.

"Restricted Subsidiary" means any Subsidiary of the Trust other than an Unrestricted Subsidiary.

"S&P" means Standard & Poor's Ratings Group, a division of The McGraw-Hill Companies, and its successors.

"Significant Subsidiary" means, at any date of determination, any Restricted Subsidiary that, together with its Subsidiaries, (1) for the most recent fiscal year of the Trust, accounted for more than 10% of the consolidated revenues of the Trust and its Restricted Subsidiaries or (2) as of the end of such fiscal year, was the owner of more than 10% of the consolidated assets of the Trust and its Restricted Subsidiaries, all as set forth on the most recently available consolidated financial statements of the Trust for such fiscal year.

"Stated Maturity" means, (1) with respect to any debt security, the date specified in such debt security as the fixed date on which the final installment of principal of such debt security is due and payable and (2) with respect to any scheduled installment of principal of or interest on any debt security, the date specified in such debt security as the fixed date on which such installment is due and payable.

"Subsidiary" means, with respect to any Person, any corporation, association or other business entity of which more than 50% of the voting power of the outstanding Voting Stock is owned, directly or indirectly, by such Person and one or more other Subsidiaries of such Person.

"Subsidiary Guarantor" means any Initial Subsidiary Guarantor and any other Restricted Subsidiary which provides a Note Guarantee until such Subsidiary is released from its Note Guarantee in accordance with the

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terms of the Indenture; provided that the term Subsidiary Guarantor shall include any Restricted Subsidiary that expressly assumes as co-obligor all of the obligations of the Issuer under the Indenture.

"Temporary Cash Investment" means any of the following:

(1): direct obligations of the United States of America or Canada or any agency thereof or obligations fully and unconditionally guaranteed by the United States of America or Canada or any agency thereof, in each case maturing within one year unless such obligations are deposited by the Trust (x) to defease any Indebtedness or (y) in a collateral or escrow account or similar arrangement to prefund the payment of interest on any indebtedness;
(2): time deposit accounts, certificates of deposit and money market deposits maturing within 180 days of the date of acquisition thereof issued by a bank or trust company which is organized under the laws of the United States of America or Canada, any state or province thereof or any foreign country recognized by the United States of America or Canada, and which bank or trust company has capital, surplus and undivided profits aggregating in excess of $100 million (or the foreign currency equivalent thereof) and has outstanding debt which is rated "A" (or such similar equivalent rating) or higher by at least one nationally recognized statistical rating organization (as defined in Rule 436 under the Securities Act) or any money market fund sponsored by a registered broker dealer or mutual fund distributor;
(3): repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clause (1) above entered into with a bank or trust company meeting the qualifications described in clause (2) above;
(4): commercial paper, maturing not more than one year after the date of acquisition, issued by a corporation (other than an Affiliate of the Trust) organized and in existence under the laws of the United States of America or Canada, any state or province thereof or any foreign country recognized by the United States of America or Canada with a rating at the time as of which any investment therein is made of "P-1" (or higher) according to Moody's or "A-1" (or higher) according to S&P;
(5): securities with maturities of six months or less from the date of acquisition issued or fully and unconditionally guaranteed by any state, commonwealth or territory of the United States of America, any province of Canada, or by any political subdivision or taxing authority thereof, and rated at least "A" by S&P or Moody's; and
(6): any mutual fund that has at least 95% of its assets continuously invested in investments of the types described in clauses (1) through (5) above.

"Trade Payables" means, with respect to any Person, any accounts payable or any other indebtedness or monetary obligation to trade creditors created, assumed or Guaranteed by such Person or any of its Subsidiaries arising in the ordinary course of business in connection with the acquisition of goods or services.

"Transaction Date" means, with respect to the Incurrence of any Indebtedness, the date such Indebtedness is to be Incurred and, with respect to any Restricted Payment, the date such Restricted Payment is to be made.

"Trust Guarantee" means the Guarantee by the Trust of the obligations of (1) the Issuer under the Indenture and the notes and (2) each Subsidiary Guarantor under its Note Guarantee and the Indenture.

"Unpaid Restricted Payments Basket" shall initially equal $40.0 million; provided that at the end of every fiscal quarter ending after the Closing Date the Trust could make Restricted Payments pursuant to clause (B) of the first paragraph of the "Limitation on Restricted Payments" covenant, the amount of Restricted Payments that could be made at such time pursuant to clause (B) of the first paragraph of the "Limitation on Restricted Payments" covenant (after giving effect to any Indebtedness which would need to be Incurred to make such Restricted Payments) shall be added to the Unpaid Restricted Payments Basket as of the last day of such fiscal quarter.

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"Unrestricted Subsidiary" means (1) any Subsidiary of the Trust that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Issuer in the manner provided below; and (2) any Subsidiary of an Unrestricted Subsidiary. The Board of Directors may designate any Restricted Subsidiary (including any newly acquired or newly formed Subsidiary of the Trust but excluding the Issuer) to be an Unrestricted Subsidiary unless such Subsidiary owns any Capital Stock of, or owns or holds any Lien on any property of, the Trust or any Restricted Subsidiary; provided that (A) any Guarantee by the Trust or any Restricted Subsidiary of any Indebtedness of the Subsidiary being so designated shall be deemed an "Incurrence" of such Indebtedness and an "Investment" by the Trust or such Restricted Subsidiary (or both, if applicable) at the time of such designation; (B) either (I) the Subsidiary to be so designated has total assets of $1,000 or less or (II) if such Subsidiary has assets greater than $1,000, such designation would be permitted under the "Limitation on Restricted Payments" covenant and (C) if applicable, the Incurrence of Indebtedness and the Investment referred to in clause (A) of this proviso would be permitted under the "Limitation on Indebtedness" and "Limitation on Restricted Payments" covenants. The Board of Directors may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that (a) no Default or Event of Default shall have occurred and be continuing at the time of or after giving effect to such designation, (b) all Liens and Indebtedness of such Unrestricted Subsidiary outstanding immediately after such designation would, if Incurred at such time, have been permitted to be Incurred (and shall be deemed to have been Incurred) for all purposes of the Indenture and (c) all outstanding Investments owned by such Unrestricted Subsidiary will be deemed to be made as of the time of such designation and such Investments shall only be permitted if such Investments would be permitted by the "Limitation on Restricted Payments" covenant. Any such designation by the Board of Directors shall be evidenced to the Trustee by promptly filing with the Trustee a copy of the Board Resolution giving effect to such designation and an Officers' Certificate certifying that such designation complied with the foregoing provisions.

"U.S. Government Obligations" means securities that are (1) direct obligations of the United States of America for the payment of which its full faith and credit is pledged or (2) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof at any time prior to the Stated Maturity of the notes, and shall also include a depository receipt issued by a bank or trust company as custodian with respect to any such U.S. Government Obligation or a specific payment of interest on or principal of any such U.S. Government Obligation held by such custodian for the account of the holder of a depository receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depository receipt.

"Voting Stock" means with respect to any Person, Capital Stock of any class or kind ordinarily having the power to vote for the election of directors, managers or other voting members of the governing body of such Person.

"Wholly Owned" means, with respect to any Subsidiary of any Person, the ownership of all of the outstanding Capital Stock of such Subsidiary (other than any director's qualifying shares or Investments by foreign nationals mandated by applicable law) by such Person or one or more Wholly Owned Subsidiaries of such Person.

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INCOME TAX CONSIDERATIONS

The following summary is of a general nature only and is not intended to be, and should not be construed to be, legal, or tax advice to any prospective investor and no representation with respect to the tax consequences to any particular investor is made. Accordingly, prospective investors should consult with their own tax advisers for advice with respect to the income tax consequences to them having regard to their own particular circumstances, including any consequences of an investment in the notes or the exchange notes arising under state, provincial or local tax laws or tax laws of jurisdictions outside the United States or Canada.

Canadian Federal Income Tax Considerations

In the opinion of Burnet, Duckworth & Palmer LLP, our Canadian legal counsel, the following is, as of the date of this prospectus, a fair and adequate summary of the principal Canadian federal income tax consequences to a holder of the notes who, at all material times and for the purposes of the Income Tax Act (Canada) (the "Canadian Tax Act") is the beneficial owner of the notes and is not deemed to be resident in Canada during any taxation year in which it owns the notes (a "Non-Canadian Holder"). A reference to the notes herein includes a reference to the exchange notes, but not to any additional notes.

This summary is based on the current provisions of the Canadian Tax Act and the regulations thereunder, counsel's understanding of the current published administrative practices of the Canada Revenue Agency, and all specific proposals to amend the Canadian Tax Act and the regulations thereunder announced by or on behalf of the Minister of Finance prior to the date of this prospectus. This summary does not otherwise take into account or anticipate changes in the law, whether by judicial, regulatory or legislative decisions or actions, nor does it take into account tax legislation or considerations of any province or territory of Canada or any jurisdiction other than Canada.

The payment by Harvest Operations of interest, principal or premium on the notes to a Non-Canadian Holder with whom we deal at arm's length within the meaning of the Canadian Tax Act at all relevant times will be exempt from Canadian non-resident withholding tax. However, any amounts paid or credited by the Trust or any Subsidiary Guarantor that is resident in Canada or that carries on business in Canada for the purposes of the Canadian Tax Act under a guarantee in satisfaction of any amounts that may reasonably be regarded as being or being attributable to interest payable under any note may be subject to Canadian non-resident withholding tax at the rate of 25% or such lower rate as may be provided under the terms of any applicable bilateral tax treaty. For the purposes of the Canadian Tax Act, related persons (as defined in the Canadian Tax Act) are deemed not to deal at arm's length and it is a question of fact whether persons not related to each other deal at arm's length.

No other taxes on income (including taxable capital gains) will be payable by a Non-Canadian Holder under the Canadian Tax Act in respect of the holding, sale, redemption, exchange or other disposition of the notes or the receipt of interest, principal or premium thereon where the Non-Canadian Holder does not use or hold and is not deemed to use or hold the notes in the course of carrying on business in Canada for the purposes of the Canadian Tax Act and, in the case of a holder who carries on an insurance business in Canada and elsewhere, establishes that the notes are not "designated insurance property" and are not effectively connected with such insurance business carried on in Canada.

U.S. Federal Income Tax Considerations

The following summary describes certain U.S. federal income tax consequences that may be relevant to U.S. persons (as defined below) of the exchange of initial notes for exchange notes in accordance with the exchange offer, and of the purchase, ownership and disposition of exchange notes acquired in the exchange offer. In the opinion of Paul, Weiss, Rifkind, Wharton & Garrison LLP, our special U.S. tax counsel, subject to the exceptions, assumptions and qualification set forth below, the discussion accurately reflects the material U.S. federal income tax consequences to U.S. Holders of the consummation of the exchange offer and the purchase, ownership and disposition of exchange notes acquired in the exchange offer. This discussion assumes that U.S. persons hold the initial notes and exchange notes as capital assets ("U.S. Holders") within the meaning of section 1221 of the Internal Revenue Code of 1986, as amended (the "Code"). This discussion does not purport to deal with all aspects of U.S. federal income taxation that may be relevant to particular holders in light of their particular circumstances nor does it deal with all U.S. federal income tax considerations applicable to

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persons subject to special tax rules, such as dealers in securities or currencies, financial institutions, insurance companies, tax-exempt organizations, persons holding notes as a part of a straddle, hedge or conversion transaction or a synthetic security or other integrated transaction, partnerships or other pass-through entities, U.S. Holders whose "functional currency" is not the U.S. dollar, and holders who are not U.S. Holders. Furthermore, the discussion below is based upon the provisions of the Code, Treasury regulations promulgated under the Code, administrative authority and judicial decisions effective as of the date of this prospectus. Those authorities may be repealed, revoked or modified (possibly with retroactive effect) so as to result in U.S. federal income tax consequences different from those discussed below. In addition, no rulings from the United States Internal Revenue Service (the "IRS") have been or will be sought with respect to the matters discussed below. Consequently, there can be no assurance that the IRS will take a similar view as to any of the tax consequences described in this summary.

If an entity that is classified as a partnership for U.S. federal income tax purposes holds initial notes or exchange notes, the tax treatment of its partners will generally depend upon the status of the partner and the activities of the partnership. Partnerships and other entities that are classified as partnerships for U.S. federal income tax purposes and persons holding initial notes or exchange notes through a partnership or other entity classified as a partnership for U.S. federal income tax purposes are urged to consult their tax advisors.

U.S. Holders should consult their own tax advisors concerning the U.S. federal income tax consequences applicable to such holder of the exchange offer, and the purchase, ownership and disposition of the exchange notes, in light of their particular situations as well as any consequences arising under the laws of any state, local or foreign taxing jurisdiction.

As used in this section, the term "U.S. person" means a beneficial owner of a note that is for U.S. federal income tax purposes (i) a citizen or resident of the United States, (ii) a corporation created or organized in or under the laws of the United States or any political subdivision of the United States, (iii) an estate the income of which is subject to U.S. federal income taxation regardless of its source or (iv) a trust if either (A) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (B) the trust has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.

Exchange of Notes for Exchange Notes

The exchange of initial notes for exchange notes pursuant to the Registration Rights Agreement should not constitute a recognition event for U.S. federal income tax purposes. Consequently, no gain or loss should be recognized by a U.S. Holder upon receipt of the exchange notes. For purposes of determining gain or loss upon the subsequent sale, exchange or redemption of exchange notes, a U.S. Holder's basis in exchange notes should be the same as such U.S. Holder's basis in the initial notes exchanged for the exchange notes. In addition, a U.S. Holder's holding period for an exchange note should include the holding period for the original note exchanged pursuant to the Registration Rights Agreement.

Payments of Interest

Interest on an exchange note will generally be taxable to a U.S. Holder as ordinary income at the time it is paid or accrued in accordance with the U.S. Holder's method of accounting for tax purposes. In the event we were required to withhold Canadian taxes, a U.S. Holder would be required to include in income, in addition to interest on the exchange notes, any additional amounts we pay to cover any Canadian taxes withheld from such interest payments. In such case, a U.S. Holder might be entitled to claim a credit against its U.S. federal income tax liability, or a deduction in computing its U.S. federal taxable income, for Canadian income taxes withheld and paid over to the Canadian taxing authorities or for any of those taxes paid directly to the Canadian taxing authorities. The rules governing the foreign tax credit are complex. Investors are urged to consult their tax advisors regarding the availability of the foreign tax credit under their particular circumstances. Interest income on a note generally will constitute foreign source income and generally will be considered "passive" income or "financial services" income (or, if Canadian withholding tax at a rate of 5% or more were to be imposed, as "high withholding tax interest"), which are treated separately from other types of income in computing the U.S. foreign tax credit allowable to U.S. Holders under the Code.

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If the exchange notes' "stated redemption price at maturity" (generally, the sum of all payments required under the note other than payments of stated interest) exceeds the issue price by more than a de minimus amount, a U.S. Holder will be required to include such excess in income as original issue discount, which is treated for U.S. federal income tax purposes as accruing over the exchange notes' term as interest income of the U.S. Holders. A U.S. Holder's adjusted tax basis in an exchange note would be increased by the amount of any original issue discount included in its gross income. In compliance with Treasury regulations, if the Company determines that the exchange notes have more than a de minimus amount of original issue discount, it will provide certain information to the IRS and/or U.S. Holders that is relevant to determining the amount of original issue discount in each accrual period.

Market Discount and Bond Premium

If a United States Holder purchased an initial note prior to this exchange offer for an amount that is less than its principal amount, then, subject to a statutory de minimus rule, the difference generally will be treated as market discount. If a United States Holder exchanges an initial note with respect to which there is market discount, for an exchange note pursuant to the exchange offer, the market discount applicable to the initial note should carry over to the exchange note so received. In that case, any partial principal payment on, or any gain realized on the sale, redemption, retirement or other disposition of (including dispositions which are nonrecognition transactions under certain provisions of the Code), the exchange note will be included in gross income and characterized as ordinary income to the extent of the market discount that (1) has not previously been included in income and (2) is treated as having accrued on the exchange note prior to the payment or disposition.

Market discount generally accrues on a straight-line basis over the remaining term of the exchange note. Upon an irrevocable election, however, market discount will accrue on a constant yield basis. A United States Holder might be required to defer all or a portion of the interest expense on indebtedness incurred or continued to purchase or carry an exchange note. If a United States Holder elects to include market discount in gross income currently as it accrues, the preceding rules relating to the recognition of market discount and deferral of interest expense will not apply. An election made to include market discount in gross income as it accrues will apply to all debt instruments acquired by the U.S. Holder on or after the first day of the taxable year to which the election applies and may be revoked only with the consent of the IRS.

If a U.S. Holder purchased an initial note prior to this exchange offer for an amount that is in excess of all amounts payable on the initial note after the purchase date, other than payments of qualified stated interest, the excess will be treated as bond premium. If a United States Holder exchanges an initial note, with respect to which there is a bond premium, for an exchange note pursuant to the exchange offer, the bond premium applicable to the initial note should carry over to the exchange note so received. In general, a U.S. Holder may elect to amortize bond premium over the remaining term of the exchange note on a constant yield method. The amount of bond premium allocable to any accrual period is offset against the qualified stated interest allocable to the accrual period. If, following the offset determination described in the immediately preceding sentence, there is an excess allocable bond premium remaining, that excess may, in some circumstances, be deducted. An election to amortize bond premium applies to all taxable debt instruments held at the beginning of the first taxable year to which the election applies and thereafter acquired by the U.S. Holder and may be revoked only with the consent of the IRS.

Sale, Exchange and Redemption of Notes

Upon the sale, exchange or redemption of an exchange note, a U.S. Holder will recognize gain or loss equal to the difference between the amount realized upon the sale, exchange or redemption (less any accrued interest, which will be taxable as ordinary interest income) and the U.S. Holder's tax basis in the exchange note. Gain or loss realized on the sale, exchange or redemption of an exchange note will be capital gain or loss and will be long-term capital gain or loss if at the time of sale, exchange or retirement the note has been held for more than one year. Under current law, net capital gains of noncorporate taxpayers are, under some circumstances, taxed at lower rates than items of ordinary income. The deductibility of capital losses is subject to limitations. If the U.S. Holder is a United States resident (as defined in section 865 of the Code), gains realized upon disposition of an exchange note by such U.S. Holder generally will be U.S.-source income (unless it is attributable to an

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office or other fixed place of business outside the U.S.), and disposition losses generally will be allocated to reduce U.S.-source income.

Information Reporting and Backup Withholding

In general, information reporting requirements will apply to certain payments of principal and interest on an exchange note and to the proceeds of the sale of an exchange note made to U.S. Holders other than certain exempt recipients (such as corporations). A U.S. Holder that is not an exempt recipient will generally be subject to backup withholding of U.S. federal income tax (currently at a rate of 28%) unless the U.S. Holder provides an accurate taxpayer identification number ("TIN") and otherwise complies with applicable requirements of the backup withholding rules.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be allowed as a credit against the U.S. Holder's U.S. federal income tax liability and may entitle the holder to a refund to the extent that the amount withheld exceeds such liability provided the required information is furnished to the IRS. U.S. Holders should consult their tax advisors regarding the application of backup withholding in their particular situation, the availability of an exemption from withholding, and the procedure for obtaining such an exemption, if available. A U.S. Holder who does not provide a correct TIN may be subject to penalties imposed by the IRS.

The U.S. federal income tax discussion provided above is included for general information only and may or may not apply to you depending upon your particular situation. You should consult your own tax advisor with respect to the tax consequences to you of the exchange offer and of owning, holding, and disposing of an exchange note, including the tax consequences under state, local, foreign, and other tax laws and the possible effects of changes in federal or other tax laws.

PLAN OF DISTRIBUTION

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of these new notes. This prospectus, as it may be amended or supplements form time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where those old notes were acquired as a result of market-making activities or other trading activities. Harvest and the Guarantors will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests those documents in the letter of transmittal. Under the registration rights agreement Harvest and the Guarantors have agreed that we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any of these resales starting on the date the registration statement is declared effective and for a period ending on the earlier of (i) 180 days after the date the registration statement is declared effective and (ii) the date on which a participating broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of these methods of resale, at market prices prevailing at the time of resale, at prices related to these prevailing market prices or negotiated prices. Any of these resales may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any of these broker-dealers and/or the purchasers of any of these new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of these new notes may be deemed to be an underwriter within the meaning of the Securities Act and any profit of any of these resales of new notes and any commissions or concessions received by any of these persons may be deemed to be underwriting compensations under the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an underwriter within the meaning of the Securities Act.

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We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the old notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

The new notes are not being offered and may not be offered or sold, directly or indirectly, in Canada or to or for the account of any resident of Canada in contravention of the securities law of any province or territory of Canada.

LEGAL MATTERS

Legal matters in connection with this offering will be passed upon for Harvest by Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York (concerning matters of U.S. law), and Burnet, Duckworth & Palmer, LLP, Calgary, Alberta (concerning matters of Canadian law). The partners of Paul, Weiss, Rifkind, Wharton & Garrison LLP and Burnet, Duckworth & Palmer LLP beneficially own less than 1% of Harvest's trust units.

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EXPERTS

The consolidated financial statements of Harvest Energy Trust, as of December 31, 2003 and 2002 and for the year ended December 31, 2003 and the period from July 10, 2002 (date of formation) to December 31, 2002, included in this prospectus have been audited by KPMG LLP, Chartered Accountants, Calgary, Alberta, as stated in their report herein (which audit report expresses an unqualified opinion but is accompanied by Comments for U.S. readers on Canada-U.S. Reporting Difference regarding changes in accounting principles), and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing. The schedule of revenue and expenses for the Carlyle Properties for the three years ended December 31, 2002 incorporated by reference in this prospectus have also been audited by KPMG LLP, Chartered Accountants, Calgary, Alberta, as stated in their report (which audit report expresses an unqualified opinion), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Storm Energy Ltd. as of December 31, 2003 and 2002 and for the year ended December 31, 2003 and for the period from commencement of operations on August 23, 2002 to December 31, 2002 included in this prospectus have been audited by Deloitte & Touche LLP, independent registered chartered accountants, as stated in their report herein (which audit report expresses an unqualified opinion and includes a separate paragraph referring to previously issued financial statements and for U.S. readers includes Canada-U.S. reporting differences which would require explanatory paragraphs, following the opinion paragraph regarding changes in accounting principles), and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The schedule of revenues, royalties and expenses of the New Properties (relating to the EnCana assets) for the two years ended December 31, 2003 and 2002, included in this prospectus have been audited by PricewaterhouseCoopers LLP, Chartered Accountants, Calgary, Alberta, as stated in their report appearing herein (which audit report expresses an unqualified opinion), and has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

Information about Harvest's estimated proved reserves and the future net cash flow attributable to these reserves as of July 1, 2004 were consolidated by McDaniel & Associates Consultants Ltd., independent qualified reserves evaluators, based on individual reserve reports on various properties belonging to Harvest. These individual reserve reports were prepared by McDaniel & Associates Consultants Ltd., with respect to Harvest's properties to the end of 2003, McDaniel & Associates Consultants Ltd. and Paddock Lindstrom and Associates, independent qualified reserve evaluators, with respect to the Storm assets, and McDaniel & Associates Consultants Ltd. and Gilbert Laustsen Jung Associates Ltd., independent qualified reserves evaluators, with respect to the EnCana assets. As at the date hereof, the directors, officers and associates of each of McDaniel & Associates Consultants Ltd., Paddock Lindstrom and Associates and Gilbert Laustsen Jung Associates Ltd., as a group, own, directly or indirectly, less than 1% of Harvest's outstanding trust units.

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DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT

The following documents have been filed with the SEC as part of the registration statement:

•: The documents listed under "Documents Incorporated By Reference" in this prospectus;
•: Purchase Agreement dated October 7, 2004 by and among Harvest Operations Corp., Harvest Energy Trust, the Subsidiary Guarantors identified therein and the Initial Purchasers identified therein.
•: Registration Rights Agreement dated as of October 14, 2004 by and among Harvest Operations Corp., Harvest Energy Trust, the Subsidiary Guarantors identified therein and the Initial Purchasers identified therein.
•: Consent of McDaniel & Associates Consultants Ltd.
•: Consent of Paddock, Lindstrom and Associates, Ltd.
•: Consent of Gilbert Laustsen Jung Associates Ltd.
•: Consent of KPMG LLP.
•: Acknowledgement Letter of KPMG LLP.
•: Consent of Deloitte & Touche LLP.
•: Consent of PricewaterhouseCoopers LLP.
•: Consent of Burnet Duckworth & Palmer LLP.
•: Consent of Paul, Weiss, Rifkind, Wharton & Garrison LLP.
•: Powers of Attorney (included on the signature page hereto).
•: Indenture dated as of October 14, 2004 by and among Harvest Operations Corp., Harvest Energy Trust, the Subsidiary Guarantors identified therein and U.S. Bank National Association.
•: Statement of Eligibility of the Trustee on Form T-1.
•: Letter of Transmittal.
•: Notice of Guaranteed Delivery.
•: Instruction to Registered Holder from the Beneficial Owner.

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INDEX TO FINANCIAL STATEMENTS


Harvest Energy Trust Consolidated Financial Statements
	Independent Auditors' Report	F-2
	Consolidated Balance Sheets	F-3
	Consolidated Statements of Income and Accumulated Income	F-4
	Consolidated Statements of Cash Flow	F-5
	Notes to Consolidated Financial Statements	F-7
Harvest Energy Trust Pro Forma Consolidated Financial Statements
	Compilation Report	F-36
	Pro Forma Consolidated Statement of Income	F-37
	Notes to Pro Forma Consolidated Financial Statements	F-39
Storm Energy Ltd. Consolidated Financial Statements for the Period Ended March 31, 2004 (Unaudited)
	Consolidated Balance Sheet	F-46
	Consolidated Statement of Income and Retained Earnings	F-47
	Consolidated Statement of Cash Flows	F-48
	Notes to Consolidated Financial Statements	F-49
Storm Energy Ltd. Consolidated Financial Statements for the Period Ended December 31, 2003 and December 31, 2002
	Independent Auditors' Consent	F-59
	Report of Independent Registered Chartered Accountants	F-60
	Consolidated Balance Sheets	F-61
	Consolidated Statements of Income and Retained Earnings	F-62
	Consolidated Statements of Cash Flows	F-63
	Notes to Consolidated Financial Statements	F-64
New Properties Financial Statements
	Independent Auditors' Consent	F-79
	Independent Auditors' Report	F-80
	Schedule of Revenues, Royalties and Expenses	F-81
	Notes to Schedule of Revenues, Royalties and Expenses	F-82
Unaudited Supplemental Information on Oil and Gas Production Activities		F-83

F-1

AUDITORS' REPORT TO THE TRUSTEE OF HARVEST ENERGY TRUST
AND DIRECTORS OF HARVEST OPERATIONS CORP.

We have audited the consolidated balance sheets of Harvest Energy Trust as at December 31, 2003 and 2002 and the consolidated statements of income and accumulated income and cash flow for the year ended December 31, 2003 and for the period from July 10, 2002 (date of formation) to December 31, 2002. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those 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 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 flow for the year ended December 31, 2003 and for the period from July 10, 2002 (date of formation) to December 31, 2002 in accordance with Canadian generally accepted accounting principles.

Calgary, Canada		(Signed) KPMG LLP
April 15, 2004 except as to Note 18(a) which is as of December 23, 2004		Chartered Accountants

COMMENTS BY AUDITOR FOR U.S. READERS
ON CANADA-U.S. REPORTING DIFFERENCE

In the United States, reporting standards of the Public Company Accounting Oversight Board (United States) for auditors require the addition of an explanatory paragraph following the opinion paragraph when there is a change in accounting principles that has a material effect on the comparability of the Trust's financial statements, such as the changes described in Note 3 to the financial statements. Our report to the Trustee of Harvest Energy Trust and the Directors of Harvest Operations Corp. dated April 15, 2004 except as to Note 18(a) which is as at December 23, 2004 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditor's report when the change is properly accounted for and adequately disclosed in the financial statements.

Calgary, Canada		(Signed) KPMG LLP
December 23, 2004		Chartered Accountants

F-2

HARVEST ENERGY TRUST

CONSOLIDATED BALANCE SHEETS

		September 30, 2004			December 31, 2003			December 31, 2002
		(Unaudited)			(Restated — Note 4)			(Restated — Note 4)
		(Thousands of Canadian dollars)
Assets
Current assets
	Cash and short term investments	$	—		$	—		$	4,503
	Accounts receivable		56,024			19,168			13,578
	Prepaid expenses and deposits		15,272			12,131			534

			71,296			31,299			18,615
Deferred financing charges, net of amortization			4,116			1,989			2,210
Future income tax (Note 14)			—			12,609			1,480
Property, plant and equipment (Notes 4, 5, 6 and 7)			965,028			210,543			86,142
Goodwill (Note 6)			29,576			—			—

		$	1,070,016		$	256,440		$	108,447

Liabilities and Unitholders' Equity
Current liabilities
	Accounts payable and accrued liabilities	$	65,741		$	18,083		$	6,029
	Cash distributions payable		7,371			3,422			1,863
	Current portion of commodity derivative contracts (Note 15)		23,333			—			—
	Bank debt (Note 8)		401,556			63,349			45,286

			498,001			84,854			53,178
Long term portion of commodity derivative contracts (Note 15)			6,063			—			—
Asset retirement obligation (Note 4)			96,200			42,009			15,566
Future income tax (Notes 6 and 14)			19,129			—			—

			619,393			126,863			68,744

Unitholders' equity
	Unitholders' capital (Note 10)		392,356			117,407			36,728
	Exchangeable shares (Note 11)		8,167			—			—
	Equity bridge notes (Notes 9 and 17)		10,000			25,000			—
	Convertible debentures (Note 13)		91,821			—			—
	Accumulated income		19,558			19,478			4,832
	Contributed surplus		1,008			239			5
	Accumulated cash distributions		(72,287	)		(32,547	)		(1,862	)

			450,623			129,577			39,703

		$	1,070,016		$	256,440		$	108,447

Subsequent events (Note 18)
Commitments and contingencies (Note 19)

See accompanying notes to consolidated financial statements.

F-3

HARVEST ENERGY TRUST

CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED INCOME

		Nine months ended
		September 30, 2004			September 30, 2003			Year ended December 31, 2003			Period from July 10 (date of formation) to December 31, 2002
		(Unaudited)			(Unaudited)			(Restated — Note 4)			(Restated — Note 4)
					(Restated — Note 4)
		(Thousands of Canadian dollars, except per trust unit amounts)
Revenue
	Oil and natural gas sales	$	202,681		$	79,407		$	119,351		$	22,709
	Royalty expense, net		(33,031	)		(10,045	)		(16,412	)		(2,745	)
	Hedging loss		(37,761	)		(15,821	)		(18,924	)		(1,009	)
	Mark to market loss on commodity derivative contracts (Note 15)		(29,396	)		—			—			—

			102,493			53,541			84,015			18,955
Expenses
	Operating		46,267			23,061			36,045			6,396
	General and administrative		6,049			2,087			4,340			577
	Interest		3,919			1,807			2,975			2,010
	Finance charges and amortization of deferred finance charges		1,845			1,579			2,607			636
	Depletion, depreciation and accretion		53,002			24,275			35,727			6,192
	Foreign exchange gain		(565	)		(5,313	)		(4,374	)		(255	)

			110,517			47,496			77,320			15,556

Income (loss) before taxes			(8,024	)		6,045			6,695			3,399
Taxes
	Large corporation tax		256			138			157			47
	Future tax recovery (Note 14)		(13,796	)		(3,906	)		(8,978	)		(1,480	)

Net income for the period			5,696			9,813			15,516			4,832
Interest on equity bridge notes (Note 9 and 17)			(658	)		(205	)		(870	)		—
Interest on convertible debentures (Note 13)			(4,958	)		—			—			—
Accumulated income, beginning of period			19,478			4,832			4,832			—

Accumulated income, end of period		$	19,558		$	14,440		$	19,478		$	4,832

Net income per trust unit (Notes 10 and 12)
	Income per trust unit, basic	$	—		$	0.86		$	1.16		$	3.47

	Income per trust unit, diluted	$	—		$	0.84		$	1.13		$	3.27

See accompanying notes to consolidated financial statements.

F-4

HARVEST ENERGY TRUST

CONSOLIDATED STATEMENTS OF CASH FLOW

			Nine months ended
			September 30, 2004			September 30, 2003			Year ended December 31, 2003			Period from July 10 (date of formation) to December 31, 2002
			(Unaudited)			(Unaudited)			(Restated — Note 4)			(Restated — Note 4)
						(Restated — Note 4)
			(Thousands of Canadian dollars, except per trust unit amounts)
Cash provided by (used in)
Operating Activities
	Net income for the period		$	5,696		$	9,813		$	15,516		$	4,832
	Items not requiring cash
		Depletion, depreciation and accretion		53,002			24,275			35,727			6,192
		Foreign exchange		1,256			997			1,432			(255	)
		Amortization of deferred finance charges		1,845			1,579			2,556			210
		Mark to market loss on commodity derivative contracts (Note 15)		29,396			—			—			—
		Future tax recovery		(13,976	)		(3,906	)		(8,978	)		(1,480	)
		Unit based compensation		769			37			236			5

	Cash flow from operations			77,988			32,795			46,487			9,504
	Site restoration and reclamation expenditures			(307	)		—			(577	)		—
	Change in non-cash working capital (Note 16)			(12,405	)		6,449			(12,286	)		(6,974	)

				65,276			39,244			33,624			2,530

Financing Activities
	Issue of trust units, net of costs			165,932			13,631			61,691			31,728
	Issue of trust units under the distribution reinvestment plan, net of costs (Note 10)			7,063			7,385			10,638			—
	Issue of bridge note payable			—			25,000			—			—
	Issue of equity bridge notes (Notes 9 and 17)			30,000			33,500			33,500			—
	Repayment of equity bridge notes (Notes 9 and 17)			(45,000	)		—			(8,500	)		—
	Interest on equity bridge notes			(658	)		—			(205	)		—
	Issuance of convertible debentures, net of costs			152,834			—			—			5,000
	Interest on convertible debentures			(4,958	)		—			—			—
	Increase in bank debt			624,065			41,864			143,661			60,203
	Repayment of bank debt			(344,294	)		(86,684	)		(128,398	)		(14,661	)
	Repayment of promissory note payable			—			(850	)		(850	)		—
	Financing costs			(3,973	)		(542	)		(2,334	)		(2,420	)
	Cash distributions			(39,740	)		(19,833	)		(29,126	)		—
	Change in non-cash working capital (Note 16)			5,841			642			2,224			781

				547,112			14,113			82,301			80,631

F-5

Investing Activities
	Acquisition of properties		(513,815	)		—			(90,549	)		(76,153	)
	Additions to property, plant and equipment		(33,822	)		(34,012	)		(27,209	)		(770	)
	Acquisition of a private company (Note 5)		—			(3,000	)		(3,000	)		—
	Acquisition of Storm Energy Ltd. (Note 6)		(75,000	)		—			—			—
	Proceeds on disposition of property, plant and equipment		—			—			—			155
	Change in non-cash working capital (Note 16)		10,249			(3,444	)		330			(1,890	)

			(612,388	)		(40,456	)		(120,428	)		(78,658	)

Increase (decrease) in cash and short-term investments			—			12,901			(4,503	)		4,503
Cash, beginning of period			—			4,503			4,503			—

Cash, end of period		$	—		$	17,404		$	—		$	4,503

Cash interest payments		$	4,375		$	1,687		$	2,866		$	1,887
Cash tax payments		$	527		$	138		$	157		$	—
Cash distributions declared per unit		$	1.80		$	1.80		$	2.40		$	0.20

See accompanying notes to consolidated financial statements.

F-6

HARVEST ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information as at September 30, 2004 and for the Nine Month Periods Ended
September 30, 2004 and 2003 is unaudited
(tabular amounts in thousands of Canadian dollars, except 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 trust indentures 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 acquired and held by Harvest Operations and its subsidiary Redearth Energy Inc. The Trust acquires and holds net profit interests in oil and natural gas properties in Saskatchewan and held by Harvest Sask Energy Trust. The Trust is the sole unitholder of the Harvest Sask. Energy Trust. The Trust recently acquired additional properties (note 5) in a partnership directly and indirectly owned by 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 the Trust have been prepared by management in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). See note 20 for a discussion and reconciliation of the differences between Canadian GAAP and U.S. GAAP as they relate to these consolidated financial statements.

(a) Consolidation

These consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries. All inter-entity transactions and balances have been eliminated upon consolidation.

(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 and amounts used for the ceiling test calculation 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.

Revenues associated with the sale of the subsidiaries' crude oil, natural gas and natural gas liquids are recognized when title passes from the subsidiaries to their customers.

(d) Cash and short-term investments

Short-term investments with maturities less than three months are considered to be cash equivalents and are recorded at cost, which approximate market value.

(e) Joint venture accounting

The subsidiaries of the Trust conduct substantially all of their oil and natural gas production activities through joint ventures, and the accounts reflect only their proportionate interest in such activities.

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(f) Property, plant and equipment

The Trust follows the full cost method of accounting. All costs of acquiring oil and natural gas properties and related exploration and development costs, including overhead charges directly related to these activities, are capitalized and accumulated in one cost center. 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.

Impairment

The Trust places a limit on the aggregate carrying value of its property, plant and equipment, which may be amortized against revenues of future periods.

Impairment is recognized if the carrying amount of the property, plant and equipment 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 and are adjusted for the Trust's contracted prices and quality differentials.

Upon recognition of impairment, the Trust would then measure the amount of impairment by comparing the carrying amounts of the property, plant and equipment to an amount equal to the estimated net present value of future cash flows from proved plus risked 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 recorded as a permanent impairment.

The cost of unproved properties are excluded from the ceiling test calculation and subject to a separate impairment test.

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 the normal use of the assets. 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 gross proved reserves. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.

Depletion, depreciation and accretion

Provision for depletion and depreciation of petroleum and natural gas assets is calculated on the unit-of-production method, based on proved reserves before royalties as estimated by independent petroleum engineers. The basis used for the calculation of the provision is the capitalized costs of petroleum and natural gas assets plus the estimated future development costs of proved undeveloped

F-8

reserves. Reserves are converted to equivalent units on the basis of six thousand cubic feet of natural gas to one barrel of oil.

Depreciation and amortization of office furniture and equipment is provided for at rates ranging from 20% to 50% per annum.

(g) 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 (Note 6). The goodwill balance is assessed for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The Trust first tests for possible impairment by comparing unitholders' equity to the fair value of the reporting entity. If the fair value of the consolidated Trust 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.

(h) Income taxes

The Trust and its trust entity subsidiaries are taxable entities under the Income Tax Act (Canada) and are taxable only on income that is not distributed or distributable to the unitholders. As both the Trust and Harvest Sask. Energy Trust plan to distribute all of their taxable income to their respective unitholders and meet the requirements of the Income Tax Act (Canada) applicable to a Trust, neither the Trust nor Harvest Sask. Energy Trust 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. Temporary differences arising on acquisitions result in future income tax assets and liabilities.

(i) Unit-based compensation

The Trust uses the fair value method of accounting for the Trust Unit incentive plan (Note 12). 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 compensation expense is recognized in the statement of income over the vesting period of the associated unit appreciation right.

(j) 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.

F-9

(k) Financial instruments

Harvest Operations enters into financial instruments to manage its exposure to adverse fluctuations in commodity prices, foreign currency exchange rates, electricity costs and interest rates. Harvest Operation's policy is not to utilize derivative financial instruments for trading or speculative purposes. Realized gains or losses on financial instruments that are designated and assessed effective as hedges are recognized in income concurrently with the underlying hedged transaction. If the hedge of an anticipated transaction is terminated or ceases to be effective, the associated gain or loss at that date is deferred and recognized concurrently with the anticipated transaction. Subsequent changes in value of the financial instruments are reflected in income.

(l) 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.

(m) Comparative figures

Certain prior period's comparative figures have been reclassified to conform to the current year's presentation.

3. CHANGES IN ACCOUNTING POLICY

(a) Trust unit incentive plan

Effective January 1, 2003 the Trust has elected to prospectively adopt the amendments to CICA Handbook section 3870 "Stock-based Compensation and Other Stock-based payments". Under this section, the Trust has chosen to recognize compensation expense when trust unit rights are granted under the trust unit incentive plan with no cash settlement features on a prospective basis. As such, compensation expense has been calculated on all trust unit rights issued on or subsequent to January 1, 2003. The fair value of trust unit rights issued has been determined using a binomial option pricing model. The binomial model has been utilized by the Trust as it allows the calculation of the fair value of a trust unit right with a decreasing exercise price, based on the distributions paid from the date of issue to the date of vesting.

(b) Full cost accounting guideline

Effective January 1, 2004, the Trust has adopted the CICA 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 the net income, property plant and equipment or any other financial statement amounts as a result of the implementation of this guideline.

F-10

Effective January 1, 2004, the Trust has adopted the CICA Handbook standard for accounting for asset retirement obligation. This standard has been applied retroactively with all prior period financial statements and comparatives adjusted as described in Note 4 of the consolidated financial statements.

(d) Financial instruments

Effective January 1, 2004, the Trust has implemented CICA Accounting Guideline 13 "Hedging Relationships". This guideline addresses the identification, designation and effectiveness of financial contracts for the purpose of application of 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 instruments in income. (Note 15)

4. ASSET RETIREMENT OBLIGATION

The Trust's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Trust estimates the total undiscounted amount of cash flow required to settle its asset retirement obligations, gross of salvage proceeds, is approximately $182 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 7.5 percent was used to calculate the fair value of the asset retirement obligations.

A reconciliation of the asset retirement obligation is provided below:

	Nine month period ended September 30,
										Period from July 10 (date of formation) to December 31, 2002
							Year ended December 31, 2003
	2004			2003			Year ended December 31, 2003
*Asset retirement obligations*
Balance, beginning of period	$	42,009		$	15,566		$	15,566		$	—
Liabilities incurred in the period		51,611			11,406			25,175			15,274
Liabilities settled in the period		(307	)		(125	)		(577	)		—
Accretion expense		2,887			1,183			1,845			292

Balance, end of period	$	96,200		$	28,030		$	42,009		$	15,566

F-11

The effect of the change in accounting policy (Note 3) has been recorded retroactively with restatement of prior periods as follows;

	As at December 31, 2003			As at December 31, 2002
*Balance sheet*
Asset retirement costs, included in property, plant and equipment	$	35,166		$	14,510
Asset retirement obligations		42,009			15,566
Site restoration provision		(4,321	)		(544	)
Future income tax asset		1,024			208
Accumulated income	$	(1,498	)	$	(304	)

	Nine month period ended September 30, 2003			Year ended December 31, 2003			Period from July 10 (date of formation) to December 31, 2002
*Income statement*
Accretion expense	$	1,183		$	1,845		$	292
Depletion and depreciation on asset retirement costs		2,911			4,520			764
Site restoration and reclamation		(2,655	)		(4,355	)		(544	)
Future tax recovery		(585	)		(816	)		(208	)

Net earnings change	$	(854	)	$	(1,194	)	$	(304	)

Basic net earnings change per trust unit	$	(0.08	)	$	(0.10	)	$	(0.22	)

Diluted net earnings change per trust unit	$	(0.08	)	$	(0.09	)	$	(0.21	)

5. ACQUISITIONS

On September 2, 2004, the Trust purchased oil and gas producing properties from EnCana Corporation for cash consideration of approximately $526 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 10), and $100 million in 8% convertible unsecured subordinated debentures (Note 13). The balance of the acquisition cost was funded with a new credit facility arrangement (Note 8). In association with the purchase, an asset retirement obligation in the amount of $45.1 million was recorded (Note 4). The Trust has not yet finalized the statements of adjustments and therefore, the acquisition cost may be subject to change.

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 (Note 10), $3 million in cash and an $850,000 unsecured

F-12

demand promissory note that bears interest at 10% per annum effective June 27, 2003. The acquisition has been accounted for using the purchase price method.

	Amount
*Acquisition of Private Company*
Property, plant & equipment	$	15,400
Working capital, net		(2,501	)
Bank debt		(2,799	)

	$	10,100

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 (Note 10) with the balance being funded by bank debt.

6. PLAN OF ARRANGEMENT WITH STORM ENERGY LTD.

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 $189.2 million. This amount consisted of the issuance of 2,720,837 trust units at a price of $14.77 per unit (Note 10), the issuance of 600,587 exchangeable shares (Note 11), $75 million in cash, the assumption of approximately $58.5 million in debt and a working capital deficit of $6.7 million. The acquisition was financed with the new credit facility (Note 8) and with a draw on the equity bridge notes (Note 9). 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. The Trust has not yet completed its final calculation of the assets acquired and liabilities assumed and therefore, the purchase price allocation may be subject to change.

	Amount
Property, plant & equipment	$	211,829
Goodwill		29,576
Working capital, net		(6,669	)
Bank debt		(58,472	)
Asset retirement obligation		(6,477	)
Future income tax		(45,734	)

	$	124,053

Consideration for the acquisition:
Cash	$	75,000
Issuance of trust units		40,183
Issuance of exchangeable shares		8,870

	$	124,053

F-13

7. PROPERTY, PLANT AND EQUIPMENT

	September 30, 2004
	Cost		Accumulated depletion, depreciation and amortization			Net book value
Oil and natural gas properties	$	849,005	$	(71,794	)	$	777,211
Production facilities and equipment		204,918		(17,947	)		186,971
Office furniture and equipment		1,187		(341	)		846

	$	1,055,110	$	(90,082	)	$	965,028

	December 31, 2003
	Cost		Accumulated depletion, depreciation and amortization			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

	$	250,308	$	(39,765	)	$	210,543

	December 31, 2002
	Cost		Accumulated depletion, depreciation and amortization			Net book value
Oil and natural gas properties	$	70,463	$	(4,605	)	$	65,858
Production facilities and equipment		21,343		(1,272	)		20,071
Office furniture and equipment		236		(23	)		213

	$	92,042	$	(5,900	)	$	86,142

General and administrative costs of $1.8 million, $0.7 million, $1.3 million and $0.2 million have been capitalized during the nine months ended September 30, 2004 and September 30, 2003, the year ended December 31, 2003 and period ended December 31, 2002, respectively.

All costs are subject to depletion and depreciation at September 30, 2004. In addition, future development costs of $70.2 million, $8.3 million, $15.2 million and $9.9 million are included in depletion and depreciation calculations at September 30, 2004, September 30, 2003, December 31, 2003 and December 31, 2002.

In accordance with Canadian GAAP, the Trust has performed a ceiling test as at September 30, 2004 using forecast commodity prices with net future revenues discounted at the Trust's risk free interest rate, which resulted in a ceiling test excess.

F-14

8. BANK DEBT

On September 1, 2004, Harvest Operations Corp. entered into an amended credit agreement with a syndicate of Canadian chartered banks and the Alberta Treasury Branches. This facility consists of a $355 million production loan, a $15 million operating loan, a $70 million equity bridge facility and a US$18.8 million mark to market credit to be used for financial instrument hedging. The term of the facility is to June 29, 2005. The facility permits drawings in Canadian or U.S. dollars, and includes bankers acceptances, LIBOR 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 floating charge over all of the assets of the Corporation, and a guarantee by the Trust and its subsidiaries. Under the terms of this credit agreement, the equity bridge facility was provided to assist in the closing of the EnCana asset acquisition (Note 5). This facility matures on June 29, 2005, and outstanding balances under this facility bear interest at progressive rates of 3% to 8% above the applicable Canadian prime rate. The equity bridge facility is to be repaid with the net proceeds of any debt or equity financing completed subsequent to its issuance. Distributions to the Trust's unitholders, and payments on the Equity Bridge notes (Note 9), and the convertible debentures (Note 13) are subordinate to the bank debt. The credit facility agreement includes certain restrictive covenants, including a working capital ratio as defined under the agreement, of at least one to one and a requirement that Harvest not hedge more than 75% of its net after royalty production. See note 18.

On October 16, 2003, Harvest Operations Corp. entered into a credit agreement with a syndicate of Canadian chartered banks and the Alberta Treasury Branches. The revolving reducing bank debt provides a borrowing base of $89 million with availability reducing by $4.5 million on the last day of each calendar month starting January 31, 2004. The bank debt permits drawings in Canadian or U.S. dollars, and include bankers acceptances, LIBOR, $10 million in letters of credit and a $3 million mark to market facility to be used for financial instrument hedging. The bank debt bears interest at rates ranging from 0.25% to 2% above the applicable Canadian or U.S. prime rate depending upon the type of borrowing and the debt to annualized cash flow ratio. The bank debt is secured by a $150 million debenture with a floating charge over all of the assets of Harvest Operations Corp. This facility was extinguished and replaced with the new facility described above.

9. EQUITY BRIDGE NOTES

On July 28, 2003, the Trust entered into two equity bridge note agreements, which provide for advances in aggregate of up to $40 million. The terms and conditions are identical for both agreements, which is comprised of a $30 million agreement with a corporation controlled by a director of Harvest Operations, and a $10 million agreement with a director of Harvest Operations.

Under the terms of the agreements, interest is paid quarterly in arrears and is calculated daily at a fixed rate of 10% per annum. The Trust has the option to settle the quarterly interest payments with cash or the issue of trust units. If the Trust elects to issue trust units, the number of trust units to be issued to settle a quarterly payment shall be the equivalent to the quarterly payment amount divided by 90% of the most recent ten-day weighted average trading price.

The Trust also has the option to repay the principal amounts outstanding at any time. If the Trust chooses to partially repay the outstanding principal amount, such payment is to be made in cash. If the Trust elects to repay the full principal amount plus the accrued quarterly payment at maturity, the Trust then has the option to settle its obligation with cash or with the issue of trust units. The terms to settle with units is the

F-15

same as with the interest option described above. The outstanding principal portion and all accrued and unpaid interest on the equity bridge note agreements is due and payable in full on July 31, 2005. Security has been provided in the form of a fixed and floating debenture on the Trust's NPI. The equity bridge lenders may demand payment of the full amount if specified events of default under the equity bridge note agreements occur. On September 29, 2003, the equity bridge note agreements were amended to extend the uses permitted under the previous agreements, to include repayment of bank debt. As at December 31, 2003, there was $25 million drawn on the equity bridge notes, and accrued interest of $665,069 which was paid on January 2, 2004. Interest in respect of the equity bridge notes is a charge to unitholders' equity and not included in income.

On January 26 and 29, 2004, the Trust repaid the two equity bridge notes outstanding in the amounts of $7.4 million and $17.6 million, respectively. During the nine months ended September 30, 2004, the Trust also paid the accrued and outstanding interest in the amount of $1,521,407.

On June 29 and July 9, 2004, the Trust drew $25 million and $5 million respectively, under the equity bridge note agreement. This agreement is with a corporation controlled by a director of Harvest Operations Corp, respectively. On August 11, 2004 the Trust repaid $20 million of this balance with proceeds from subscription receipts issued (Note 10). Interest in respect of the equity bridge notes accrues at 10% per annum and is a charge to unitholders' equity and is not included in income.

10. UNITHOLDERS' CAPITAL

(a) Authorized

The authorized capital consists of an unlimited number of trust units.

Each trust unitholder is entitled to a beneficiary interest in any distribution of the Trust and in any net assets in the event of termination or wind-up. Trust units are redeemable at any time at the option of the holder. The redemption price is equal to the lesser of 95% of the average market price of the trust units during a 10 day period commencing immediately after the redemption date and the closing market price on the redemption date. The total amount payable by the Trust in respect of redemptions in any calendar month shall not exceed $100,000. To the extent that a unitholder is entitled to a redemption payment, it will be satisfied by a cash payment from the Trust or by the Trust distributing a pro-rata number of Harvest Operations notes or distributing its own notes.

(b) Issued

	Number of units		Amount
Issued for cash on formation⁽ⁱ⁾	100		$	100
Initial public offering⁽ⁱⁱ⁾	4,312,500			34,500
Settlement of debenture⁽ⁱⁱⁱ⁾	5,000,000			5,000
Cancellation of the initial units issued on formation⁽ⁱ⁾	(100	)		(100	)
Unit issue costs	—			(2,772	)

As at December 31, 2002	9,312,500		$	36,728

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Exercise of warrants^(iv)	150,000	$	150
Special warrant exercise^(v)	1,500,000		15,000
Acquisitions^(vi)	825,000		8,350
Trust unit issue^(vii)	4,312,500		48,645
Distribution reinvestment plan issuance^(xii)	1,009,006		10,638
Unit issue costs	—		(2,104	)

As at December 31, 2003	17,109,006	$	117,407

Unit appreciation rights exercise^(viii)	68,750	$	295
Storm Plan of Arrangement^(ix)	2,720,837		40,183
Conversion of subscription receipts^(x)	12,166,666		175,200
Convertible debenture conversions^(xi)	4,277,216		63,866
Exchangeable Share retraction^(xii)	48,896		703
Distribution reinvestment plan issuance^(xiii)	483,458		7,063
Unit issue costs	—		(12,361	)

As at September 30, 2004	36,874,829	$	392,356

(i): On July 10, 2002, the Trust issued 100 units for cash proceeds of $100. As per the agreement on the initial issuance, the units were cancelled upon the completion of the initial public offering on December 5, 2002.
(ii): On December 5, 2002, the Trust issued 3,750,000 trust units for $27.6 million, net of a 6% underwriters' fee and $702,003 of issue costs. The net proceeds were used to fully repay a loan from a corporation controlled by a director of Harvest Operations and partially repay the bank loans. In conjunction with this initial public offering, the Trust granted the underwriters an option, to purchase up to an additional 562,500 trust units at a price of $8.00 per unit. On December 17, 2002, the underwriters exercised the option; the net proceeds were used to partially repay the bank loans.
(iii): Upon completion of the initial public offering the Trust paid the trust debenture principal and interest thereon, by the issuance of 5,000,000 trust units and a cash payment of $34,829.
(iv): On January 24, 2003, 150,000 trust units were issued to a corporation controlled by a director of Harvest Operations on the exercise of a warrant. The $150,000 in proceeds was added to working capital.
(v): On March 7, 2003, 1,500,000 special warrants were exercised into trust units. The special warrants were issued on February 4, 2003 for $13,700,000 net of a 5% underwriters' fee and approximately $550,000 of issues costs.
(vi): On May 27, 2003, the Trust issued 200,000 trust units at a price of $10.50 per trust unit, for consideration of the purchase of a crude oil producing property.

On June 27, 2003, the Trust issued 625,000 trust units at a price of $10.00 per trust unit, for partial consideration of the purchase of a private company (Note 5).
(vii): On October 16, 2003, the Trust issued 4,312,500 trust units at a price of $12.00 per trust unit, for proceeds of $51.75 million net of a 6% underwriters' fee and $346,000 of issue costs. The net proceeds were used to partially fund the acquisition of Carlyle properties in South East Saskatchewan.
(viii): During the nine month period ended September 20, 2004, 68,750 Trust Unit appreciation rights were exercised, for proceeds of $294,500.
(ix): On June 30, 2004, 2,720,837 trust units were issued under the Plan of Arrangement with Storm Energy Ltd. (Note 6)

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(x): On September 2, 2004, the subscription receipts issued on August 10, 2004 were converted into trust units in connection with the closing of the EnCana asset purchase. (Note 5)
(xi): During the nine month period ended September 30, 2004, 35,085 9% convertible debentures and 28,781 8% convertible debentures were converted at the option of the holders, into 4,277,216 trust units and $987,847 in accrued interest and fractional units. (Note 13)
(xii): During the period ended September 30, 2004, 47,615 exchangeable shares were retracted at the option of the holder, and converted into 48,896 trust units. (Note 11)
(xiii): For the nine month period ended September 30, 2004 and the year ended December 31, 2003, 483,458 trust units in the amount of $7.1 million and 1,009,006 trust units in the amount of $10.6 million were issued under the distribution reinvestment plan ("DRIP").

The following table summarizes the trust units used in calculating income per trust unit:

	Nine month period ended September 30,
							Period from July 10 (date of formation) to December 31, 2002
					Year ended December 31, 2003
	2004		2003		Year ended December 31, 2003
Weighted average trust units outstanding	$	20,938,137	$	11,383,042	$	12,590,937	$	1,391,608
Weighted average exchangeable shares outstanding		205,084		—		—		—

Weighted average trust units outstanding, basic		21,143,221		11,383,042		12,590,937		1,391,608
Effect of trust unit appreciation rights		570,771		360,157		411,868		87,500

Weighted average trust units outstanding, diluted	$	21,713,992	$	11,743,199	$	13,002,805	$	1,479,108

The income (loss) per trust unit is calculated on the basis of net income available to the Trust Unitholder, and as such deducts the interest on the equity bridge notes and convertible debentures in the numerator of the calculation.

For purposes of the per trust unit information, the interest on the convertible debentures and equity bridge notes is deducted in determining income available to trust unitholders as follows:

	Nine month period ended September 30,
							Period from July 10 (date of formation) to December 31, 2002
					Year ended December 31, 2003
	2004		2003		Year ended December 31, 2003
Amount deducted	$	5,616	$	205	$	870	$	—

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11. EXCHANGEABLE SHARES

(a) Authorized

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

(b) Issued

Exchangeable shares, series 1

	Number		Amount
Storm Plan of Arrangement	600,587		$	8,870
Shareholder retractions	(47,615	)		(703	)

As at September 30, 2004	552,972		$	8,167

On June 30, 2004, 600,587 exchangeable shares, series 1 were issued at $14.77 per exchangeable share as partial consideration for the Plan of Arrangement with Storm (Note 6). The exchangeable shares had an exchange ratio of 1:1.04703 at October 15, 2004.

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 by Harvest Operations at any date subsequent to June 30, 2006 until June 30, 2009, at which time all remaining exchangeable shares in this series will be redeemed. Harvest Operations also has the option to convert up to 20% of the initial amount of the exchangeable shares outstanding annually in the first 90 days of each calendar year, and may also redeem all of the exchangeable shares if the aggregate amount outstanding is less than 500,000.

12. TRUST UNIT INCENTIVE PLAN

A trust unit incentive plan has been established whereby 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. The initial exercise price of rights granted under the plan is equal to the closing market price on the date immediately prior to the date the rights are granted and the maximum term of each right is not to exceed five years. The exercise price of the rights is adjusted downwards from

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time to time based upon the cash distributions made on the trust units if the minimum distribution rate is met. The following summarizes the trust units reserved for issuance under the trust unit incentive plan:

	Trust unit rights		Weighted average exercise price
Granted on November 25, 2002	787,500		$	8.00
Average reduction in exercise price due to distributions	—			(0.20	)

As at December 31, 2002	787,500			7.80
Granted	277,650			11.93
Average reduction in exercise price due to distributions	—			(2.02	)

As at December 31, 2003	1,065,150		$	6.86
Granted	370,000			15.66
Cancelled	(83,375	)		(5.36	)
Exercised for trust units	(111,000	)		(3.80	)
Exercised for cash	(11,250	)		(6.81	)
Average reduction in exercise price due to distributions	—			(1.26	)

As at September 30, 2004	1,230,225		$	8.22

All of the trust unit rights outstanding vest equally over the four years following their anniversary date.

For purposes of estimating fair value disclosures below, the fair value of each trust unit right has been estimated on the grant date using the following weighted-average assumptions:

	Nine month period ended
	Nine month period ended						Period from July 10 (date of formation) to December 31, 2002
	September 30, 2004		September 30, 2003		Year ended December 31, 2003
Expected volatility		23.3%		23.3%		23.3%		25.6%
Risk free interest rate		4.0%		3.5%		4.1%		3.0%
Expected life of the trust unit rights		4 years		4 years		4 years		4 years
Estimated annual distributions per unit	$	2.40	$	2.40	$	2.40	$	2.40

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For the purposes of pro forma disclosures, the estimated fair value of all of the trust unit rights issued subsequent to December 31, 2002 is amortized to expense over the vesting periods. The Trust's pro forma net income and per trust unit amounts would have been accounted for as follows:

								Period from July 10 (date of formation) to December 31, 2002
		Nine month period ended
		September 30, 2004		September 30, 2003		Year Ended December 31, 2003
Net income	As reported	$	5,696	$	9,813	$	15,516	$	4,832
	Pro forma	$	4,548	$	8,668	$	14,228	$	4,665
Income per unit — basic	As reported	$	0.07	$	0.86	$	1.16	$	3.47
	Pro forma	$	0.05	$	0.76	$	1.06	$	3.35
Income per unit — diluted	As reported	$	0.07	$	0.84	$	1.13	$	3.27
	Pro forma	$	0.05	$	0.74	$	1.03	$	3.15

The Trust has recognized $0.8 million, $37,000, $0.2 million and $4,500 during the nine months ended September 30, 2004 and September 30, 2003, the year ended December 31, 2003 and period ended December 31, 2002, respectively, in compensation expense and included it in general and administrative expense in the consolidated statement of income and accumulated income.

13. CONVERTIBLE DEBENTURES

On January 29, 2004, the Trust closed an issue of 60,000 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 when completed. The Trust may also elect to redeem the debentures with the issue 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. Under both redemption options, the Trust may elect to pay both the debenture and accrued interest in the form of trust units. A settlement in trust units is subject to specified notice and regulatory approval.

On August 10, 2004, the Trust closed an issue of 100,000 8% convertible unsecured subordinated debentures due September 30, 2009, for gross total proceeds of $100 million. 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

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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 when completed. The Trust may also elect to redeem the debentures upon maturity with the issue 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. Under both redemption options, the Trust may elect to pay both the debenture and accrued interest in the form of trust units. This convertible debenture issuance ranks pari-passu with the outstanding debentures issued on January 29, 2004.

The following table summarizes the issuance and conversions of the convertible debentures:

	9% Series					8% Series
	Number of debentures		Amount			Number of debentures		Amount			Total
January 29, 2004 issuance	60,000		$	60,000							$	60,000
August 10, 2004 issuance						100,000		$	100,000			100,000
Converted for Trust Units⁽ⁱ⁾	(35,085	)		(35,085	)	(28,781	)		(28,781	)		(63,866	)
Convertible debenture issue costs	—			(1,108	)	—			(3,205	)		(4,313	)
As at September 30, 2004	24,915		$	23,807		71,219		$	68,014		$	91,821

(i): During the nine months ended September 30, 2004, 35,085 and 28,781 convertible debentures were converted at the option of the holders, into 2,506,056 and 1,771,130 Trust Units and $766,904 and $220,943 in accrued interest and fractional units for the 9% and 8% series, respectively.

14. INCOME TAXES

Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities of Harvest Operations for financial reporting purposes and the amounts used for income tax purposes. During 2003, legislation regarding the reduction of certain Federal and Provincial corporate income tax rates have received Royal Assent. These rate changes are expected to be applied in varying degrees until fully in place in 2007, and have resulted in an effective tax rate of approximately 34% for the Trust, to be applied on the temporary difference in the future tax calculation.

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The provisions 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:

		Nine month period ended
		Nine month period ended									Period from July 10 (date of formation) to December 31, 2002
		September 30, 2004			September 30, 2003			Year ended December 31, 2003
Income (loss) before taxes		$	(8,024	)	$	6,045		$	6,695		$	3,399
Computed income tax expense at the statutory rates of 38.9%, 42.1%, 40.6% and 42.1%, respectively			(3,121	)		2,545			2,718			1,431
Amount included in Trust income			(5,263	)		(11,117	)		(13,293	)		(2,912	)

			(16,408	)		(2,527	)		(10,575	)		(1,481	)
Increase (decrease) resulting from the following:
	Non-deductible crown royalties and other payments		1,143			320			(61	)		9
	Federal resource allowance		(26	)		536			2,062			(17	)
	Unit appreciation rights expense		299			—			99			—
	Foreign exchange gain		216			(2,236	)		(1,282	)		—
	Rate change		967			—			794			—
	Other		13			1			(15	)		9

Future income tax recovery		$	(13,796	)	$	(3,906	)	$	(8,978	)	$	(1,480	)

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

		As at September 30, 2004			As at December 31, 2003		As at December 31, 2002
Future tax assets (liabilities):
	Tax pools of oil and natural gas in excess of (less than) net book value	$	(19,724	)	$	9,806	$	761
	Resource allowance		595			1,203		172
	Tax loss carryforwards		—			1,600		547

Net future tax asset (liability)		$	(19,129	)	$	12,609	$	1,480

15. 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.

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(a) Fair values

Financial instruments of the Trust consist mainly of cash and short term investments, accounts receivable, prepaid expenses and deposits, accounts payable and accrued liabilities, distributions payable, and bank debt. As at September 30, 2004, there were no significant differences between the carrying amounts of these financial instruments reported on the balance sheet and their estimated fair value.

(b) Interest rate risk

The Trust is exposed to interest rate risk on its demand loan.

Substantially all of the 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 the 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. During 2003 and 2004, the Trust borrowed funds denominated in U.S. dollars as an economic hedge of the impact of exchange rates on sales during the year.

(e) Commodity risk management

The Trust uses oil sales contracts and derivative financial instruments to comply with this requirement. 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 commodity price 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.

The following is a summary of the oil sales contracts with price swap or collar features as at September 30, 2004, that have fixed future sales prices:

Commodity swap contracts based on West Texas Intermediate

Daily Quantity	Term	Price per Barrel (Note 1)	Mark to Market Gain (Loss)
500 Bbls/d	October through December 2004	US$24.12 ($15.50)	$	(1,035	)⁽ⁱ⁾
3,325 Bbls/d	October through December 2004	US$25.24		(8,040	)
500 Bbls/d	January through December 2005	US$24.00		(4,829	)
1,100 Bbls/d	January through March 2005	US$22.38		(3,153	)
1,030 Bbls/d	April through June 2005	US$22.18		(2,777	)

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Commodity swap contracts based on the Lloydminster Blend Crude differential

Daily Quantity		Term		Price per Barrel (Note 1)		Mark to Market Gain
4,500 Bbls/d		October through December 2004		US($7.82)		$	2,933

Commodity collar contracts based on West Texas Intermediate

Daily Quantity	Term	Price per Barrel (Note 1)	Mark to Market Gain (Loss)
2,500 Bbls/d	October through December 2004	US$22.00 – 28.10	$	(3,994	)
3,000 Bbls/d	October through December 2004	US$25.19 – 29.40 ($18.88)		(4,334	)⁽ⁱ⁾
2,500 Bbls/d	January through June 2005	US$28.40 – 32.25 ($21.80)		(8,150	)⁽ⁱ⁾
1,500 Bbls/d	July through December 2005	US$28.17 – 32.10 ($22.33)		(3,877	)⁽ⁱ⁾
2,000 Bbls/d	January through December 2005	US$28.00 – 42.00		—

Note 1 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.

Commodity option contracts based on West Texas Intermediate

Daily Quantity	Term	Price per Barrel	Mark to Market Gain (Loss)
1,250 Bbls/d	October through December 2004 – long put	US$24.00	$	(415	)⁽ⁱ⁾
11,000 Bbls/d	January through December 2005 – long put	US$33.18		3,135	⁽ⁱ⁾
4,352 Bbls/d	January through December 2005 – short call	US$32.73		(24,172	)⁽ⁱ⁾
4,352 Bbls/d	January through December 2005 – long call	US$42.73		9,711	⁽ⁱ⁾
7,500 Bbls/d	January through June 2006 – long put	US$34.00		1,801	⁽ⁱ⁾
3,750 Bbls/d	January through June 2006 – short call	US$34.00		(6,591	)⁽ⁱ⁾
3,750 Bbls/d	January through June 2006 – long call	US$44.00		3,496	⁽ⁱ⁾

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The following is a summary of electricity price hedging physical and financial swap contracts entered into by Harvest Operations Corp. to fix the cost of future electricity usage as at September 30, 2004:

Commodity swap contracts based on electricity prices

Quantity	Term	Price per Megawatt	Mark to Market Gain
15MW	October through December 2004	Cdn$45.83	$	350
5MW	January through December 2005	Cdn$43.00		453
9.75MW	October 2004 through March 2006	Cdn$44.50		1,393
10MW	January through December 2005	Cdn$52.20		101
10MW	January through December 2006	Cdn$48.50		22
10MW	January through December 2006	Cdn$48.00		66
10MW	April through December 2006	Cdn$46.50		32

Commodity swap contracts based on electricity heat rate

Swaps		Term		Price		Mark to Market Gain
5MW		January through December 2005		8.40 GJ/MWh		$	111

Foreign Currency Contracts

Monthly Contract Amount		Term		Contract Rate		Mark to Market Gain
US$3 million		October through December 2004		1.3333 Cdn/US		$	679

At September 30, 2004 the net mark-to-market unrealized loss for all the financial derivative contracts entered into by Harvest Operations Corp. was approximately $47.1 million. Harvest Operations Corp. has provided deposits to some counterparties for a portion of its financial derivative contracts, based on the mark-to-market value of those contracts at the end of the trading day. As at September 30, 2004, the amounts deposited totaled $15.3 million and are recorded in the prepaid expense and deposits balance.

Upon the implementation of the CICA Accounting Guideline 13, the Trust recorded a liability and a corresponding unrealized mark to market loss of $5.5 million. As at September 30, 2004, the mark to market loss is $29.4 million. The realized losses on all derivative contracts are included in the period in which they are incurred. All contracts not being accounted for as hedges are marked with an (i).

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The following is a summary of the oil sales contracts with price swap or collar features as at December 31, 2003, that have fixed future sales prices:

Commodity collar contracts based on West Texas Intermediate

Daily Quantity	Term	Price per Barrel (Note 1)	Mark to Market Gain (Loss) Cdn$
2,500 Bbls/d	January through December 2004	US$22.00 – 28.10	$	(2,457	)
1,000 Bbls/d	January through December 2004	US$23.00 – 27.95 ($18.00)	$	(1,096	)
1,000 Bbls/d	January through December 2004	US$25.00 – 28.25 ($18.00)	$	(954	)
500 Bbls/d	January through December 2004	US$27.50 – 31.00 ($20.25)	$	155
500 Bbls/d	January through December 2004	US$27.65 – 33.00 ($21.00)	$	(47	)

Note 1 Harvest has sold a put option at the price denoted in parenthesis, for the same volumes as the associated commodity contract. The counterparty may exercise this option if the respective index falls below the specified price on a monthly settlement basis.

Commodity swap contracts based on West Texas Intermediate

Daily Quantity	Term	Price per Barrel (Note 1)	Mark to Market Gain (Loss) Cdn$
1,510 Bbls/d	January through March 2004	US$23.23	$	(1,554	)
1,300 Bbls/d	January through March 2004	US$24.33	$	(1,171	)
500 Bbls/d	January through December 2004	US$24.12 ($15.50)	$	(1,442	)
500 Bbls/d	January through December 2004	US$24.25	$	(1,399	)
500 Bbls/d	January through December 2004	US$29.32	$	(204	)
1,430 Bbls/d	April through June 2004	US$22.93	$	(1,297	)
1,200 Bbls/d	April through June 2004	US$25.50	$	(2,912	)
1,380 Bbls/d	July through September 2004	US$22.70	$	(1,098	)
500 Bbls/d	July through September 2004	US$24.56	$	(287	)
1,325 Bbls/d	October through December 2004	US$22.54	$	(958	)
500 Bbls/d	October through December 2004	US$24.03	$	(273	)
500 Bbls/d	January through December 2004	US$30.50	$	75
500 Bbls/d	January through December 2005	US$24.00	$	(811	)
1,100 Bbls/d	January through March 2005	US$22.38	$	(714	)
1,030 Bbls/d	April through June 2005	US$22.18	$	(652	)

Commodity swap contracts based on the Lloydminster Blend Crude differential

Daily Quantity	Term	Price per Barrel (Note 1)	Mark to Market Gain (Loss) Cdn$
2,000 Bbls/d	January through December 2004	US($7.75)	$	1,368
1,000 Bbls/d	January through December 2004	US($8.20)	$	472
500 Bbls/d	January through December 2004	US($7.90)	$	307

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The following is a summary of electricity price hedging swap contracts entered into by Harvest Operations to fix the cost of future electricity usage as at December 31, 2003:

Commodity swap contracts based on electricity prices

Quantity	Term	Price per Megawatt	Mark to Market Gain (Loss)
5MW	January through December 2004	Cdn$46.00	$	384
5MW	January through December 2004	Cdn$46.00	$	384
5MW	January through December 2004	Cdn$45.50	$	406
5MW	January through December 2005	Cdn$43.00	$	153
9.75MW	January 2004 through March 2006	Cdn$44.50	$	1,373

Commodity swap contracts based on electricity heat rate

Quantity		Term		Price per Megawatt		Mark to Market Gain (Loss)
5MW		January through December 2005		8.40 GJ/MWh		$	46

Foreign Currency Contracts

Monthly Contract Amount		Term		Contract Rate		Mark to Market Gain (Loss) Cdn$
US$3 million		January through December 2004		1.3333 Cdn/US		$	1,735

At December 31, 2003 the net mark-to-market unrealized loss for all the financial derivative contracts entered into by Harvest Operations was approximately $12.4 million. Harvest Operations has provided a deposit to the counterparties with some of its financial derivative contracts, based on the mark-to-market value of those contracts at the end of the trading day. As at December 31, 2003, this amount totaled $11.9 million and is recorded in the prepaid expense and deposits balance.

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16. CHANGE IN NON-CASH WORKING CAPITAL

		Nine month period ended September 30,
											Period from July 10 (date of formation) to December 31, 2002
								Year ended December 31, 2003
		2004			2003			Year ended December 31, 2003
Changes in non-cash working capital items:
	Accounts receivable	$	(36,856	)	$	(82	)	$	(5,590	)	$	(13,578	)
	Prepaid expenses and deposits		(3,141	)		(6,195	)		(11,597	)		(534	)
	Accounts payable and accrued liabilities		47,658			9,282			12,054			6,029
	Cash distributions payable		3,949			642			1,559			—

		$	11,610		$	3,647		$	(3,574	)	$	(8,083	)

Changes relating to operating activities		$	(12,405	)	$	6,449		$	(12,286	)	$	(6,974	)
Changes relating to financing activities			5,841			642			2,224			781
Changes relating to investing activities			10,249			(3,444	)		330			(1,890	)
Add: Non cash changes			7,925			—			6,158			—

		$	11,610		$	3,647		$	(3,574	)	$	(8,083	)

17. RELATED PARTY TRANSACTIONS

A director and a corporation controlled by a director of Harvest Operations advanced $33.5 million and were repaid $8.5 million under the equity bridge note during the year ended December 31, 2003. The director and corporation issued $30 million and were repaid $45 million under the equity bridge note during the nine month period ended September 30, 2004. The Trust paid $1,521,407 and $205,205 during the nine months ended September 30, 2004 and the year ended December 31, 2003, respectively, of the total interest accrued and payable. (Note 9)

A corporation controlled by a director of Harvest Operations exercised warrants to purchase 150,000 trust units for proceeds of $150,000 on January 24, 2003. (Note 10)

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

18. SUBSEQUENT EVENTS

(a): On October 14, 2004, Harvest Operations Corp. closed an agreement to sell, on a private placement basis in the United States, US$250 million of senior notes due October 15, 2011. The senior notes are unsecured and unsubordinated and bear interest at an annual rate of 7⁷/8% and were sold at a price of 99.3392% of their principal amount. The senior notes are unconditionally guaranteed by the Trust and all of its wholly-owed 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 revolving credit facility. Harvest's syndicate of lenders has reduced the amount of the production loan which may be drawn to $310 million, from $355 million, as a result of the issuance of the senior notes.
(b): Subsequent to September 30, 2004, 12,436 and 53,915 convertible debentures were converted at the option of the holders, into 888,282 and 3,317,840 trust units and $0.4 million and $0.8 million in

F-29

accrued interest and fractional units for the 9% and 8% series respectively, leaving $29.8 million face value of convertible debentures outstanding as at November 5, 2004.

Subsequent to September 30, 2004, 5,697 exchangeable shares were converted into 5,965 trust units, leaving 547,275 exchangeable shares outstanding as at November 5, 2004.

Subsequent to September 30, 2004, 158,500 trust unit appreciation rights were exercised, for proceeds of $2,978,788.

The following is a summary of the Trust distributions announced and paid subsequent to September 30, 2004:

Distribution Month		Record Date		Payment Date		Trust units issued under DRIP		Total Amount of Distribution
September		September 30, 2004		October 15, 2004		93,160		$	7,375
October		October 31, 2004		November 15, 2004					8,163

19. COMMITMENTS AND CONTINGENCIES

From time to time, the Trust is involved in litigation or has claims sought 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.

The Trust has letters of credit outstanding in the amount of approximately $5 million, related to electricity infrastructure usage. These letters are provided by the Trust's lenders under the availability of the demand loan. The letters expire throughout 2004 and 2005, and are expected to be renewed as required.

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 generally accepted accounting principles ("Canadian GAAP") which, in most respects, conforms to generally accepted accounting principles in the United States ("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.

F-30

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

		Nine months ended September 30,
											Period from July 10 (date of formation) to December 31, 2002
								Year ended December 31, 2003
		2004			2003			Year ended December 31, 2003
Net income as reported		$	5,696		$	9,813		$	15,516		$	4,832
Adjustments
	Depletion, depreciation and accretion^{(a and b)}		—			—			—			511
	Future income tax effect on depletion, depreciation and accretion^{(a and b)}		—			—			—			(208	)
	Unrealized loss on derivative financial instruments^(f)		(5,220	)		(8,776	)		(9,345	)		(3,123	)
	Future income tax effect on unrealized loss on derivative financial instruments^(f)		1,697			2,852			3,952			1,299
	Interest on convertible debentures^(d)		(4,958	)		—			—			—
	Interest on equity bridge notes^(d)		(658	)		(205	)		(870	)		—
	Non-cash general and administrative expenses^(c)		(1,148	)		(1,145	)		(1,288	)		(167	)

	Net income (loss) under U.S. GAAP before cumulative effect of change in accounting policy		(4,591	)		2,539			7,965			3,144

	Cumulative effect of change in accounting policy^(b)		—			(304	)		(303	)		—

	Net income (loss) under U.S. GAAP after cumulative effect of change in accounting policy		(4,591	)		2,235			7,662			3,144

Change in redemption value of trust units under U.S. GAAP^(e)			(246,621	)		28,347			(48,362	)		(47,923	)

Net income (loss) available to unitholders under U.S. GAAP^(e)		$	(251,212	)	$	30,582		$	(40,700	)	$	(44,779	)

F-31

Basic earnings per unit:
	Net income (loss) under U.S. GAAP before cumulative effect of change in accounting policy	$	(0.22	)	$	0.22		$	0.63		$	2.25
	Cumulative effect of change in accounting policy^(b)		—			(0.02	)		(0.02	)		—

	Net income (loss) after the cumulative effect of change in accounting policy (before changes in redemption value of trust units)		(0.22	)		0.20			0.61			2.25

	Net income (loss) available to unitholders per trust unit under U.S. GAAP	$	(11.88	)	$	2.69		$	(3.23	)	$	(32.17	)

Diluted earnings per unit:
	Net income (loss) under U.S. GAAP before cumulative effect of change in accounting policy	$	(0.22	)	$	0.22		$	0.61		$	2.13

	Cumulative effect of change in accounting policy^(b)		—			(0.03	)		(0.02	)		—

	Net income (loss) after the cumulative effect of change in accounting policy (before changes in redemption value of trust units)		(0.22	)		0.19			0.59			2.13

	Net income (loss) available to unitholders per trust unit under U.S. GAAP	$	(11.88	)	$	2.60		$	(3.23	)	$	(32.17	)

F-32

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

		September 30, 2004					December 31, 2003					December 31, 2002
		Canadian GAAP		U.S. GAAP			Canadian GAAP		U.S. GAAP			Canadian GAAP		U.S. GAAP
Assets
	Deferred financing charges, net of amortization	$	4,116	$	8,429		$	1,989	$	1,989		$	2,210	$	2,210
	Property, plant and equipment^(a)(b)		965,028		965,028			210,543		210,543			86,142		71,631
	Future taxes^(a)(b)(f)(g)		—		—			12,609		17,860			1,480		2,571
Liabilities
	Commodity derivative contracts^(f)		29,396		47,084			—		12,468			—		3,123
	Future taxes^(a)(b)(f)(g)		19,129		12,181			—		—			—
	Equity bridge notes^(d)		—		10,000			—		25,000			—		—
	Convertible debentures^(d)		—		96,134			—		—			—		—
	Asset retirement obligation^(b)		96,200		96,200			42,009		42,009			15,566		—
	Site restoration and reclamation^(b)		—		—			—		—			—		544
	Unitholders' capital liability^(e)		—		743,429			—		213,692			—		84,651
Unitholders' Equity															—
	Unitholders' capital^(e)		392,356		—			117,407		—			36,728		—
	Equity bridge notes^(d)		10,000		—			25,000		—			—		—
	Convertible debentures^(d)		91,821		—			—		—			—		—
	Exchangeable shares^(e)		8,167		—			—		—			—		—
	Contributed surplus^(c)		1,008		3,611			239		1,694			5		172
	Accumulated income	$	19,558	$	(336,691	)	$	19,478	$	(85,479	)	$	4,832	$	(44,779	)

(a): 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. For periods prior to January 1, 2004, the Trust used undiscounted future net revenue from proved oil and natural gas reserves plus the cost of unproved properties less impairment, using period end prices. Under U.S. GAAP, entities using the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using future net revenue from proved oil and natural gas reserves discounted at ten percent. The prices used under the U.S. GAAP ceiling tests are those in effect at period end. There was no adjustment required under application of U.S. GAAP.
(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 ("FAS") 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): For Canadian GAAP purposes, the Trust recognizes compensation expense related to trust unit rights using the fair value method for rights granted on or after January 1, 2003. For U.S. GAAP purposes, the Trust is required to account for all rights granted since inception using the fair value method of accounting. An adjustment to earnings and contributed surplus has been recorded to reflect the associated additional compensation expense.

F-33

(d)

Under Canadian GAAP, the equity bridge notes and convertible debentures are classified as unitholders' equity and the interest accrued and paid on the equity bridge notes and convertible debentures has been recorded as a reduction of accumulated income. Under U.S. GAAP, the equity bridge notes and convertible debentures are classified as long-term debt. Accordingly, an adjustment has been recorded to income to reflect interest expense on both instruments.

(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' Capital would be reduced by an amount equal to the redemption value of the trust units as at the balance sheet date. The redemption value of the trust units 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 Unitholders' Capital Liability. Increases or decreases, if any, in the redemption value during a period would result in an adjustment to income available to unitholders for the period. Similarly, exchangeable shares, which are convertible into trust units, have been reclassified to Unitholders' Capital Liability on the balance sheet.

(f)

The fair market value for derivative instruments used for hedging activities are not recorded within the financial statements under Canadian GAAP for the period ended September 30, 2004 and 2003, the year ended December 31, 2003 or the period ended December 31, 2002, respectively. The mark to market fair value amounts are disclosed within the notes to the consolidated financial statements.

Under U.S. GAAP, FAS 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 hedge accounting treatment. The Trust had not formally documented and designated all hedging relationships for U.S. GAAP purposes as at September 30, 2004, December 31, 2003 or December 31, 2002, and as such was not eligible for hedge accounting treatment under U.S. GAAP.

(g)

The Canadian GAAP liability method of accounting for income taxes is similar to the U.S. GAAP FAS 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 taxes, whereas Canadian GAAP uses substantively enacted rates. There are no differences in the income tax provisions between Canada and U.S. GAAP for the periods ended September 30, 2004 and 2003, December 31, 2003 and 2002 except those arising from the impact of other U.S. GAAP differences reflected therein.

(h)

The consolidated statements of cash flow 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 operating cash flow before changes in non-cash working capital items in the consolidated statement of cash flow. This total cannot be presented under U.S. GAAP.

(i)

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 2003, FASB issued FAS 150, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." FAS 150 establishes standards for the measurement and classification of certain financial instruments with characteristics of both liabilities and equity. FAS 150 is applicable to financial instruments entered into or modified after May 31, 2003, and otherwise effective at the beginning of the first interim period beginning after May 31, 2003. The Trust has reflected this new standard in the December 31, 2003 U.S. GAAP reconciliation by reclassifying interest expense on the equity bridge notes and convertible debentures from accumulated income to interest expense.

In 2003, FASB issued Interpretation Number 46R, "Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51." The standard mandates that variable interest entities be consolidated by their primary beneficiary. In Canada, the corresponding Canadian Institute of Chartered Accountants ("CICA") Handbook Accounting Guideline 15, "Consolidation of Variable Interest Entities" will be effective for periods beginning after November 1, 2004 to harmonize it with FAS Interpretation Number 46R. At December 31, 2002 and 2003 and June 30, 2004 the Trust did not have any variable interests in special purpose entities.

F-34

Additional disclosures required under U.S. GAAP

		September 30, 2004		December 31, 2003		December 31, 2002
Components of accounts receivable
	Trade	$	51,886	$	16,334	$	13,538
	Other		4,188		2,834		40

		$	56,024	$	19,168	$	13,578

Components of prepaid expenses and deposits
	Prepaid expenses	$	1,906	$	232	$	534
	Funds on deposit		13,366		11,899		—

		$	15,272	$	12,131	$	534

Components of accounts payable and accrued liabilities
	Accounts payable	$	21,861	$	5,239	$	4,435
	Accrued liabilities		43,880		12,844		1,594

		$	65,741	$	18,083	$	6,029

The following information is unaudited and reflects pro forma amounts arising from the Storm, EnCana and other acquisitions carried out in the respective periods:

Pro forma oil and natural gas sales	$	426,058	$	517,568
Pro forma net income		40,902		101,204
Pro forma net income per unit		1.04		2.80

On July 10, 2002, the Trust acquired oil and natural gas producing properties from a major producer for $26.1 million. The purchase price was funded by an advance under Harvest Operations Corp.'s credit facilities and, indirectly, through an interim loan provided by a corporation controlled by a director of Harvest Operations Corp. On August 1, 2002, the Trust entered into an agreement with a major oil and natural gas producer to purchase oil and natural gas properties for $71.8 million. This acquisition was completed on November 15, 2002. The purchase price was funded by an advance under Harvest Operations Corp.'s credit facilities and, indirectly, through an interim loan provided by a corporation controlled by a director of Harvest Operations Corp.

F-35

COMPILATION REPORT

To the Trustee of Harvest Energy Trust and the Directors of Harvest Operations Corp.

We have read the accompanying unaudited pro forma consolidated statements of income of Harvest Energy Trust (the "Trust") for the nine month period ended September 30, 2004 and for the year ended December 31, 2003, and have performed the following procedures:

1.

Compared the figures in the columns captioned "Harvest Energy Trust" to the consolidated statement of income of the Trust for the nine month period ended September 30, 2004, and the consolidated statement of income for the year ended December 31, 2003 and found them to be in agreement.

2.

Compared the figures in the columns captioned "Storm Energy Ltd." to a schedule that combines the unaudited consolidated statement of income of Storm Energy Ltd. for the three month period ended March 31, 2004 and the unaudited results of operations for the three month period ended June 30, 2004, and to the consolidated statement of income for the year ended December 31, 2003 and found them to be in agreement.

3.

Compared the figures in the columns captioned "EnCana Properties" to a schedule that combines the unaudited Schedule of Revenues, Royalties and Operating Expenses of the properties for the six month period ended June 30, 2004, with the unaudited revenues, royalties and operating expenses of the properties for the two months ended August 31, 2004 and for the year ended December 31, 2003 and found them to be in agreement.

4.

Compared the figures in the columns captioned "Carlyle Properties" to a schedule that combines the unaudited Schedule of Revenues, Royalties and Operating Expenses of the properties for the six month period ended June 30, 2003 and the period from July 1, 2003 to October 14, 2003, and found them to be in agreement.

5.

Made enquiries of certain officials of the Trust who have responsibility for financial and accounting matters about:

(a): The basis for the determination of the pro forma adjustments; and
(b): Whether the pro forma consolidated financial statements comply in all material respects with the applicable regulatory requirements.

The officers:

(a): Described to us the basis for determination of the pro forma adjustments, and
(b): Stated that the pro forma consolidated financial statements comply as to form in all material respects with the applicable regulatory requirements.

6.: Read the notes to the pro forma consolidated financial statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.
7.: Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the other columns for the nine month period ended September 30, 2004 and the year ended December 31, 2003 and found the amounts in the column captioned "Pro forma Consolidated" to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.

Calgary, Canada		(Signed) KPMG LLP
December 23, 2004		Chartered Accountants

Comments for United States readers on differences between
Canadian and United States reporting standards

The above report, provided solely pursuant to Canadian requirements, is expressed in accordance with standards of reporting generally accepted in Canada. To report in conformity with United States standards on the reasonableness of the pro forma adjustments and their application to the pro forma financial statements requires an examination or review substantially greater in scope than the review we have conducted. Consequently, we are unable to express any opinion in accordance with standards of reporting generally accepted in the United States with respect to the compilation of the accompanying unaudited pro forma financial information.

Calgary, Canada		(Signed) KPMG LLP
December 23, 2004		Chartered Accountants

F-36

HARVEST ENERGY TRUST

PRO FORMA CONSOLIDATED STATEMENT OF INCOME

Period Ended September 30, 2004
(Thousands of dollars)
(Unaudited)

		Harvest Energy Trust			Storm Energy Ltd.			Adjustments			EnCana Properties			Adjustments			Notes	Harvest Energy Trust Subtotal			Senior Notes			Notes	Pro Forma Consolidated
Revenue
	Oil and natural gas sales	$	202,681		$	40,814		$	(5,029	)	$	187,592			—		2a, 2b	$	426,058		$	—			$	426,058
	Royalty expense, net		(33,031	)		(8,902	)		1,095			(23,195	)		—		2a, 2b		(64,033	)		—				(64,033	)
	Other		—			198			—			—			—				198			—				198
	Alberta royalty tax credit		—			328			—			—			—				328			—				328
	Hedging loss		(37,761	)		(4,685	)		—			—			—				(42,446	)		—				(42,446	)
	Mark to market loss on commodity derivative contracts		(29,396	)		—			—			—			—				(29,396	)		—				(29,396	)

			102,493			27,753			(3,934	)		164,397			—				290,709			—				290,709
Expenses
	Operating		46,267			4,711			(1,024	)		33,830			—		2a, 2b		83,784			—				83,784
	General and administrative		6,049			1,839			(1,075	)		—			1,200		2f		8,013			—				8,013
	Interest		3,919			1,113			2,457			—			10,193		2d		17,682			5,081		2d		22,763
	Amortization of deferred finance charges		1,845			—			500			—			3,000		2d		5,345			1,242		2d		6,587
	Depletion, depreciation and accretion		53,002			9,153			6,734			—			73,317		2e		142,206			—				142,206
	Foreign exchange gain		(565	)		—			—			—			—				(565	)		—				(565	)

			110,517			16,816			7,592			33,830			87,710				256,465			6,323				262,788

Income (loss) before taxes			(8,024	)		10,937			(11,526	)		130,567			(87,710	)			34,244			(6,323	)			27,921
Taxes
	Current taxes		—			841			—			—			—				841			—				841
	Large corporation tax		256			117			—			—			—				373			—				373
	Future tax expense (recovery)		(13,976	)		2,293			(2,512	)		—			—		2g		(14,195	)		—				(14,195	)

			(13,720	)		3,251			(2,512	)		—			—				(12,981	)		—				(12,981	)

Net income (loss)		$	5,696		$	7,686		$	(9,014	)	$	130,567		$	(87,710	)		$	47,225		$	(6,323	)		$	40,902

Net income per trust unit
	Basic	$	0.00																					2h	$	1.04
	Diluted	$	0.00																					2h	$	1.01

F-37

HARVEST ENERGY TRUST

PRO FORMA CONSOLIDATED STATEMENT OF INCOME

Year ended December 31, 2003
(Thousands of dollars)
(Unaudited)

		Harvest Energy Trust			Carlyle Properties			Adjustments			Storm Energy Ltd.			Adjustments			EnCana Properties			Adjustments			Notes	Harvest Energy Trust Subtotal			Senior Notes			Notes	Pro Forma Consolidated
Revenue
	Oil and natural gas sales	$	119,351		$	59,839		$	—		$	59,547		$	(1,811	)	$	280,642		$	—		2a, 2b, 2c	$	517,568		$	—			$	517,568
	Royalty expense, net		(16,412	)		(12,646	)		—			(13,674	)		214			(34,250	)		—		2a, 2b, 2c		(76,768	)		—				(76,768	)
	Other		—			—			—			467			—			—			—				467			—				467
	Hedging loss		(18,924	)		—			—			—			—			—			—				(18,924	)		—				(18,924	)

			84,015			47,193			—			46,340			(1,597	)		246,392			—				422,343			—				422,343
Expenses
	Operating		36,045			18,057			—			6,318			(340	)		51,422			—		2a, 2b, 2c		111,502			—				111,502
	General and administrative		4,340			—			—			2,410			(1,286	)		—			2,143		2f		7,607			—				7,607
	Interest		2,975			—			1,368			3,194			3,236			—			14,147		2d		24,920			8,143		2d		33,063
	Amortization of deferred finance charges		2,607			—			—			—			775			—			4,000		2d		7,382			1,656		2d		9,038
	Depletion, depreciation and accretion		35,727			—			5,506			15,020			14,856			—			99,034		2e		170,143			—				170,143
	Foreign exchange gain		(4,374	)		—			—			—			—			—			—				(4,374	)		—				(4,374	)

			77,320			18,057			6,874			26,942			17,241			51,422			119,324				317,180			9,799				326,979

Income (loss) before taxes			6,695			29,136			(6,874	)		19,398			(18,838	)		194,970			(119,324	)			105,163			(9,799	)			95,364
Taxes
	Large corporation tax		157			—			—			309			—			—			—				466			—				466
	Future tax expense (recovery)		(8,978	)		—			—			7,891			(5,219	)		—			—		2g		(6,306	)		—				(6,306	)

			(8,821	)		—			—			8,200			(5,219	)		—			—				(5,840	)		—				(5,840	)

Net income (loss)		$	15,516		$	29,136		$	(6,874	)	$	11,198		$	(13,619	)	$	194,970		$	(119,324	)		$	111,003		$	(9,799	)		$	101,204

Net income per trust unit
	Basic	$	1.16																											2h	$	2.80
	Diluted	$	1.13																											2h	$	2.79

F-38

HARVEST ENERGY TRUST

NOTES TO PRO FORMA CONSOLIDATED STATEMENTS OF INCOME

1. BASIS OF PRESENTATION

Harvest Energy Trust (the "Trust") is an open-ended, unincorporated investment trust formed under the laws of Alberta. Pursuant to the 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 acquired and held by Harvest Operations. The Trust acquires and holds net profit interests in oil and natural gas properties in Saskatchewan and held by Harvest Sask. Energy Trust. The Trust is the sole unitholder of Harvest Sask. Energy Trust. The EnCana properties acquired, as described below, are held in a partnership. The partnership is owned by two trusts (which have no other activities) of which the Trust is the direct or indirect sole unitholder of each. All properties under the Trust are operated by Harvest Operations.

The accompanying unaudited pro forma statements of income have been prepared by the management of Harvest Operations in accordance with Canadian generally accepted accounting principles on a basis consistent with the consolidated financial statements of the Trust. These pro forma financial statements should be read in conjunction with the historical financial statements of the Trust and of the acquired properties and companies. In the opinion of management, the pro forma consolidated statements of income include all material adjustments necessary for fair presentation in accordance with Canadian generally accepted accounting principles.

The pro forma consolidated statements of income are not necessarily indicative either of the results that actually would have occurred if the following events reflected herein had taken place on the dates indicated or of the results that may be obtained in the future.

•: On October 1, 2003 the Trust and Harvest Operations entered into an agreement to acquire properties from a third party (the "Carlyle Properties"). The cost to Harvest Operations was approximately $81.1 million including the closing adjustments and estimated transaction costs of approximately $2 million.
•: On June 30, 2004, the Trust completed a plan of arrangement with Storm Energy Ltd. ("Storm"), whereby the Trust acquired all of the outstanding shares of Storm for approximately $189 million, including assumed net debt and transaction costs of approximately $65 million. As part of the Plan of Arrangement, certain assets of Storm were transferred to a new entity ("ExploreCo") which is owned by former Storm shareholders.
•: On September 2, 2004, the Trust completed the acquisition of oil and natural gas properties from EnCana Corporation ("EnCana") (the "EnCana Properties"). The cost to the Trust and Harvest Operations is approximately $513 million net of adjustments and costs.
•: On October 14, 2004, Harvest Operations Corp. closed an agreement to sell, on a private placement basis in the United States, US$250 million of senior notes due October 15, 2011. The senior notes are unsecured and unsubordinated and bear interest at an annual rate of 7⁷/8% and were sold at a price of 99.3392% of their principal amount. The senior notes are unconditionally guaranteed by the Trust and all of its wholly-owned subsidiaries.

F-39

2. PRO FORMA ASSUMPTIONS AND ADJUSTMENTS

The pro forma statements of income for the nine month period ended September 30, 2004 and for the year ended December 31, 2003 have been prepared assuming that the transactions described in notes 2(a), 2(b) and 2(c) were completed at the beginning of the respective periods as follows:

(a) Acquisition of EnCana Properties

The amounts included in the pro forma consolidated statement of income for the revenue, royalties and expenses for the EnCana Properties for the eight month period ended August 31, 2004 and the year ended December 31, 2003 have been derived from the unaudited schedule of revenues, royalties and expenses for the EnCana Properties for the six month period ended June 30, 2004 and the unaudited financial information of the revenues, royalties and expenses of the EnCana Properties for the two month period ended August 31, 2004. The amounts included in the pro forma consolidated statement of income for the revenue, royalties and expenses for the year ended December 31, 2003 have been derived from the audited schedule of revenues, royalties and expenses of the EnCana Properties for the year ended December 31, 2003. Consideration for the EnCana Properties is $513 million, consisting of the purchase price of $526 million net of interim adjustments and acquisition costs estimated to be $13 million. The following is a table reconciling the amounts within the pro forma income statement to the New Properties Schedule of Revenues, Royalties and Expenses statement in the prospectus:

	Six months ended June 30, 2004		Two months ended August 31, 2004		EnCana Properties Pro forma
Revenues	$	135,246	$	52,346	$	187,592
Royalties		16,800		6,395		23,195

		118,446		45,951		164,397
Expenses		24,652		9,178		33,830

Excess of revenues over expenses	$	93,794	$	36,773	$	130,567

In accordance with the financing requirements for the purchase of the EnCana Properties, it has been assumed for these pro forma consolidated statements of income that the following transactions have occurred:

(i): Issue of Subscription Receipts

On July 15, 2004, the Trust entered into an underwriting agreement for the issue of 12,166,666 subscription receipts at a price of $14.40 each, which entitled the holder to receive one trust unit per subscription receipt for approximate gross proceeds of $175.2 million. The net proceeds are $165.9 million after the deduction of the underwriters' commission at 5% and estimated costs of $0.5 million.

(ii): Issue of Convertible Unsecured Subordinated Debentures

On July 15, 2004, the Trust entered into an underwriting agreement for the issue of 100,000 convertible unsecured subordinated debentures ("debentures") at a price of $1,000 each, for gross proceeds of $100 million. The net proceeds are $95.5 million after the deduction of the underwriters' commission at 4% and estimated costs of $0.5 million. The debentures have a maturity date of September 30, 2009. The debentures bear interest at an annual rate of 8% payable semi-annually on March 31 and September 30 in each year commencing on March 31,

F-40

2005. The debentures are redeemable by the Trust at a price of $1,050 per debenture after September 30, 2007, and on or before September 30, 2008, and at a price of $1,025 per debenture after September 30, 2008 and before maturity on September 30, 2009, in each case, plus accrued and unpaid interest thereon, if any.

(iii): Bank Borrowings

The cost of the EnCana Properties, less the net proceeds from the issuance of subscription receipts and debentures, was financed through the issue of a new bank loan in the approximate amount of $181.6 million and a bridge note of approximately $70 million due within nine months of issuance. The new facilities bear interest at variable rates based on the lenders' prime rates.

(b) Plan of arrangement with Storm

The amounts included in the pro forma consolidated statement of income for Storm for the nine month period ended September 30, 2004 and the year ended December 31, 2003 are derived from Storm's unaudited and audited financial statements, respectively. Historical results from the Storm assets for the period from July 1 to September 30, 2004 are included in the Trust's statement of income for the nine month period ended September 30, 2004. In accordance with the terms of the plan of arrangement concluded June 30, 2004, the consideration paid consisted of 2,720,837 trust units and 600,587 exchangeable shares at an ascribed value of $14.77 per trust unit and exchangeable share, and cash of $75 million for an aggregate consideration of approximately $189 million (including assumed debt and transaction costs totalling approximately $65 million). The exchangeable shares are exchangeable by the holder at any time into trust units.

The amounts included in the pro forma consolidated statement of income for the revenue, royalties and operating costs for the Carlyle Properties for the year ended December 31, 2003 have been derived from the unaudited schedule of revenue and expenses for the Carlyle Properties for the period from January 1, 2003 to June 30, 2003 and from the unaudited financial information for the Carlyle Properties for the period from July 1, 2003 to October 14, 2003. Operations from October 15, 2003 to December 31, 2003 have been included in the Trust's statement of income for the year ended December 31, 2003. The following is a table reconciling the amounts within the pro forma income statement to the Carlyle Properties Schedule of Revenue, Royalties and Operating Expenses statement incorporated by reference in the prospectus:

	Six months ended June 30, 2003		Period from July 1 to October 14, 2003		Carlyle Properties Pro forma
Revenue	$	40,371	$	19,468	$	59,839
Royalties		8,443		4,203		12,646

		31,928		15,265		47,193
Operating expenses		12,695		5,362		18,057

Excess of revenue over operating expenses	$	19,233	$	9,903	$	29,136

(d) Interest and amortization of deferred financing charges

Interest has been adjusted to include the costs associated with the new bank loan borrowings upon acquisition of Storm and the new bank loan and bridge loan borrowings upon acquisition of the

F-41

EnCana Properties, respectively. The balance also includes the interest on the senior notes as if the senior notes had been issued at the beginning of the respective period, offset with interest on bank loan and bridge loan amounts repaid with net proceeds from the senior note issuance. Deferred finance costs associated with the debt issuances have been amortized over their respective periods to maturity.

As the Trust has the ability to settle the interest and principal amounts outstanding under the Equity Bridge Agreement and the debentures through the issue of trust units, the corresponding pro forma interest amounts will be presented as a direct charge to accumulated income rather than as a deduction in determining income for the applicable periods.

(e) Depletion, depreciation and accretion

The September 30, 2004 pro forma adjustments for depletion, depreciation and accretion have been determined using the full cost method of accounting based on combined proved reserves, future development costs and production volumes and incorporation of the cost of the properties acquired pursuant to the Storm plan of arrangement and the purchase of the EnCana Properties (including associated estimated future development costs of $11.6 million and $57.8 million, respectively).

The December 31, 2003 pro forma adjustments for depletion, depreciation and accretion have been determined using the full cost method of accounting based on combined proved reserves, future development costs and production volumes and incorporation of the costs of acquiring the Carlyle Properties (including estimated future development costs of $10 million), and the cost of the properties acquired pursuant to the Storm plan of arrangement and the purchase of the EnCana Properties discussed above.

(f) General and administrative expense

General and administrative expense has been adjusted to reflect the estimated costs of the associated combined entity under the plan of arrangement with Storm and the purchase of the EnCana Properties, respectively.

(g) Taxes

For income tax purposes, the Trust is able to, and intends to, claim a deduction for all amounts paid or payable to unitholders, and then to allocate the remaining income, if any, to the unitholders. However, the pro forma adjustment for future income taxes has been based on the assumption that 50% of the incremental cash flow related to the Storm assets would have been paid by Storm to the Trust as a royalty payment. Future tax expense is calculated based on the adjustments at an average rate of 40%. Under the purchase of the EnCana Properties, the EnCana Properties are held by trusts and as such, there will be no calculation for future or corporate taxes.

(h) Income per trust unit

The number of trust units included in the basic weighted average number outstanding for the nine month period ended September 30, 2004 was based on the weighted average number of trust units actually outstanding for the period, plus a pro-ration of the trust units and exchangeable shares issued under the terms of the Storm plan of arrangement of 1,813,891 and 347,888 respectively, plus a pro-ration of the trust units issued in the purchase of the EnCana Properties of 9,462,962. The number also includes the number of trust units issued upon conversion of the subordinated convertible debentures up to and including November 15, 2004. This balance was included on the assumption that these trust units were outstanding on January 1, 2004. The pro forma income available to unitholders

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was reduced by the interest applicable to the outstanding debentures and equity bridge notes net of amounts related to convertible debentures assumed to have converted to trust units on January 1, 2004.

The diluted weighted average number of trust units for the nine month period ended September 30, 2004 was 38,089,484 which includes trust unit appreciation rights issued to new employees of Harvest associated with the Storm plan of arrangement and the EnCana Properties acquisition. The pro forma income available to unitholders was reduced by the interest applicable to the debentures and equity bridge notes as if they were outstanding as at January 1, 2004.

The number of trust units included in the basic weighted average number outstanding for the year ended December 31, 2003 was based on the weighted average number of trust units actually outstanding for the period, plus the 2,720,837 trust units and 600,587 exchangeable shares issued under the terms of the Storm plan of arrangement, plus the estimated 12,166,666 trust units issued in the purchase of the EnCana assets, and the 4,312,500 trust units issued under the terms of the underwriting agreement dated October 7, 2003. The pro forma income available to unitholders was reduced by the interest applicable to the debentures and equity bridge notes as if they were outstanding as at January 1, 2003.

The diluted weighted average number of trust units for the year ended December 31, 2003 was 32,508,846 which included an estimated portion of trust unit appreciation rights issued to the new employees of Harvest associated with the Storm plan of arrangement and the EnCana Properties acquisition, and with respect to the settlement of the amounts drawn under the Equity Bridge Agreement and the convertible debentures. The pro forma income available to unitholders was reduced by the interest applicable to the convertible debentures and equity bridge notes as if they were outstanding as at January 1, 2003.

3. UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

These unaudited consolidated pro forma statements of income have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") which, in most respects, conforms to generally accepted accounting principles in the United States ("U.S. GAAP"). Any differences in accounting principles as they have been applied to the accompanying consolidated pro forma statements of income are not material except as described below.

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

			September 30, 2004			December 31, 2003
Pro forma consolidated net income as reported			$	40,902		$	101,204
Adjustments
	Loss on derivative financial instruments^(f)			(5,220	)		(9,345	)
		Future income tax effect thereon^(f)		1,697			3,952
	Loss on derivative financial instruments — Storm^(f)			—			(3,728	)
		Future income tax effect thereon^(f)		—			1,570
	Interest on convertible debentures^(d)			(1,863	)		(2,484	)
	Interest on equity bridge notes^(d)			(750	)		(1,000	)
	Non-cash general and administrative expenses^(c)			(1,148	)		(1,288	)

	Net income under U.S. GAAP before cumulative effect of change in accounting policy			33,618			88,881
	Cumulative effect of change in accounting policy^(b)			—			(303	)

	Net income under U.S. GAAP after cumulative effect of change in accounting policy			33,618			88,578
	Increase in redemption value of trust units^(e)			(246,621	)		(48,362	)

	Net income (loss) available to unitholders — U.S. GAAP		$	(213,003	)	$	40,216

Basic earnings per unit:
	Net income under U.S. GAAP
		Before effect of change in accounting policy	$	1.11		$	2.74
		Cumulative effect of change in accounting policy^(b)		—			(0.01	)

		After the cumulative effect of change in accounting policy (before changes in redemption value of trust units)		1.11			2.73

		Available to unitholders under U.S. GAAP^(e)	$	(5.56	)	$	1.24

Diluted earnings per unit:
	Net income under U.S. GAAP
		Before effect of change in accounting policy	$	1.07		$	2.73
		Cumulative effect of change in accounting policy^(b)		—			(0.01	)

		After the cumulative effect of change in accounting policy (before changes in redemption value of trust units)		1.07			2.72

		Available to unitholders under U.S. GAAP^(e)	$	(5.56	)	$	1.24

(a): 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. For periods prior to January 1, 2004, the Trust used undiscounted future net revenue from proved oil and natural gas reserves plus the cost of unproved properties less impairment, using period end prices. Under U.S. GAAP, entities using the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using discounted future net revenue from proved oil and natural gas reserves discounted at ten percent. The prices used under the U.S. GAAP ceiling tests are those in effect at year end. As there was no writedown required under U.S. GAAP, the amounts recorded for depletion and depreciation have not been adjusted in the periods pursuant to U.S. GAAP to reflect an impact in the reduction of depletable costs.

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(b): Effective January 1, 2004, the Trust retroactively adopted the CICA Handbook standard for accounting for asset retirement obligation. This section is equivalent to Statement of Financial Accounting Standards ("FAS") 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): For Canadian GAAP purposes, the Trust recognizes compensation expense using the fair value method for rights granted on or after January 1, 2003. For US GAAP purposes, the Trust has accounted for all rights granted since inception using the fair value method of accounting. An adjustment to earnings has been recorded to reflect the associated additional compensation expense.
(d): Under Canadian GAAP, the equity bridge notes and convertible debentures are classified as unitholders' equity and the interest accrued and paid on the equity bridge notes and convertible debentures has been recorded as a reduction of accumulated income. Under U.S. GAAP, the equity bridge notes and convertible debentures are classified as long-term debt. Accordingly, an adjustment has been recorded to income to record interest expense on both instruments.
(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 redemption value of the trust units 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 or decreases, if any, in the redemption value during a period result in an adjustment to permanent equity and are reflected in earnings available to unitholders for the period.
(f): The fair market value for derivative instruments used for hedging activities are not recorded within the financial statements under Canadian GAAP for the period ended September 30, 2004 or the year ended December 31, 2003, respectively. The mark to market fair value amounts are disclosed within the notes to the consolidated financial statements.

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. If the derivative is designated a fair value hedge, the changes in the fair value of the derivative and the hedged item attributable to the hedged risk are recognized in income. If the derivative is designated a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income and are recognized in income when the hedge item is realized. Ineffective portions of change in fair value are recognized in income immediately. For any derivatives designated as a cash flow hedge, U.S. GAAP requires that a company formally document, designate, and assess the effectiveness of derivative instruments that receive this accounting treatment. The Trust had not formally documented and designated all hedging relationships for US GAAP purposes and as such was not eligible for hedge accounting treatment under U.S. GAAP.

F-45

STORM ENERGY LTD.

CONSOLIDATED BALANCE SHEET

(Unaudited)

	March 31, 2004		December 31, 2003
			(Restated — Note 2)
ASSETS
Current
Cash	$	2,952,638	$	3,034,282
Accounts receivable		15,367,367		21,516,419
Prepaid expenses		768,645		999,922

		19,088,650		25,550,623
Investment (Note 8)		2,810,140		2,810,140
Property and equipment (Notes 2(a) & 3)		138,335,482		132,604,893

	$	160,234,272	$	160,965,656

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities	$	24,704,671	$	31,648,087
Long term debt (Note 4)		57,327,526		55,575,425
Future income taxes		15,282,982		14,574,807
Asset retirement obligation (Note 2(a))		9,002,817		8,875,379
Minority interest		1,476,319		1,517,141
Shareholders' equity
Share capital (Note 5)		32,400,432		32,389,692
Contributed surplus (Note 5)		151,422		85,019
Retained earnings (Note 2(a))		19,888,103		16,300,106

		52,439,957		48,774,817

	$	160,234,272	$	160,965,656

See accompanying notes

F-46

STORM ENERGY LTD.

CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS

(Unaudited)

	Three months ended March 31, 2004			Three months ended March 31, 2003
				(Restated — Note 2)
Revenue
Production revenue	$	17,587,765		$	14,308,624
Royalties		(4,225,530	)		(3,799,426	)
Alberta royalty tax credit		101,104			—
Other		47,458			149,260

		13,510,797			10,658,458

Expenses
Production		2,171,661			994,543
General and administrative		926,815			964,381
General and administrative cost recovery (Note 8)		—			(1,050,000	)
Interest on long term debt		663,459			411,175
Depletion, depreciation and accretion		4,564,709			2,487,289

		8,326,644			3,807,388

Income before income and other taxes		5,184,153			6,851,070
Income and other taxes
Future income tax		708,175			2,903,748
Current taxes		840,934			—
Capital taxes		47,047			29,125

		1,596,156			2,932,873

Net income for the period (Note 6)		3,587,997			3,918,197
Retained earnings, beginning of period		16,300,106			3,945,546
Retroactive restatement of change in accounting policy (Note 2(a))		—			1,156,830

Retained earnings, end of period	$	19,888,103		$	9,020,573

See accompanying notes

F-47

STORM ENERGY LTD.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

	Three months ended March 31, 2004			Three months ended March 31, 2003
				(Restated — Note 2)
Operating activities
Net income for the period	$	3,587,997		$	3,918,197
Add non-cash items:
Depletion, depreciation and accretion		4,564,709			2,487,289
Stock based compensation		66,403			8,721
Future income taxes		708,175			2,903,748

Cash flow from operations		8,927,284			9,317,955
Asset retirement obligation settled		(7,865	)		(5,041	)
Net change in non-cash working capital items (Note 7)		1,205,810			(6,862,722	)

		10,125,229			2,450,192

Financing activities
Increase in long term debt		1,752,101			9,077,130
Exercise of stock options		10,740			—
Minority interest		(40,822	)		—

		1,722,019			9,077,130

Investing activities
Property and equipment additions		(10,159,994	)		(14,421,290	)
Net change in non-cash working capital items (Note 7)		(1,768,898	)		2,893,968

		(11,928,892	)		(11,527,322	)

Change in cash during the period		(81,644	)		—
Cash, beginning of period		3,034,282			—

Cash, end of period	$	2,952,638		$	—

See accompanying notes

F-48

STORM ENERGY LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As at March 31, 2004
(Unaudited)

1. SIGNIFICANT ACCOUNTING POLICIES

Storm Energy Ltd. (the "Company") was incorporated on July 15, 2002 and commenced operations on August 23, 2002 under a Plan of Arrangement entered into by Storm Energy Inc., a Toronto Stock Exchange listed public company. Under the Plan of Arrangement, various assets and obligations of Storm Energy Inc., comprising certain producing and all undeveloped assets, were transferred to Storm Energy Ltd., along with a pro rata share of debt. Storm Energy Inc. continued as FET Resources Ltd., a wholly-owned subsidiary of Focus Energy Trust.

The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiary, Redearth Energy Inc., its 60% share of the Redearth Partnership, and its 50% interest in Storm Ventures International Inc. and have been prepared by management in accordance with Canadian generally accepted accounting principles and are consistent with the accounting policies set out in the Company's 2003 financial statements included in this prospectus, except as noted below. In management's opinion, all adjustments considered necessary for fair presentation of interim financial results have been incorporated into these financial statements.

These consolidated financial statements and notes should be read in conjunction with the Company's 2003 Annual Report and the unaudited interim financial statements for prior periods, as the interim statements do not conform in all respects to the note disclosure requirements of Canadian generally accepted accounting principles for annual financial statements.

2. CHANGE IN ACCOUNTING POLICIES

(a) Asset Retirement Obligations

Effective January 1, 2004 the Company adopted CICA Handbook section 3110 "Asset Retirement Obligations". This change in accounting policy has been applied retroactively with restatement of prior periods presented for comparative purposes. Previously, the Company recognized the provision for future site restoration and abandonment costs over the life of the Company's oil and gas properties using the unit-of-production method.

The Company now recognizes the fair value of an Asset Retirement Obligation ("ARO") in the period in which the obligation is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated fair value would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company's earnings in the period in which the settlement occurs.

As a result of this change, income before taxes and net income for the three months ended March 31, 2004 increased by $7,600 and decreased by $80,800, respectively. The impact on net income for the

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three months ended March 31, 2003 and the impact on the consolidated balance sheet at December 31, 2003, is shown below:

Unaudited Consolidated Statement of Income for the Three Months Ended March 31, 2003

Depletion, Depreciation and Amortization as reported		$	2,483,092
	Less: Provision for site restoration and abandonment		(130,275	)
	Plus: Asset retirement obligation amortization		99,588
	Plus: Asset retirement obligation accretion		34,884

Depletion, Depreciation and Accretion as restated		$	2,487,289

Consolidated Balance Sheet as at December 31, 2003

	As reported	Change		As restated
	($)	($)		($)
Property and equipment	124,893,508	7,711,385		132,604,893
Asset retirement obligation	—	8,875,379		8,875,379
Future income taxes	14,421,451	153,356		14,574,807
Provision for site restoration and abandonment	2,024,106	(2,024,106	)	—
Retained earnings	15,593,350	706,756		16,300,106

The total future asset retirement obligation was estimated by management based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Company has estimated the net present value of its total ARO to be $9,002,817 as at March 31, 2004, based on a total future liability of $20,128,900. These payments are expected to be made over the next 20 years with the majority of the costs to be incurred between 2011 and 2019. The Company's credit adjusted risk free rate of 6.1 per cent was used to calculate the present value of the asset retirement obligation.

The following table reconciles the Company's total asset retirement obligation:

	Three months ended March 31, 2004			Year ended December 31, 2003
Balance, beginning of period	$	8,875,379		$	2,288,242
Increase in obligation during the period		—			6,492,164
Settlement of obligation during the period		(7,865	)		(44,562	)
Accretion expense		135,303			139,535

Balance, end of period	$	9,002,817		$	8,875,379

(b) Full Cost Accounting

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recoverable and does not exceed the fair value of the properties. The costs are deemed to be recoverable if the undiscounted cash flows expected to result from the production of proved reserves are in excess of the carrying value of the oil and gas assets. If it is determined that the carrying value is not recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the discounted cash flows expected from the production of proved and probable reserves. Cash flows are estimated using future product prices and costs, and are discounted using the risk-free rate. The cost of unproved properties is excluded from the ceiling test calculation, which are subject to a separate impairment test. There were no indications of impairment as at March 31, 2004.

The CICA issued Accounting Guideline 13"Hedging Relationships", which deals with the identification, designation, documentation and effectiveness of hedging relationships for the purposes of applying hedge accounting. The guideline is effective for fiscal years beginning on or after July 1, 2003. Where hedge accounting does not apply, the Company would be required to account for its hedges on a mark-to-market basis and any changes in the mark-to-market value of the contracts relating to a financial period can either reduce or increase net earnings and net earnings per share for that period. The Company enters into certain financial instruments to manage its exposure to commodity price and the associated foreign currency risk and protect future cash flow, normally as part of a debt retirement program. These contracts qualify as hedges under the new accounting guideline and the Company applies hedge accounting to its financial instruments. This new accounting policy has been applied prospectively.

3. ACQUISITIONS & DISPOSITIONS

(a): On May 1, 2003, the Company acquired certain producing, development and exploratory petroleum and natural gas properties in North Central Alberta and Northeast British Columbia, along with undeveloped land, an inventory of 3-D seismic, and facilities. The purchase price was $68.4 million, of which $59 million has been ascribed to the acquired oil and natural gas reserves, with the remainder to undeveloped property, seismic and facilities. The effective date of the acquisition was May 1, 2003.
(b): On June 2, 2003, the Company disposed of certain producing petroleum and natural gas properties in North Central Alberta, along with an interest in facilities. The proceeds of disposition were $20.9 million. The effective date of the disposition was May 1, 2003.

4. LONG TERM DEBT

The Company has a revolving term credit facility with a Canadian financial institution. The Company has a total of $68 million available under this facility. Interest on advances is based on bank prime or banker's acceptance rates. The facility is subject to review by the bank and if certain conditions are not met, the facility becomes a two-year term loan, with repayment commencing 366 days after March 31, 2004. The loan facility is secured by a floating charge debenture in the amount of $175 million covering all of the assets of the Company and a general security agreement.

F-51

5. SHARE CAPITAL

Authorized

An unlimited number of voting common shares
An unlimited number of preferred shares

Issued

	Number of Shares	Consideration
Common Shares
Balance as at December 31, 2002	28,590,302	$	26,533,076
Issue of flow through shares	1,300,000		10,400,000
Tax effect of flow through share renouncement	—		(4,224,480	)
Share issue costs, net of tax effect of $218,151	—		(318,904	)

Balance as at December 31, 2003	29,890,302		32,389,692
Exercise of stock options	2,000		10,740

Balance as at March 31, 2004	29,892,302	$	32,400,432

On June 26, 2003, the Company issued 1,300,000 flow through shares at a price of $8.00 per share for proceeds of $10,400,000, before commission and expenses. Under the terms of the share issue, the Company is required to renounce to subscribers Canadian Exploration Expense in the amount of $10,400,000, to be incurred by the Company prior to December 31, 2004. The full amount has been incurred and renounced as at March 31, 2004.

Stock Based Compensation Plan

The Company has a stock option plan under which it may grant, at the Company's discretion, stock options to its directors, officers and employees for the purchase of common shares. Under the plan, 3,000,000 shares are reserved for issuance. The exercise price of each option equals the weighted average market price of the shares for the five days prior to the date of grant. The options vest in equal amounts at the end of each year for four years and expire at the end of the fifth year after granting. The following table summarizes the status of the Company's stock option plan as at March 31, 2004 and December 31, 2003 and changes during the period ended on those dates:

	Three months ended March 31, 2004			Year ended December 31, 2003
	Shares (000's)		Weighted-Average Exercise Price ($)	Shares (000's)		Weighted-Average Exercise Price ($)
Outstanding at beginning of period	2,717		5.41	2,455		5.37
Granted	15		5.44	546		5.56
Exercised	(2	)	5.37	—		—
Repurchased	—		—	(119	)	5.37
Cancelled	(15	)	5.35	(165	)	5.37

Outstanding at end of period	2,715		5.41	2,717		5.41

F-52

The Company accounts for its stock-based compensation plan using the fair value method of accounting, adopted January 1, 2003. This method has been applied to awards granted and settled on or after the year starting January 1, 2003. The total compensation recognized during the period to March 31, 2004, and included in the Company's statement of income and contributed surplus was $66,403. The weighted average fair value of options at the time of grant was $2.44 per share.

The fair value of each option on the date of grant is determined using the Black-Scholes option-pricing model with weighted average assumptions as follows:

Risk free interest rate (%)		4.25
Expected lives (years)		5.00
Expected volatility (%)		30.00
Dividend per share		0.00

The following shows pro forma net income and earnings per common share had the Company applied the fair value method to account for all stock options outstanding that were granted up to December 31, 2002. The fair value of the stock options granted after that date have been expensed as general and administrative costs.

			Three months ended March 31, 2004		Three months ended March 31, 2003
			($ thousands, except per share)
Fair value of stock options granted			255		204
Less: fair value of stock options expensed			(40	)	(5	)

			215		199
Net income:
	As reported		3,588		3,918
	Pro forma		3,373		3,719
Net income per common share
	Basic
		As reported	0.12		0.14
		Pro forma	0.11		0.13
	Diluted
		As reported	0.12		0.14
		Pro forma	0.11		0.13

6. PER SHARE AMOUNTS

	Three months ended March 31, 2004	Three months ended March 31, 2003
Basic
Net income per share ($)	0.12	0.14
Weighted average number of shares outstanding (000's)	29,891	28,590
Diluted
Net income per share ($)	0.12	0.14
Weighted average number of shares outstanding (000's)	30,074	28,697

F-53

The number of shares used to calculate diluted net income per share for the three months ended March 31, 2004 included the weighted average number of shares outstanding of 29,890,434 (three months ended March 31, 2003 28,590,302) plus 117,861 (three months ended March 31, 2003 106,510) shares related to the dilutive effect of stock options. The diluted net income per share for the three months ended March 31, 2004 did not include 241,000 shares (three months ended March 31, 2003 — nil) under the stock option plan because the respective exercise prices exceeded the average market price of the common shares.

7. CASH FLOW INFORMATION

	Three months ended March 31, 2004		Three months ended March 31, 2003
	($ thousands)
Accounts receivable	6,149		(178	)
Prepaid expenses	231		258
Accounts payable and accrued liabilities	(6,943	)	(4,049	)

Change in non-cash working capital	(563	)	(3,969	)

These changes relate to the following activities:
Operating activities	1,205		(6,863	)
Investing activities	(1,769	)	2,894

	(563	)	(3,969	)

Interest paid	497		411
Income taxes paid	—		—

8. RELATED PARTY TRANSACTIONS

(i): As part of the Plan of Arrangement (Note 1), the Company entered into a Technical Services Agreement with FET Resources Ltd., a successor company to Storm Energy Inc. Under this agreement, the Company provided certain technical and administrative services in exchange for a monthly fee of $350,000, which is recorded as a general and administrative cost recovery. The Technical Services Agreement expired June 30, 2003.
(ii): In January 2003, the Company sold its interest in certain producing oil and gas properties in the Medicine River area of central Alberta, for fair value proceeds of $2,800,000, to a private company, Rock Energy Ltd. ("Rock"), in exchange for common shares amounting to an approximate 46% ownership of Rock. The Company's interest has since decreased to 18% as a result of Rock entering into a reverse takeover of a public company and issuing additional share capital. The Company has recorded its interest in Rock at cost, as the ownership percentage is not significant and no influence is exercised in the direction of the company. The market value of the Company's shareholding in Rock approximates $7,852,900, as at March 31, 2004.
(iii): In September 2003, the Company established Storm Ventures International Inc. ("SVI"), a private corporation, with the purpose of participating in oil and gas activities outside of the Western Canadian Sedimentary Basin. The Company purchased 2,200,000 common shares in SVI for $1,100,000, to acquire a 50% interest. As part of the share purchase agreement, the Company is committed to subscribing for an additional 4,400,000 common shares of SVI at a price of $0.50 per share to be

F-54

payable on or before June 30, 2004, for a total investment of $3,300,000. Concurrently with the Company's initial share purchase, SVI raised an additional $2,200,000 under private placement arrangements, with participants, who included members of the Company's management and directors. Under the private placement participants are committed to providing an additional $4,500,000 on or prior to June 30, 2004, for a total investment of $6,700,000.

Failure by any participant to provide the additional funding will result in loss of their initial ownership position. The investment in SVI has been consolidated into the accounts of the Company as the Company is regarded as having operating and financial control. The subscription for additional shares has not been reflected in the accounts of the Company, as the Company is not bound to the obligation. However, should such payment not occur, the Company will surrender its original investment.

The cash balance of $2,952,638, included in current assets, is an asset of SVI and cannot be used to reduce the Company's revolving long-term debt facility (Note 4). The minority interest balance represents the third party ownership of the SVI assets which arises as a result of the consolidation of the accounts of SVI into the Company's accounts.

9. DERIVATIVE FINANCIAL INSTRUMENTS

The following contracts were closed during the three months ended March 31, 2004, with the associated gains/losses recognized in production income:

Exposure	Volume hedged	Pricing	Term	Realized Gain/(Loss)
Oil	1,250 bbls/day	US$29.83/bbl	January 1, 2004 – March 31, 2004	US$(606,504	)
	1,250 bbls/day	US$30.04/bbl	January 1, 2004 – March 31, 2004	US$(582,616	)
Foreign Currency	US$700,000/month	1.345 CAD/USD	January 1, 2004 – March 31, 2004	CAD$57,120

At March 31, 2004, the Company had entered into the following contracts:

Exposure	Volume Hedged	Pricing	Term
Oil	1,250 bbls/day	US$28.62/bbl	April 1, 2004 – June 30, 2004
	1,250 bbls/day	US$28.27/bbl	April 1, 2004 – June 30, 2004
	1,250 bbls/day	US$24.00/bbl & cost of US$2.80/bbl	July 1, 2004 – December 31, 2004

10. SUBSEQUENT EVENT

Subsequent to March 31, 2004, the Company has entered into an agreement for a business combination pursuant to a Plan of Arrangement with Harvest Energy Trust ("Harvest"). The Plan of Arrangement provides for the acquisition by a subsidiary of Harvest Energy Trust of the common shares of Storm Energy Ltd. in exchange for cash, units of Harvest and exchangeable shares, or a combination of each. Shareholders will also receive shares of Rock Energy Ltd., and shares of a smaller exploration company, Storm Energy Ltd. which will own certain producing and development assets of Storm Energy Ltd. Completion of the Plan is subject to various conditions, including the receipt of all regulatory, shareholder and Court approvals.

F-55

11. RECONCILIATION OF THE CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

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

	For the Three Months Ended March 31
	2004			2003
	(thousands)			(thousands)
Consolidated net income as reported	$	3,588		$	3,918
Adjustments
Depletion, depreciation and accretion^(b)		—			—
Unrealized loss on derivative financial instruments^(d)		(1,652	)		468
Future income tax effect on unrealized loss on derivative financial instruments^(d)		660			(187	)
Equity investment in Rock Energy^(g)		—			99
Gain on dilution of investment in Rock Energy^(g)		964			—
Non-cash general and administrative expenses^(c)		(425	)		(256	)

Net income under U.S. GAAP before cumulative effect of change in accounting policy		3,135			4,042

Cumulative effect of change in accounting policy^(b)		—			22

Net income under U.S. GAAP after cumulative effect of change in accounting policy	$	3,135		$	4,064

Basic
Net income under U.S. GAAP before cumulative effect of change in accounting policy	$	0.11		$	0.14
Cumulative effect of change in accounting policy^(b)		—			—

Net income after the cumulative effect of change in accounting policy	$	0.11		$	0.14

Diluted
Net income under U.S. GAAP before cumulative effect of change in accounting policy	$	0.10		$	0.12

Net income after the cumulative effect of change in accounting policy	$	0.10		$	0.12

F-56

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

		March 31, 2004				December 31, 2003
		Canadian GAAP		U.S. GAAP		Canadian GAAP		U.S. GAAP
		(thousands)				(thousands)
Assets
	Property and equipment^(b)	$	138,335	$	138,335	$	132,605	$	132,605
	Investment^(g)		2,810		3,919		2,810		2,955
Liabilities
	Commodity derivative contracts^(d)		—		5,380		—		3,728
	Future taxes^(b)(d)(e)		15,283		13,053		14,575		13,005
	Asset retirement obligation^(b)		9,003		9,003		8,875		8,875
Shareholders' Equity
	Share capital^(e)		32,400		38,816		32,390		38,806
	Contributed surplus^(c)		151		1,182		85		691
	Retained earnings	$	19,888	$	10,399	$	16,300	$	7,265

(a): The Company 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 Company's risk free interest rate. For periods prior to January 1, 2004, the Company used undiscounted future net revenue from proved oil and natural gas reserves plus the cost of unproved properties less impairment, using period end prices. Under U.S. GAAP, entities using the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using future net revenue from proved oil and natural gas reserves discounted at ten percent. The prices used under the U.S. GAAP ceiling tests are those in effect at period and year end. There was no adjustment required under application of U.S. GAAP.
(b): Effective January 1, 2004, the Company retroactively adopted the CICA Handbook standard for accounting for asset retirement obligations. This section is equivalent to Statement of Financial Accounting Standards ("FAS") 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): For Canadian GAAP purposes, the Company recognizes compensation expense using the fair value method for rights granted on or after January 1, 2003. For US GAAP purposes, the Company has accounted for all rights granted since inception using the fair value method of accounting. An adjustment to earnings has been recorded to reflect the associated additional compensation expense.
(d): The fair market value for derivative instruments used for hedging activities are not recorded within the financial statements under Canadian GAAP for the three months ended March 31, 2004 and 2003 and the year ended December 31, 2003. Under U.S. GAAP, FAS No. 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. If the derivative is designated a fair value hedge, the changes in the fair value of the derivative and the hedged item attributable to the hedged risk are recognized in income. If the derivative is designated a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income and are recognized in income when the hedged item is realized. Ineffective portions of change in fair value are recognized in income immediately. For a derivative designated as a cash flow hedge, U.S. GAAP requires that a company formally document, designate, and assess the effectiveness of derivative instruments that receive this accounting treatment. The Company had not formally documented and designated all hedging relationships for U.S. GAAP purposes as at March 31, 2004 and 2003 as well as December 31, 2003, and as such was not eligible for hedge accounting treatment under U.S. GAAP.

F-57

(e): Under U.S. GAAP flow-through shares are recorded at their fair value without any adjustment for the renouncement of the tax deductions, and any temporary difference resulting from the renouncement must be recognized in the determination of tax expense in the year incurred. U.S. GAAP also requires that the estimated cost of the tax deductions renounced be recorded as a future income tax liability. In addition, any proceeds received in excess of the quoted market value of the shares is recognized in the determination of income tax expense for the period.
(f): The Canadian GAAP liability method of accounting for income taxes is similar to the U.S. GAAP FAS No. 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 Company's consolidated financial statements. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates. There are no differences for the three months ended March 31, 2004 and 2003 or as at December 31, 2003.
(g): Under Canadian GAAP, the Company's interest in Rock Energy Inc. is recorded on a cost basis, as the ownership percentage is not significant and no influence is exercised in the direction of the company. Under U.S. GAAP, this investment is required to be accounted for on an equity basis due to the ownership percentage of the investment. An adjustment has been made in the financial statements to reflect the Company's interest in Rock Energy. As a result of the Company's dilution in its investment in Rock Energy effective January 7, 2004, its ownership has decreased to less than 20% and thus equity basis accounting is no longer necessary for this investment.
(h): 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 operating cash flow before changes in non-cash working capital items in the consolidated statement of cash flows. This total cannot be presented under U.S. GAAP. U.S. GAAP would require this statement to be a note to the financial statements.
(i): The following are standards and interpretations that have been issued by the Financial Accounting Standards Board ("FASB") and the Company has assessed the impact to be as follows:

Accounting for certain financial instruments with characteristics of both liabilities and equity

In 2003, FASB issued FAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." FAS No. 150 establishes standards for the measurement and classification of certain financial instruments with characteristics of both liabilities and equity. FAS No. 150 is applicable to financial instruments entered into or modified after May 31, 2003, and otherwise effective at the beginning of the first interim period beginning after May 31, 2003. This standard did not have any impact on the Company.

Consolidation of Variable Interest Entities

In 2003, FASB issued Interpretation Number 46R, "Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51." The standard mandates that variable interest entities be consolidated by their primary beneficiary. In Canada, the Accounting Standards Board (ACSB) has suspended the effective dates for the Canadian Institute of Chartered Accountants ("CICA") Handbook Accounting Guideline 15, "Consolidation of Variable Interest Entities" to amend the guideline to harmonize it with FAS Interpretation Number 46R. This will be effective for periods beginning after November 1, 2004. At March 31, 2004 and 2003 as well as December 31, 2003, the Company did not have any variable interests in variable interest entities.

F-58

CONSENT OF DELOITTE & TOUCHE LLP

We have read the short form prospectus of Harvest Operations Corp. (the "Corporation") dated January 10, 2005, related to the qualification for distribution of up to US$250,000,000 principal amount of senior notes of the Corporation unconditionally guaranteed by Harvest Energy Trust. We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the use in the above-mentioned short form prospectus of our report to the shareholders of Storm Energy Ltd. on the consolidated balance sheets of Storm Energy Ltd. as at December 31, 2003 and 2002 and the consolidated statements of income and retained earnings and cash flow for the year ended December 31, 2003 and for the period from commencement of operations on August 23, 2002 to December 31, 2002. Our report is dated February 18, 2004 (except as to Notes 1(a) and 11 which are as of October 7, 2004).

Calgary, Alberta		(Signed) DELOITTE & TOUCHE LLP
January 10, 2005		Chartered Accountants

F-59

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Shareholders of Storm Energy Ltd.:

We have audited the consolidated balance sheets of Storm Energy Ltd. as at December 31, 2003 and 2002 and the consolidated statements of income and retained earnings and cash flows for the year ended December 31, 2003 and for the period from commencement of operations on August 23, 2002 to December 31, 2002. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for the year ended December 31, 2003 and for the period from commencement of operations on August 23, 2002 to December 31, 2002 in accordance with Canadian generally accepted accounting principles.

On February 18, 2004, we issued our report to the shareholders of Storm Energy Ltd. on the consolidated financial statements for the same periods, prepared in accordance with Canadian generally accepted accounting principles which did not include Note 1(a), change in accounting policies and Note 11, reconciliation of the consolidated financial statements to United States generally accepted accounting principles.

Calgary, Alberta
February 18, 2004
(except as to Notes 1(a) and 11
which are as of October 7, 2004)

(Signed) DELOITTE & TOUCHE LLP
Independent Registered Chartered Accountants

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

The standards of the Public Company Accounting Oversight Board (United States) for auditors require the addition of an explanatory paragraph (following the opinion paragraph) outlining changes in accounting principles that have been implemented in the financial statements, certain of which have a material effect on the comparability of the financial statements. As discussed in Note 5 to the consolidated financial statements, in 2003 the Company prospectively adopted the new Canadian Institute of Chartered Accountants ("CICA") Handbook recommendation 3870 with respect to stock-based compensation and as discussed in Note 1(a) to the consolidated financial statements, the Company retroactively adopted the new CICA Handbook recommendation 3110 with respect to asset retirement obligations. We conducted our audit in accordance with Canadian generally accepted auditing standards, our report to the shareholders dated February 18, 2004 (except as to Notes 1(a) and 11 which are as of October 7, 2004) is expressed in accordance with Canadian reporting standards which do not include this reference.

Calgary, Alberta
October 7, 2004

(Signed) DELOITTE & TOUCHE LLP
Independent Registered Chartered Accountants

F-60

STORM ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

		December 31, 2003		December 31, 2002
		(Restated — Note 1)		(Restated — Note 1)
ASSETS
Current
	Cash (Note 9(c))	$	3,034,282	$	—
	Accounts receivable		21,516,419		13,719,444
	Prepaid expenses		999,922		742,512

			25,550,623		14,461,956
Investment (Note 9(b))			2,810,140		—
Property and equipment (Notes 2 & 3)			132,604,893		67,568,082

		$	160,965,656	$	82,030,038

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
	Accounts payable and accrued liabilities	$	31,648,087	$	23,367,504
Long-term debt (Note 4)			55,575,425		22,061,767
Future income taxes (Note 6)			14,574,807		2,677,073
Asset retirement obligation (Note 1)			8,875,379		2,288,242
Minority interest (Note 9(c))			1,517,141		—
Shareholders' equity
	Share capital (Note 5)		32,389,692		26,533,076
	Contributed surplus (Note 5)		85,019		—
	Retained earnings		16,300,106		5,102,376

			48,774,817		31,635,452

		$	160,965,656	$	82,030,038

See accompanying notes

F-61

STORM ENERGY LTD.

CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

		Year Ended December 31, 2003			Year Ended December 31, 2002⁽¹⁾
		(Restated — Note 1)			(Restated — Note 1)
Revenue
	Production income	$	59,547,522		$	17,762,474
	Royalties, net		(13,674,387	)		(4,738,025	)
	Other		466,742			193,295

			46,339,877			13,217,744

Expenses
	Production		6,317,776			1,862,117
	General and administrative		4,510,370			1,931,918
	General and administrative cost recovery (Note 9(a))		(2,100,000	)		(1,501,613	)
	Interest on long-term debt		3,194,040			519,761
	Depletion, depreciation and accretion		15,019,912			3,442,990

			26,942,098			6,255,173

Income before income and other taxes			19,397,779			6,962,571
Income and other taxes (Note 6)
	Future income taxes		7,891,265			2,868,625
	Capital taxes		308,784			59,203

			8,200,049			2,927,828

Net income for the period (Note 7)			11,197,730			4,034,743
Retained earnings, beginning of period			5,102,376			—
Retroactive change of accounting policy (Note 1(a))			—			1,067,633

Retained earnings, end of period		$	16,300,106		$	5,102,376

(1): Amounts for 2002 are for the period from August 23, 2002 to December 31, 2002.
See accompanying notes

F-62

STORM ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

			Year Ended December 31, 2003			Year Ended December 31, 2002⁽¹⁾
			(Restated — Note 1)			(Restated — Note 1)
Operating activities
	Net income for the period		$	11,197,730		$	4,034,743
	Add non-cash items:
		Depletion, depreciation and accretion		15,019,912			3,442,990
		Stock-based compensation (Note 5)		85,019			—
		Future income taxes		7,891,265			2,868,625

Cash flow from operations				34,193,926			10,346,358

Actual site restoration paid				(44,562	)		(8,429	)
Net change in non-cash working capital items (Note 8)				(7,828,112	)		6,586,845

				26,321,252			16,924,774

Financing activities
	Increase (decrease) in long-term debt			33,513,658			(2,230,632	)
	Minority interest			1,517,141			—
	Issuance of flow-through shares, net			9,862,945			—

				44,893,744			(2,230,632	)

Investing activities
	Property and equipment additions			(106,518,481	)		(18,588,412	)
	Property and equipment dispositions			30,283,458			—
	Net change in non-cash working capital items (Note 8)			8,054,309			3,894,270

				(68,180,714	)		(14,694,142	)

Change in cash during the period				3,034,282			—
Cash, beginning of period				—			—

Cash, end of period			$	3,034,282		$	—

(1): Amounts for 2002 are for the period from August 23, 2002 to December 31, 2002.
See accompanying notes

F-63

STORM ENERGY LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2003
(Amounts for 2002 are for the period from August 23, 2002 to December 31, 2002)

1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Storm Energy Ltd. (the "Company") was incorporated on July 15, 2002 and commenced operations on August 23, 2002 under a Plan of Arrangement entered into by Storm Energy Inc., a Toronto Stock Exchange listed public company. Under the Plan of Arrangement various assets of Storm Energy Inc., comprising certain producing and undeveloped assets, were transferred to Storm Energy Ltd., along with a pro rata share of debt. Storm Energy Inc. continued as FET Resources Ltd., a wholly owned subsidiary of Focus Energy Trust.

The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles and include the accounts of the Company, its wholly owned subsidiary, Redearth Energy Inc., its 60% share of the Redearth Partnership, and its 50% interest in Storm Ventures International Inc. The preparation of these consolidated financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect the amounts reported in the statements and the accompanying notes. As a result, actual results could differ from estimated amounts. These consolidated financial statements have, in management's opinion, been properly prepared within reasonable limits of materiality and within the framework of the accounting principles summarized below.

(a) Change in Accounting Policies

Asset Retirement Obligation

Previously, the Company recognized the provision for future site restoration and abandonment costs over the life of the Company's oil and gas properties using the unit-of-production basis.

The Company now recognizes the fair value of an Asset Retirement Obligation ("ARO") in the period in which the obligation is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated discounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company's earnings in the period in which the settlement occurs.

The impact on the consolidated balance sheet as at December 31, 2003 and 2002, is shown below.

F-64

Consolidated Statement of Income

		Year ended December 31, 2003		Year ended December 31, 2002
Depletion, Depreciation and Amortization as reported		14,723,055		3,532,187
	Less: Provision for site restoration and abandonment	(803,972	)	(205,353	)
	Plus: Asset retirement obligation amortization	961,294		116,156
	Plus: Asset retirement obligation accretion	139,535		—

Depletion, Depreciation and Accretion as restated		15,019,912		3,442,990

Consolidated Balance Sheet

	December 31, 2003				December 31, 2002
	As reported	Change		Restated	As reported	Change		Restated
Property and equipment	124,893,508	7,711,385		132,604,893	65,387,567	2,180,515		67,568,082
Asset retirement obligation	—	8,875,379		8,875,379	—	2,288,242		2,288,242
Future income taxes	14,421,451	153,356		14,574,807	2,677,073	—		2,677,073
Provision for site restoration and abandonment	2,024,106	(2,024,106	)	—	1,264,557	(1,264,557	)	—
Retained earnings	15,593,350	706,756		16,300,106	3,945,546	1,156,830		5,102,376

The total future asset retirement obligation was estimated by management based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Company has estimated the net present value of its total ARO to be $8,875,379 as at December 31, 2003, based on a total future liability of $20,128,900. These payments are expected to be made over the next 20 years with the majority of the costs incurred between 2011 and 2019. The Company's credit adjusted risk free rate of 6.1 per cent was used to calculate the present value of the asset retirement obligation.

Consolidated Statement of Income

The following table reconciles the Company's total asset retirement obligation:

	December 31, 2003		December 31, 2002
Carrying amount, beginning of period	2,288,242		—
Increase in liabilities during the period	6,492,164		2,296,671
Settlement of liabilities during the period	(44,562	)	(8,429	)
Accretion expense	139,535		—

Carrying amount, end of period	8,875,379		2,288,242

F-65

Full Cost Accounting Guideline

Effective January 1, 2004, the Company adopted the CICA Accounting Guideline 16, which replaced Accounting Guideline 5, "Full Cost Accounting in the Oil and Gas Industry". This change in accounting policy has been adopted prospectively. The most significant change is the modification of the ceiling test, where the new guideline limits the carrying value of oil and gas properties to their fair value. Oil and gas assets are tested in each reporting period to determine that the book value is recoverable and does not exceed the fair value of the properties. The costs are deemed to be recoverable if the undiscounted cash flows expected to result from the production of proved reserves are in excess of the carrying value of the oil and gas assets. If it is determined that the carrying value is not recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the discounted cash flows expected from the production of proved and probable reserves. Cash flows are estimated using future product prices and costs, and are discounted using the risk-free rate. The cost of unproved properties is excluded from the ceiling test calculation, which are subject to separate impairment test. There were no indications of impairment as at December 31, 2003.

Hedging Relationships

The CICA issued Accounting Guideline 13 — "Hedging Relationships", which deals with the identification, designation, documentation and effectiveness of hedging relationships for the purposes of applying hedge accounting. The guideline is effective for fiscal years beginning on or after July 1, 2003. Where hedge accounting does not apply, the Company would be required to account for its hedges on a mark-to-market basis and any changes in the mark-to-market value of the contracts relating to a financial period can either reduce or increase net earnings and net earnings per share for that period. The Company enters into certain financial instruments to manage its exposure to commodity price and the associated foreign currency risk and protest future cash flow, normally as part of a debt retirement program. These contracts qualify as hedges under the new accounting guideline and the Company applies hedge accounting to is financial instruments. This new accounting policy has been applied prospectively.

(b) Property and Equipment

Petroleum and Natural Gas Properties and Equipment

The Company follows the full-cost method of accounting for petroleum and natural gas properties, whereby all costs associated with the exploration for and development of petroleum and natural gas reserves, whether productive or unproductive, are capitalized in a Canadian cost centre. Such costs include lease acquisition, drilling, geological and geophysical equipment costs and overhead expenses related to exploration and development activities. Costs of acquiring and evaluating unproved properties are excluded from depletion calculations until it is determined whether or not proved reserves are attributable to the properties.

Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion of 20% or more.

Depletion of petroleum and natural gas properties and depreciation of production equipment is provided using the unit-of-production method based on estimated proved petroleum and natural gas

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reserves, before royalties, as determined by independent engineers. Production and reserves of natural gas are converted to equivalent barrels of crude oil on the basis of six thousand cubic feet of gas to one barrel of oil. Processing facilities are depreciated on a straight-line basis over the estimated useful life of the facility.

The depletion and depreciation cost base includes total capitalized costs, less prior depletion and depreciation charges, less costs of unproved properties and salvage, plus provision for estimated future development costs of proved undeveloped reserves.

The net carrying value of the Company's petroleum and natural gas properties is limited to an ultimate recoverable amount ("ceiling test"). This amount is the aggregate of estimated future net revenues from proved reserves and the costs of unproved properties, net of impairment allowances, less future estimated production costs, general and administrative costs, financing costs, future site restoration and abandonment costs and income taxes. Future net revenues are estimated using year-end prices and costs without escalation or discounting, and the income tax and Alberta Royalty Tax Credit legislation in effect at the end of the year. Any carrying amount in excess of the ceiling test is charged to current operations as additional depletion. No such charges have been incurred by the Company since inception.

Office Furniture and Equipment

Office equipment is recorded at cost and is depreciated on the declining balance basis using rates varying from 7% to 100% per annum.

Leasehold Improvements

Leasehold improvements are recorded at cost and are depreciated on a straight-line basis over the lease term, including one renewal period.

Certain of the Company's exploration and production activities are conducted jointly with others through unincorporated joint ventures. The accounts of the Company reflect its proportionate interest in such activities.

(d) Revenue Recognition

Revenues from the sale of crude oil, natural gas liquids, and natural gas are recorded when title passes to a third party.

(e) Income Taxes

Income taxes are calculated using the liability method of tax accounting. Temporary differences arising from the difference between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax assets and liabilities. Future income tax assets and liabilities are calculated using tax rates anticipated to apply in the periods that the temporary differences are expected to reverse.

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(f) Measurement Uncertainty

The amounts recorded for depletion and depreciation of capital assets, the provision for site restoration and abandonment costs and amounts used for ceiling test calculations are based on estimates of reserves and future costs. The Company's reserve estimates are reviewed annually by independent engineers. These estimates of reserves and related future cash flow are subject to measurement uncertainty and the impact on the consolidated financial statements of changes in such estimates in future periods could be material.

(g) Financial Instruments

The Company uses derivative financial instruments from time to time to hedge its exposure to commodity price and the associated foreign currency risk. Such financial instruments are used to protect future cash flow, normally as part of a debt retirement program following a debt-financed acquisition. The Company does not enter into derivative financial instruments for trading or speculative purposes.

The derivative financial instruments correspond to the Company's formal risk management policy. Under the policy, derivatives are linked to specific assets and liabilities or to specific firm commitments or anticipated transactions. The Company considers that the derivative financial instruments are effective as hedges, both at the inception of and throughout the term of the instrument, as the term and notional amount do not exceed the Company's firm commitment or forecasted transaction and the underlying basis of the instrument, such as commodity price or foreign exchange rate, matches the Company's exposure.

The Company enters into hedges of its exposure to crude oil and natural gas commodity prices by entering into crude oil and natural gas swap contracts, options or collars, when it is deemed appropriate under its risk management policy. The derivative contracts, accounted for as hedges, are not recognized on the Company's balance sheet. Actual gains or losses on these contracts are included in production income and cash flow in the same period in which the revenues associated with the hedged transactions are recognized.

The Company may enter into foreign exchange forward contracts to hedge anticipated US dollar denominated crude oil and natural gas sales. These derivatives are accounted for as hedges and are not recognized on the balance sheet. Gains and losses on these derivatives are included in production income when the sale is recorded.

The carrying values of short-term financial instruments, being cash, accounts receivable and accounts payable, approximate their fair values. The fair value of long-term debt approximates its carrying value due to the floating interest rate and the revolving nature of the obligation.

A substantial portion of the Company's accounts receivable are concentrated with a limited number of purchasers of commodities and joint venture partners in the oil and gas industry and are subject to normal industry credit risk. Management considers these concentrations of credit risk to be minimal, as commodity purchasers are considered to be major industry participants, and receivables from partners are protected by effective industry standard legal remedies.

The Company is exposed to interest rate risk to the extent that long-term debt bears interest based on bank prime or banker's acceptance rates.

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(h) Stock-Based Compensation

The Company has a stock-based compensation plan for employees and directors as described in Note 5. The Company follows the fair value method of accounting for the compensation costs associated with the plan, whereby an estimate of the fair value of the stock options granted is measured and recorded as compensation cost over the period during which the related services are rendered, with the related offset recorded as contributed surplus. The effect of actual forfeitures by employees or directors of a previously granted option are recognized as they occur. Any consideration paid by employees or directors with respect to the exercise of stock options is credited to share capital.

(i) Flow-Through Shares

Flow-through shares are issued at a fixed price and the proceeds are used to fund qualifying exploration expenditures within a defined period. The expenditures funded by flow-through arrangements are renounced to investors in accordance with tax legislation. Share capital is reduced and future tax liability is increased by the total estimated future income tax cost of the renounced tax deductions in the year of issue.

(j) Per Share Amounts

Net income per share is calculated using the weighted average number of shares outstanding during the period. Diluted net income per share is calculated using the treasury stock method to determine the dilutive effect of stock options. The treasury stock method assumes that the proceeds received from the exercise of "in the money" stock options are used to repurchase common shares at the average market price during the period.

2. TRANSFER OF ASSETS AND COMMENCEMENT OF OPERATIONS

Under the Plan of Arrangement dated August 23, 2002, Storm Energy Inc. transferred to Storm Energy Ltd. certain assets, being producing and undeveloped oil and gas properties, administrative assets and working capital, and an amount of long-term debt. As this was a related-party transaction, assets and liabilities were transferred at book value. Details are as follows:

Petroleum and natural gas assets and equipment	$	49,739,821
Office furniture and equipment		348,714
Leasehold improvements		37,454
Net working capital		1,575,566
Future income tax		191,551

Total assets transferred		51,893,106
Long-term debt		(24,292,399	)
Provision for site restoration and abandonment		(1,067,731	)

Net assets transferred and share capital issued	$	26,532,976

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3. PROPERTY AND EQUIPMENT

		December 31, 2003				December 31, 2002
		Cost		Accumulated Depletion and Depreciation		Cost		Accumulated Depletion and Depreciation
Petroleum and natural gas properties and equipment		$	150,456,219	$	18,174,183	$	70,618,972	$	3,405,267
Office furniture and equipment			434,474		131,552		354,533		33,315
	Leasehold improvements		37,567		17,632		37,567		4,408

		$	150,928,260	$	18,323,367	$	71,011,072	$	3,442,990

Net book value			$132,604,893				$67,568,082

Undeveloped property costs of $11,632,384 ($6,296,471 — December 31, 2002) were excluded from the depletable base at December 31, 2003.

A ceiling test calculation as at December 31, 2003 indicated that the ultimate recoverable amount from proved reserves exceeded the net carrying value of the Company's petroleum and natural gas properties. The ceiling test is a cost recovery test and is not an estimate of fair market value. The prices used in the ceiling test were based on the year-end prices received, being $39.45 (Cdn) per barrel of crude oil, $7.99 per mcf for gas and an average of $32.49 (Cdn) per barrel of natural gas liquids.

As at December 31, 2003, the Company's share of the estimated future site restoration and abandonment costs, net of accruals already accounted for, to be accrued over the life of the remaining proved reserves was $8,149,000 ($3,575,000 — December 31, 2002).

4. LONG-TERM DEBT

The Company has a revolving term credit facility with a Canadian financial institution. The Company has $68,000,000 available under this facility. Interest on advances is based on bank prime or banker's acceptance rates. The facility is subject to review by the bank and if certain conditions are not met the facility becomes a two-year term loan, with repayment commencing 366 days after March 31, 2004. The loan facility is secured by a floating charge debenture in the amount of $175 million covering all of the assets of the Company and a general security agreement. The next scheduled review of the borrowing base is March 31, 2004.

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5. SHARE CAPITAL

Authorized

An unlimited number of voting common shares
An unlimited number of preferred shares

Issued

	Number of Shares	Consideration
Common Shares
Issued upon incorporation	—	$	100
Issued in connection with Plan of Arrangement	28,590,302		26,532,976

Balance as at December 31, 2002	28,590,302		26,533,076

Issue of flow-through shares	1,300,000		10,400,000
Tax effect of flow-through share renunciation	—		(4,224,480	)
Share issue costs, net of tax effect of $218,151	—		(318,904	)

Balance as at December 31, 2003	29,890,302	$	32,389,692

On June 26, 2003, the Company issued 1,300,000 flow-through shares at a price of $8.00 per share for proceeds of $10,400,000, before commission and expenses. Under the terms of the share issue, the Company is required to renounce to subscribers Canadian exploration expenditures in the amount of $10,400,000 to be incurred by the Company prior to December 31, 2004.

Stock-Based Compensation Plan

The Company has a stock option plan under which it may grant, at the Company's discretion, stock options to its directors, officers and employees for the purchase of common shares. Under the plan, 3,000,000 shares are reserved for issuance. The exercise price of each option equals the weighted average market price of the shares for the five days prior to the date of grant. The options vest in equal amounts at the end of each year for four years and expire at the end of the fifth year after granting. The following table summarizes the status of the Company's stock option plan as at December 31, 2003 and 2002 and changes during the periods ended on those dates:

	December 31, 2003			December 31, 2002
	Options (000s)		Weighted-Average Exercise Price ($)	Options (000s)	Weighted-Average Exercise Price ($)
Outstanding at beginning of period	2,455		5.37	—	—
Granted	546		5.56	2,455	5.37
Repurchased	(119	)	5.37	—	—
Cancelled	(165	)	5.37	—	—

Outstanding at end of period	2,717		5.41	2,455	5.37

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The following table summarizes information about stock options outstanding at December 31, 2003:

Range of exercise prices ($)		Number Outstanding at 12/31/03		Average Remaining Contractual Life		Weighted-Average Exercise Price ($)		Number Exercisable at 12/31/03
5.37 – 6.37		2,716,824		3.94 years		5.41		545,456

The Company has adopted the fair value method of accounting for stock options effective January 1, 2003. This is a change in accounting policy and has been adopted on a prospective basis. This method has been applied to awards granted and settled on or after the year starting January 1, 2003. Had this new method not been adopted, the Company would have disclosed the pro forma effects on income. The adoption of the new policy results in a charge to income. The total compensation recognized during the year and included in the Company's statement of income was $85,019, with the related offset recorded as contributed surplus. The weighted average fair value of options at the time of grant was $2.45 per share.

The fair value of each option on the date of grant is determined using the Black-Scholes option-pricing model with weighted average assumptions as follows:

Risk free interest rate (%)		4.25
Expected lives (years)		5.00
Expected volatility (%)		40.00
Dividend per share		0.00

			December 31, 2003			December 31, 2002
			($ thousands, except per share)
Fair value of stock options granted			$	656		$	278
Less: fair value of stock options expensed				(50	)		—

			$	606		$	278
Net income
	As reported		$	11,198		$	4,035
	Pro forma		$	10,592		$	3,757
Net income per common share
	Basic
		As reported	$	0.38		$	0.14
		Pro forma	$	0.36		$	0.13
	Diluted
		As reported	$	0.38		$	014
		Pro forma	$	0.36		$	013

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6. INCOME AND OTHER TAXES

The provision for future income taxes is different from the amount computed by applying the combined statutory Canadian federal and provincial tax rates to pre-tax income for the period. The differences are as follows:

		December 31, 2003			December 31, 2002
Statutory combined federal and provincial income tax rate			40.74	%		42.12	%
Expected income taxes		$	7,902,655		$	2,895,065
Add (deduct) the income tax effect of:
	Non-deductible crown charges		3,667,390			1,658,749
	Resource allowance		(3,597,057	)		(1,462,388	)
	Future income tax rate reductions		(687,362	)		—
	Alberta Royalty Tax Credit		(54,950	)		(1,808	)
	Other non-deductible charges		16,578			—
	Other		369,207			(220,993	)

			7,891,265			2,868,625
	Large corporations tax		308,784			59,203

		$	8,200,049		$	2,927,828

The components of the future tax liability at December 31, 2003 and 2002 are as follows:

	December 31, 2003			December 31, 2002
Property and equipment	$	(10,381,461	)	$	(2,797,534	)
Non-coterminous year-end income deferral		(7,489,957	)		—
Provision for site restoration and abandonment		3,072,656			532,631
Other		223,955			(412,170	)

Net future income tax liability	$	(14,574,807	)	$	(2,677,073	)

7. PER SHARE AMOUNTS

	Year Ended December 31, 2003		Period Ended December 31, 2002
Basic
Net income per share	$	0.38	$	0.14
Weighted-average number of shares outstanding (000s)		29,260		28,590
Diluted
Net income per share	$	0.38	$	0.14
Weighted-average number of shares outstanding (000s)		29,295		28,799

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8. CASH FLOW INFORMATION

	Year Ended December 31, 2003			Period Ended December 31, 2002
Accounts receivable	$	(7,796,975	)	$	(12,993,086	)
Prepaid expenses		(257,410	)		(440,678	)
Accounts payable and accrued liabilities		8,280,582			23,914,879

Change in non-cash working capital	$	226,197		$	10,481,115

These changes relate to the following activities:
Operating activities	$	(7,828,112	)	$	6,586,845
Investing activities		8,054,309			3,894,270

	$	226,197		$	10,481,115

Interest paid for the period ended December 31	$	2,683,140		$	519,761
Income taxes paid	$	—		$	—

9. RELATED-PARTY TRANSACTIONS

(a): As part of the Plan of Arrangement, the Company entered into a Technical Services Agreement with FET Resources Ltd., a successor company to Storm Energy Inc. Under this agreement, the Company provided certain technical and administrative services in exchange for a monthly fee of $350,000, which is recorded as a general and administrative cost recovery. The Technical Services Agreement expired June 30, 2003.
(b): In January 2003, the Company sold its interest in certain producing oil and gas properties in the Medicine River area of central Alberta, for fair value proceeds of $2,800,000, to a private company, Rock Energy Inc. ("Rock"), in exchange for common shares amounting to an approximate 46% ownership of Rock. The Company's interest has since decreased to 18% as a result of Rock entering into a reverse takeover of a public company and issuing additional share capital. The Company has recorded its interest in Rock at cost, as the ownership percentage is not significant and no influence is exercised in the direction of the company. The market value of the Company's shareholding in Rock approximates $14,000,000, as at December 31, 2003.
(c): In September 2003, the Company established Storm Ventures International Inc. ("SVI"), a private corporation, with the purpose of participating in oil and gas activities outside of the Western Canadian Sedimentary Basin. The Company purchased 2,200,000 common shares in SVI for $1,100,000, to acquire a 50% interest. As part of the share purchase agreement, the Company is committed to subscribing for an additional 4,400,000 common shares of SVI at a price of $0.50 per share to be payable on or before June 30, 2004, for a total investment of $3,300,000. Concurrently with the Company's initial share purchase, SVI raised an additional $2,200,000 under private placement arrangements with participants who included members of the Company's management and directors. Under the private placement, participants are committed to providing an additional $4,500,000 on or prior to June 30, 2004, for a total investment of $6,700,000. Failure by any participant to provide the additional funding will result in loss of their initial ownership position. The investment in SVI has been consolidated into the accounts of the Company as the Company is regarded as having operating and financial control. The subscription for additional shares has not been reflected in the accounts of the Company, as the Company is not bound to the obligation. However, should such payment not occur, the Company will surrender its original investment.

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The cash balance of $3,034,282, included in current assets, is an asset of SVI and cannot be used to reduce the Company's revolving long-term debt facility (Note 4). The minority interest balance represents the third-party ownership of the SVI assets which arises as a result of the consolidation of the accounts of SVI.

10. DERIVATIVE FINANCIAL INSTRUMENTS

The following contracts were closed during the year ended December 31, 2003 with the associated gains/losses recognized in production income for the period:

Exposure	Volume Hedged	Pricing	Term	Realized Gain (Loss)
Oil	1,250 Bbls/d	Floor @ US$ 26.00/Bbl Ceiling @ US$ 33.85/Bbl	April 1, 2003 – June 30, 2003	nil
	1,250 Bbls/d	Floor @ US$ 26.00/Bbl Ceiling @ US$ 29.85/Bbl	July 1, 2003 – Sept 30, 2003	US$ (100,711	)
	1,250 Bbls/d	Floor @ US$ 26.00/Bbl Ceiling @ US$ 27.50/Bbl	Oct 1, 2003 – Dec 31, 2003	US$ (243,594	)
	1,250 Bbls/d	US$ 31.25/Bbl	Nov 1, 2003 – Dec 31, 2003	US$ 7,275

At December 31, 2003, the Company had entered into the following contracts:

Exposure	Volume Hedged	Pricing	Term
Oil	1,250 Bbls/d	US$ 29.83/Bbl	January 1, 2004 – March 31, 2004
	1,250 Bbls/d	US$ 30.04/Bbl	January 1, 2004 – March 31, 2004
	1,250 Bbls/d	US$ 28.62/Bbl	April 1, 2004 – June 30, 2004
	1,250 Bbls/d	US$ 28.27/Bbl	April 1, 2004 – June 30, 2004
	1,250 Bbls/d	US$ 24.00/Bbl & cost of US$ 2.80/Bbl	July 1, 2004 – December 31, 2004
Foreign currency	US$ 700,000/month	1.345 Cdn$/US$	January 1, 2004 – June 30, 2004

11. RECONCILIATION OF THE CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

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

		Year Ended December 31, 2003			Period Ended December 31, 2002
		(thousands)			(thousands)
Consolidated net income as reported		$	11,198		$	4,035
Adjustments
	Depletion, depreciation and accretion^(b)		—			89
	Unrealized loss on derivative financial instruments^(d)		(3,728	)		—
	Future income tax effect on unrealized loss on derivative financial instruments^(d)		1,600			—
	Future tax expense on flow through shares^(e)		(4,224	)		—
	Future tax expenses — premium on flow through share issuance^(e)		(2,192	)		—
	Equity investment in Rock Energy^(g)		145			—
	Non-cash general and administrative expenses^(c)		(606	)		(279	)
	Net income under U.S. GAAP before cumulative effect of change in accounting policy	$	2,163		$	3,845

	Cumulative effect of change in accounting policy^(b)		89			—

	Net income under U.S. GAAP after cumulative effect of change in accounting policy	$	2,252		$	3,845

Basic
	Net income (loss) under U.S. GAAP before cumulative effect of change in accounting policy	$	0.07		$	0.13
	Cumulative effect of change in accounting policy^(b)		0.00			—

	Net income (loss) after the cumulative effect of change in accounting policy		0.08			0.13

Diluted
	Net income under U.S. GAAP before cumulative effect of change in accounting policy	$	0.07		$	0.13
	Cumulative effect of change in accounting policy^(b)		0.00			—

	Net income (loss) after the cumulative effect of change in accounting policy		0.08			0.13

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

			December 31, 2003				December 31, 2002
			Canadian GAAP		U.S. GAAP		Canadian GAAP		U.S. GAAP
			(thousands)				(thousands)
Assets
	Property and equipment^(b)			132,605		132,605		67,568		65,388
	Investment^(g)			2,810		2,955		—		—
Liabilities
	Commodity derivative contracts^(d)			—		3,728		—		—
		Future taxes^(b)(d)(e)		14,575		13,005		2,677		2,677
	Asset retirement obligation^(b)			8,875		8,875		2,288
	Provision for site restoration and abandonment^(b)			—		—		—		1,265
Shareholders' Equity
	Share capital^(e)			32,390		38,806		26,533		26,533
	Contributed surplus^(c)			85		691		—		278
	Retained earnings		$	16,300	$	7,265	$	5,102	$	3,667

(a): The Company 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 Company's risk free interest rate. For periods prior to January 1, 2004, the Company used undiscounted future net revenue from proved oil and natural gas reserves plus the cost of unproved properties less impairment, using period end prices. Under U.S. GAAP, entities using the full cost method of accounting for oil and natural gas activities perform a ceiling test on each cost centre using future net revenue from proved oil and natural gas reserves discounted at ten percent. The prices used under the U.S. GAAP ceiling tests are those in effect at period and year end. There was no adjustment required under application of U.S. GAAP.
(b): Effective January 1, 2004, the Company retroactively adopted the CICA Handbook standard for accounting for asset retirement obligations. This section is equivalent to Statement of Financial Accounting Standards ("FAS") 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): For Canadian GAAP purposes, the Company recognizes compensation expense using the fair value method for rights granted on or after January 1, 2003. For US GAAP purposes, the Company has accounted for all rights granted since inception using the fair value method of accounting. An adjustment to earnings has been recorded to reflect the associated additional compensation expense.
(d): The fair market value for derivative instruments used for hedging activities are not recorded within the financial statements under Canadian GAAP for the year ended December 31, 2003. There were no derivative instruments outstanding as of December 31, 2002. Under U.S. GAAP, FAS No. 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. If the derivative is designated a fair value hedge, the changes in the fair value of the derivative and the hedged item attributable to the hedged risk are recognized in income. If the derivative is designated a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income and are recognized in income when the hedged item is realized. Ineffective portions of change in fair value are recognized in income immediately. For a derivative designated as a cash flow hedge, U.S. GAAP requires that a company formally document, designate, and assess the effectiveness of derivative instruments that receive this accounting treatment. The Company had not formally documented and designated all hedging

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relationships for U.S. GAAP purposes as at December 31, 2003, and as such was not eligible for hedge accounting treatment under U.S. GAAP.

(e): Under U.S. GAAP flow-through shares are recorded at their fair value without any adjustment for the renouncement of the tax deductions, and any temporary difference resulting from the renouncement must be recognized in the determination of tax expense in the year incurred. U.S. GAAP also requires that the estimated cost of the tax deductions renounced be recorded as a future income tax liability. In addition, any proceeds received in excess of the quoted market value of the shares is recognized in the determination of income tax expense for the period.
(f): The Canadian GAAP liability method of accounting for income taxes is similar to the U.S. GAAP FAS No. 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 Company's consolidated financial statements. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates. There are no differences for the year ended December 31, 2003 or the period ended December 31, 2002.
(g): Under Canadian GAAP, the Company's interest in Rock Energy Inc. is recorded on a cost basis, as the ownership percentage is not significant and no influence is exercised in the direction of the company. Under U.S. GAAP, this investment is required to be accounted for on an equity basis due to the ownership percentage of the investment. An adjustment has been made in the financial statements to reflect the Company's interest in Rock Energy.
(h): 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 operating cash flow before changes in non-cash working capital items in the consolidated statement of cash flows. This total cannot be presented under U.S. GAAP. U.S. GAAP would require this statement to be a note to the financial statements.
(i): The following are standards and interpretations that have been issued by the Financial Accounting Standards Board ("FASB") and the Company has assessed the impact to be as follows:

Accounting for certain financial instruments with characteristics of both liabilities and equity

: In 2003, FASB issued FAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." FAS No. 150 establishes standards for the measurement and classification of certain financial instruments with characteristics of both liabilities and equity. FAS No. 150 is applicable to financial instruments entered into or modified after May 31, 2003, and otherwise effective at the beginning of the first interim period beginning after May 31, 2003. This standard did not have any impact on the Company.

Consolidation of Variable Interest Entities

: In 2003, FASB issued Interpretation Number 46R, "Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51." The standard mandates that variable interest entities be consolidated by their primary beneficiary. In Canada, the Accounting Standards Board (ACSB) has suspended the effective dates for the Canadian Institute of Chartered Accountants ("CICA") Handbook Accounting Guideline 15, "Consolidation of Variable Interest Entities" to amend the guideline to harmonize it with FAS Interpretation Number 46R. This will be effective for periods beginning after November 1, 2004. At December 31, 2002 and 2003, the Company did not have any variable interests in special purpose entities.

F-78

CONSENT OF PRICEWATERHOUSECOOPERS LLP

To: The Board of Directors of Harvest Operations Corp.

We have read the short form prospectus of Harvest Operations Corp. (the "Corporation") dated January 10, 2005, relating to the offer to exchange all outstanding US$250,000,000 7⁷/8% Senior Notes due 2011 Unconditionally Guaranteed by Harvest Energy Trust for US$250,000,000 7⁷/8% Senior Notes due 2011 Unconditionally Guaranteed by Harvest Energy Trust (the "Trust"). We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the use in the above-mentioned short form prospectus of our report dated July 16, 2004 to the Trustee of the Trust and the Board of Directors of the Corporation on the schedule of revenues, royalties and expenses of the New Properties for the two years ended December 31, 2003 and 2002.

Calgary, Canada		(Signed) PRICEWATERHOUSECOOPERS LLP
January 10, 2005		Chartered Accountants

F-79

AUDITORS' REPORT

To the Trustee of Harvest Energy Trust and Directors of Harvest Operations Corp.

At the request of Harvest Energy Trust and Harvest Operations Corp., we have audited the Schedule of Revenues, Royalties and Expenses for the two years ended December 31, 2003 and 2002 for the New Properties that Harvest Energy Trust and Harvest Operations Corp. have entered into an agreement to acquire dated July 15, 2004. This financial information is the responsibility of management. Our responsibility is to express an opinion on this financial information 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 information is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial information. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial information presentation.

In our opinion, the Schedule of Revenues, Royalties and Expenses presents fairly, in all material respects, the revenues, royalties and expenses for the New Properties for each of the years ended December 31, 2003 and 2002 in accordance with the basis of accounting disclosed in note 1.

Calgary, Canada		(Signed) PRICEWATERHOUSECOOPERS LLP
July 16, 2004, except for note 1 which is as of December 9, 2004		Chartered Accountants

F-80

NEW PROPERTIES

SCHEDULE OF REVENUES, ROYALTIES AND EXPENSES

($ thousands)

		Six Months Ended June 30,				Year Ended December 31,
		2004		2003		2003		2002
		(unaudited)
Revenues		$	135,246	$	153,692	$	280,642	$	233,878
Royalties			16,800		18,234		34,250		27,072

			118,446		135,458		246,392		206,806
Expenses
	Transportation		3,217		2,856		6,025		5,305
	Operating		21,435		22,422		45,397		44,854

Excess of revenues over expenses		$	93,794	$	110,180	$	194,970	$	156,647

See accompanying Notes to Schedule

F-81

NEW PROPERTIES

NOTES TO SCHEDULE OF REVENUES, ROYALTIES AND EXPENSES

For the Years Ended December 31, 2003 and 2002
and the Six Months Ended June 30, 2004 and 2003 (unaudited)
($ thousands)

1. BASIS OF PRESENTATION

The Schedule of Revenues, Royalties and Expenses includes the operating results relating to the New Properties that Harvest Energy Trust and Harvest Operations Corp. have acquired as of September 1, 2004. Under the terms of the agreement, Harvest Breeze Trust No. 1 and No. 2 acquired Breeze Resources Partnership which owns these New Properties ("the Properties").

The Properties consist of crude oil and natural gas assets located in the Crossfield area of Alberta, in southeast Alberta and in east central Alberta.

The Schedule of Revenues, Royalties and Expenses for the Properties does not include any provision for the depletion, depreciation and amortization, asset retirement costs, future capital costs, impairment of unevaluated properties, administrative costs and income taxes for the Properties as these amounts are based on the consolidated operations of the vendor of which the Properties form only a part.

This Schedule was prepared to comply with Canadian securities regulations and does not necessarily comply with U.S. regulations. Management believes there are no measurement or recognition differences under U.S. accounting standards for revenue, royalties, transportation expenses and operating expenses.

2. SIGNIFICANT ACCOUNTING POLICIES

(a) Joint Venture Operations

Substantially all of the Properties are operated through joint ventures therefore the schedule reflects only the vendor's proportionate interest.

(b) Revenue Recognition

Revenues are recorded when the product is delivered. Gas revenues are recorded based on AECO reference pricing used for sales between operating divisions of EnCana Corporation and do not reflect ultimate marketing related activities. Oil revenues are recorded based on blended prices established between operating divisions of EnCana Corporation for similar quality product delivered to a common carrier.

Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance with the applicable regulations and/or the terms of individual royalty agreements. Crown royalties for natural gas are based on the Alberta Government posted reference price. Crown royalties for crude oil are taken in kind by the Alberta Petroleum Marketing Commission.

(d) Transportation Expenses

Transportation expenses represent the costs incurred to deliver the product to market.

(e) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage.

F-82

UNAUDITED SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCTION ACTIVITIES

The following disclosures have been prepared in accordance with FASB Statement No. 69 "Disclosures about Oil and Gas Producing Activities" ("FAS 69"):

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

Canadian provincial royalties are determined based on a graduated percentage scale, which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Trust's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Trust's share of future production from Canadian reserves to be materially different from that presented. All of the Operating Subsidiaries' reserves are in Canada and, specifically, in the provinces of Alberta and Saskatchewan.

Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the constant prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of the Operating Subsidiaries' crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.

Subsequent to December 31, 2003 no major discovery or other unfavourable or adverse event is believed to have caused a material change in the estimate of proved or proved developed reserves as of that date. However, Harvests' December 31, 2004 reserves will be estimated, in accordance with FAS 69, using constant prices as at December 31, 2004. Heavy oil prices on that date reflect a significant negative differential to WTI and, as a result, Harvest's heavy oil reserves on that date may be subject to a significant negative revision as a result.

F-83

Results of Operations for Producing Activities

The following table sets forth revenue and direct cost information relating to the Trust's oil and gas producing activities, before hedging losses, for the year and period ended December 31:

		Year ended December 31, 2003		Period from July 10 (date of formation) to December 31, 2002
		(Cdn$ thousands)
Revenue		$	119,351	$	22,709
Royalty expense, net			16,412		2,745
Operating expenses
	Production costs		36,045		6,396
	Depletion, depreciation and accretion		35,570		6,169

	Results of operations from producing activities	$	31,324	$	7,399

Depletion rates per gross equivalent barrel		$	8.83	$	8.18

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Capitalized costs incurred in oil and gas producing activities for the year and period ended December 31 were as follows:

		Year ended December 31, 2003		Period from July 10 (date of formation) to December 31, 2002
		(Cdn$ thousands)
Property acquisition
	Proved	$	118,547	$	85,483
	Unproved		12,578		5,944

			131,125		91,427
Development costs			26,773		534

		$	157,898	$	91,961

Note:

Property acquisition costs related to acquisitions in 2003 for proved properties included $118.5 million; 2002 $85.5 million. Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties. Development costs include the costs of geological and geophysical activity, drilling and equipping development wells and facilities to extract, treat and gather and store oil and gas. Development costs also include administrative costs.

F-84

Capitalized Costs Relating to Oil and Gas Producing Activities

The capitalized costs and related accumulated depletion, depreciation and accretion, including impairments, relating to the Trust's oil and gas exploration, development and producing activities at December 31 consisted of:

Capitalized Costs

		Year ended December 31, 2003	Period ended December 31, 2002
		(Cdn$ thousands)
Properties
	Proved oil and gas properties	217,529	85,595
	Unproved oil and gas properties	32,175	6,211

		249,704	91,806
Less: Accumulated depletion, depreciation and accretion		39,608	5,877

Net capitalized costs		210,096	85,929

All costs are subject to depletion and depreciation.

Oil and Gas Reserve Information

The Trust's proved crude oil, natural gas liquids and natural gas reserves are located in the provinces of Alberta and Saskatchewan. The Trust's proved developed and undeveloped reserves after deductions of royalties are summarized below:

Reconciliation of Operating Subsidiaries Net Reserves by Principal Product Type
Constant Prices and Costs

Factors		Light and Medium Oil Net Proved (Mbbl)		Heavy Oil Net Proved (Mbbl)		Associated and Non-associated Natural Gas Net Proved (MMcf)		Natural Gas Liquids Net Proved (Mbbl)
July 10, 2002		—		—		—		—
Technical Revisions		827		1,443		264		7
Acquisitions		3,973		5,750		1,312		59
Production		(634	)	(1,164	)	(139	)	(4	)

December 31, 2002		4,166		6,029		1,437		62

December 31, 2002		4,166		6,029		1,437		62
Improved Recovery		—		589		—		—
Technical Revisions		579		1,181		(91	)	—
Acquisitions		17,546		284		760		71
Minor Revisions		(522	)	126		148		—
Production		(1,655	)	(1,677	)	(403	)	(19	)

December 31, 2003		20,114		6,532		1,851		114

December 31, 2002:
	Proved Developed Reserves	3,556		5,146		1,358		52
	Proved Undeveloped Reserves	610		883		79		10
December 31, 2003:
	Proved Developed Reserves	19,114		6,327		1,783		107
	Proved Undeveloped Reserves	1,000		205		68		7

F-85

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by FAS 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of the Trust. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Trust or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Trust's reserves.

The future cash flows presented below are based on sales prices and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2003 was based on the crude oil prices computed with reference to the year-end WTI price of US$32.78/bbl (2002 — US$31.23/bbl) and on Alberta AECO year-end natural gas spot price of $5.87/mmbtu (2002 — $5.20/mmbtu). The prices of WTI and natural gas in Canadian dollars were lower at December 31, 2003 than at December 31, 2002 as a result of the Cdn./ U.S. dollar exchange rate, which was $1.29 at December 31, 2003 compared with $1.58 at December 31, 2002.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Trust's proved crude oil and natural gas reserves at December 31, for the years presented:

Standardized Measure

		Year ended December 31, 2003	Period from July 10 (date of formation) to December 31, 2002
		(Cdn$ thousands)
Future cash inflows		832,704	379,356
Future costs
	Future production and development costs	519,427	127,690
	Future income taxes	—	—

Future net cash flows		313,277	251,666
Deduct: 10% annual discount factor		69,014	47,752

Standardized measure of discounted future net cash flows		244,263	203,914

Note:

The above schedule is calculated using year end prices, costs and existing proved oil and natural gas reserves. The value of probable reserves and future changes in oil and natural gas prices and in production and development costs are excluded.

F-86

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the year and period presented.

Period and Factor

	2003		2002
	($000)		($000)
Estimated Future Net Revenue at Beginning of Period	203,914		—
Sales and Transfers of Oil and Natural Gas Produced, Net of Production Costs and Royalties	(66,894	)	(13,568	)
Net Change in Prices, Production Costs and Royalties Related to Future Production	(73,792	)	68,961
Development Costs During the Period	26,773		534
Changes in Forecast Development Costs	(5,391	)	2,827
Extensions and Improved Recovery	2,442		—
Discoveries	—		—
Acquisitions of Reserves	131,125		121,619
Dispositions of Reserves	—		(155	)
Net Change Resulting from Revisions in Quantity Estimates	5,695		23,696
Accretion of Discount	20,391		—
Net Change in Income Taxes	—		—
Estimated Future Net Revenue at End of Period	244,263		203,914

Note:

The schedules above are calculated using year-end prices, costs and existing proved oil and natural gas reserves. The value of probable reserves, future changes in oil and gas prices and in production and development costs are excluded.

F-87

PART II

INFORMATION NOT REQUIRED TO BE DELIVERED
TO OFFEREES OR PURCHASERS

Indemnification

Under the Business Corporations Act (Alberta) (the "ABCA"), each of Harvest Operations Corp., 115638 Alberta Ltd., 1115650 Alberta Ltd., and Redearth Energy, Inc. (each a "Corporation" and collectively, the "Corporations") may indemnify a present or former director or officer or a person who acts or acted at the Corporation's request as a director or officer of a body corporate of which the Corporation is or was a shareholder or creditor, and his heirs and legal representatives, against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by him in respect of any civil, criminal or administrative action or proceeding to which he is made a party by reason of being or having been a director or officer of the Corporation or that body corporate, if the director or officer acted honestly and in good faith with a view to the best interests of the Corporation, and, in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, had reasonable grounds for believing that his conduct was lawful. Such indemnification may be in connection with a derivative action only with court approval. A director or officer is entitled to indemnification from the Corporation as a matter of right if he or she was substantially successful on the merits, fulfilled the conditions set forth above, and is fairly and reasonably entitled to indemnity.

The by-laws of each of the Corporations provide that the Corporation shall indemnify a present or former director or officer or a person who acts or acted at the Corporation's request as a director or officer of a body corporate of which the Corporation is or was a shareholder or creditor, and his heirs and legal representatives, against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by him in respect of any civil, criminal or administrative action or proceeding to which he is made a party by reason of his position with the Corporation of that body corporate and provided that the director or officer acted honestly and in good faith with a view to the best interests of the Corporation and in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, had reasonable grounds for believing that his conduct was lawful.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers or persons controlling the Registrant pursuant to the foregoing provisions, the Registrant has been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is therefore unenforceable.

EXHIBITS

Exhibit Number		Description
3.1*		Purchase Agreement dated October 7, 2004 by and among Harvest Operations Corp., Harvest Energy Trust, the Subsidiary Guarantors identified therein and the Initial Purchasers identified therein.
3.2*		Registration Rights Agreement dated as of October 14, 2004 by and among Harvest Operations Corp., Harvest Energy Trust, the Subsidiary Guarantors identified therein and the Initial Purchasers identified therein.
4.1*		The Annual Information Form of Harvest Energy Trust dated April 30, 2004 for the year ended December 31, 2003, excluding (i) the Schedule of Revenue and Expenses for certain of the Provost Properties Acquired from Devon Canada Corporation for the Years Ended December 31, 2001, 2000 and 1999 and Six Months Ended June 30, 2002 and 2001; (ii) the Schedule of Revenue and Expenses for certain of the Provost Properties Acquired from Anadarko Canada Corporation for the Years Ended December 31, 2001, 2000 and 1999 and Six Months Ended June 30, 2002 and 2001; and (iii) the Pro Forma Consolidated Financial Statements of Harvest Energy Trust as at and for the Year Ended December 31, 2003.
4.2*		The Information Circular — of Harvest Energy Trust dated May 12, 2004, relating to the annual and special meeting of unitholders held on June 22, 2004, excluding those portions thereof which appear under the headings "Performance Chart" and "Corporate Governance".
4.3*		The Material Change Report of Harvest Energy Trust dated July 8, 2004, relating to the acquisition of Storm Energy Ltd.
4.4*		The Material Change Report of Harvest Energy Trust dated July 23, 2004, relating to the acquisition of Breeze Resources Partnership.
4.5*		The Material Change Report of Harvest Energy Trust dated October 22, 2004, relating to the private placement of U.S.$250,000,000 of 7⁷/8% senior notes due 2011.
5.1		Consent of McDaniel & Associates Consultants Ltd.
5.2		Consent of Paddock, Lindstrom and Associates, Ltd.
5.3		Consent of Gilbert Laustsen Jung Associates Ltd.
5.4		Consent of KPMG LLP.
5.5		Acknowledgement Letter of KPMG LLP.
5.6		Consent of Deloitte & Touche LLP.
5.7		Consent of PricewaterhouseCoopers LLP.
5.8*		Consent of Burnet Duckworth & Palmer LLP.
5.9*		Consent of Paul, Weiss, Rifkind, Wharton & Garrison LLP.
6.1*		Powers of Attorney (included on the signature page hereto).
7.1*		Indenture dated as of October 14, 2004 by and among Harvest Operations Corp., Harvest Energy Trust, the Subsidiary Guarantors identified therein and U.S. Bank National Association.
7.2*		Statement of Eligibility of the Trustee on Form T-1.
99.1*		Letter of Transmittal.
99.2*		Notice of Guaranteed Delivery.
99.3*		Instruction to Registered Holder from the Beneficial Owner.

*Previously filed

PART III

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Item 1. Undertaking

Each of the Registrants undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities registered pursuant to Form F-10 or to transactions in said securities.

Item 2. Consent to Service of Process

Concurrent with the filing of this Registration Statement, the Registrants have each filed with the Commission a written irrevocable consent and power of attorney on Form F-X.

Any change to the name or address of the agent for service of process of the Registrants shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrants certify that they have reasonable grounds to believe that they meet all of the requirements for filing on Form F-10 and have duly caused this registration statement to be signed on their behalf by the undersigned, thereunto duly authorized, in the City of Calgary in the Province of Alberta, Canada, on January 10, 2005.

		HARVEST OPERATIONS CORP.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Vice President, Chief Financial Officer and Corporate Secretary
		HARVEST ENERGY TRUST by Harvest Operations Corp.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Vice President, Chief Financial Officer and Corporate Secretary
		HARVEST SASK ENERGY TRUST by 115650 Alberta Ltd.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Secretary
		HARVEST BREEZE TRUST NO. 1 by 115638 Alberta Ltd.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Secretary
		HARVEST BREEZE TRUST NO. 2 by 115650 Alberta Ltd.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Secretary

		BREEZE RESOURCES PARTNERSHIP by 115650 Alberta Ltd.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Secretary
		REDEARTH ENERGY INC.
		By:	/s/ JACOB ROORDA
		Name: Jacob Roorda Title: President
		1115638 ALBERTA LTD.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Secretary
		1115650 ALBERTA LTD.
		By:	/s/ DAVID J. RAIN
		Name: David J. Rain Title: Secretary

SIGNATURES WITH RESPECT TO HARVEST OPERATIONS CORP.