FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

March ~~9th~~31 st, 2010

Commission File Number: 333-121627

HARVEST ENERGY TRUST

(Exact name of registrant as specified in its charter)

Suite 2100, 330 - 5th Avenue S.W,

Calgary, Alberta, Canada T2P 0L4

(403) 265-1178

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F X x Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1). __

Note: Regulation S-T Rule 101(b)(1) only permits the submission in paper of a Form 6-K if submitted solely to provide an attached annual report to security holders.

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Note: Regulation S-T Rule 101(b)(7) only permits the submission in paper of a Form 6-K if submitted to furnish a report or other document that the registrant foreign private issuer must furnish and make public under the laws of the jurisdiction in which the registrant is incorporated, domiciled or legally organized (the registrant’s "home country"), or under the rules of the home country exchange on which the registrant’s securities are traded, as long as the report or other document is not a press release, is not required to be and has not been distributed to the registrant’s security holders, and, if discussing a material event, has already been the subject of a Form 6-K submission or other Commission filing on EDGAR.

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No X x

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

EXHIBIT	~~TITLE~~	TITLE
1	~~Audited Annual Financial Statements for 2009 filed on SEDAR March 8, 2010.~~	Material Document – Amending Agreement to the Amended and restated Credit Agreement dated December 21, 2009 filed on SEDAR March 30, 2010.
2	~~Management’s Discussion and Analysis for 2009 filed on SEDAR March 8, 2010.~~	Material Document – Supply and Offtake Agreement dated October 19, 2006 filed on SEDAR March 30, 2010.
3	~~News release dated March 8, 2010 announcing fourth quarter and full year 2009 financial and operating results filed on SEDAR March 8, 2010.~~	Annual Information Form filed on SEDAR March 30, 2010.
4	~~News release dated March 8, 2010 announcing year end 2009 reserves filed on SEDAR March 8, 2010.~~	News release dated March 30, 2010 announcing filing of 2009 Annual Information Form filed on SEDAR March 30, 2010.
5	~~CEO certification of annual filings of Harvest Energy Trust, dated March 5, 2010 filed on SEDAR March 8, 2010.~~	CEO certification of annual filings of Harvest Energy Trust, dated March 30, 2010 filed on SEDAR March 30, 2010.
6	~~CFO certification of annual filings of Harvest Energy Trust, dated March 5, 2010 filed on SEDAR March 8, 2010.~~	CFO certification of annual filings of Harvest Energy Trust, dated March 30, 2010 filed on SEDAR March 30, 2010.
7	~~ON Form 13-502F1 Participation Fee filed on SEDAR March 8, 2010.~~	Securityholders Documents – First, Second and Third Supplemental Trust Indentures as of December 22, 2009 filed on SEDAR March 30, 2010.
8		Securityholders Documents – Certificate of Amalgamation as of January 1, 2010 filed on SEDAR March 30, 2010.
9		Securityholders Documents – By-Laws of Harvest Operations Corp. dated December 22, 2009 filed on SEDAR March 30, 2010.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	HARVEST ENERGY TRUST
	(Registrant)
Date: March 9th, 2010	By:	<<signed>>
Date: March 31 st, 2010	By:	/S/ John Zahary
		John Zahary
		President & Chief Executive Officer

INDEX TO EXHIBITS

EXHIBIT	~~TITLE~~	TITLE
1	~~Audited Annual Financial Statements for 2009 filed on SEDAR March 8, 2010.~~	Material Document – Amending Agreement to the Amended and restated Credit Agreement dated December 21, 2009 filed on SEDAR March 30, 2010.
2	~~Management’s Discussion and Analysis for 2009 filed on SEDAR March 8, 2010.~~	Material Document – Supply and Offtake Agreement dated October 19, 2006 filed on SEDAR March 30, 2010.
3	~~News release dated March 8, 2010 announcing fourth quarter and full year 2009 financial and operating results filed on SEDAR March 8, 2010.~~	Annual Information Form filed on SEDAR March 30, 2010.
4	~~News release dated March 8, 2010 announcing year end 2009 reserves filed on SEDAR March 8, 2010.~~	News release dated March 30, 2010 announcing filing of 2009 Annual Information Form filed on SEDAR March 30, 2010.
5	~~CEO certification of annual filings of Harvest Energy Trust, dated March 5, 2010 filed on SEDAR March 8, 2010.~~	CEO certification of annual filings of Harvest Energy Trust, dated March 30, 2010 filed on SEDAR March 30, 2010.
6	~~CFO certification of annual filings of Harvest Energy Trust, dated March 5, 2010 filed on SEDAR March 8, 2010.~~	CFO certification of annual filings of Harvest Energy Trust, dated March 30, 2010 filed on SEDAR March 30, 2010.
7	~~ON Form 13-502F1 Participation Fee filed on SEDAR March 8, 2010.~~	Securityholders Documents – First, Second and Third Supplemental Trust Indentures as of December 22, 2009 filed on SEDAR March 30, 2010.
8		Securityholders Documents – Certificate of Amalgamation as of January 1, 2010 filed on SEDAR March 30, 2010.
9		Securityholders Documents – By-Laws of Harvest Operations Corp. dated December 22, 2009 filed on SEDAR March 30, 2010.

ANNUAL INFORMATION FORM

For the year ended December 31, 2009

MARCH 30, 2010

TABLE OF CONTENTS

	Page

GLOSSARY OF TERMS	2
ABBREVIATIONS	7
CONVERSIONS	7
EXCHANGE RATE INFORMATION	8
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	8
NON-GAAP MEASURES	10
STRUCTURE OF HARVEST ENERGY TRUST	11
GENERAL DEVELOPMENT OF THE BUSINESS	13
GENERAL BUSINESS DESCRIPTION	16
UPSTREAM BUSINESS STATEMENT OF RESERVES DATA	18
OTHER UPSTREAM BUSINESS INFORMATION	29
DOWNSTREAM BUSINESS	43
RISK FACTORS	50
INTEREST PAID TO HOLDERS OF CONVERTIBLE DEBENTURES	59
GENERAL DESCRIPTION OF CAPITAL STRUCTURE	59
SUPPLEMENTAL CAPITAL STRUCTURE INFORMATION	65
MARKET FOR SECURITIES	67
DIRECTORS AND OFFICERS OF HARVEST OPERATIONS	71
EXECUTIVE COMPENSATION	74
CORPORATE GOVERNANCE DISCLOSURE	81
CONFLICTS OF INTEREST	88
LEGAL AND REGULATORY PROCEEDINGS	88
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	89
AUDITORS	89
TRANSFER AGENT AND REGISTRAR	89
MATERIAL CONTRACTS	89
INTERESTS OF EXPERTS	90
ADDITIONAL INFORMATION	90

Appendix A - Report of Management and Directors on Reserves Data and Other Information

Appendix B - Report on Reserves Data by Independent Qualified Reserves Evaluators

Appendix C - Audit Committee Information

Appendix D - Audit Committee Mandate and Terms of Reference

Appendix E – Mandate of the Harvest Board of Directors

GLOSSARY OF TERMS

In this Annual Information Form, the following terms shall have the meanings set forth below, unless otherwise indicated.

" ABCA" means the Business Corporations Act (Alberta), together with any or all regulations promulgated thereunder, as amended from time to time.

" Administration Agreement" means the agreement dated September 27, 2002 between the Trustee and Harvest Operations pursuant to which Harvest Operations provides certain administrative and advisory services in connection with the Trust.

“API” means a measure of the gravity or density of petroleum liquids expressed in terms of a scale devised by the American Petroleum Institute gravity (API), which measures how heavy or light a petroleum liquid is compared to water, and is used to compare the relative densities of petroleum liquids.

" Breeze Trust No. 1" means Harvest Breeze Trust No. 1, a trust established under the laws of the Province of Alberta, wholly owned by the Trust.

" Breeze Trust No. 2" means Harvest Breeze Trust No. 2, a trust established under the laws of the Province of Alberta, wholly owned by the Trust.

" COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum.

" Credit Facility" means the $600 million credit facility provided by a syndicate of lenders to Harvest Operations as more fully described in Note 11 to the Trust’s audited consolidated financial statements for the year ended December 31, 2009 filed on www.sedar.com.

" Debentures" means, collectively, the 6.5% Debentures Due 2010, the 6.40% Debentures Due 2012, the 7.25% Debentures Due 2013, the 7.25% Debentures Due 2014 and the 7.5% Debentures Due 2015.

" Debenture Indenture" means, collectively (i) the trust indenture dated January 29, 2004 among the Trust, Harvest Operations and Valiant Trust Company, as trustee, providing for the issue of debentures, as supplemented by the, second supplemental indenture dated August 2, 2005 in respect of the 6.50% Debentures Due 2010, the third supplemental indenture dated November 22, 2006 in respect of the 7.25% Debentures Due 2013, the fourth supplemental indenture dated February 1, 2007 in respect of the 7.25% Debentures Due 2014 and the fifth supplemental indenture dated April 25, 2008 in respect of the 7.50% Debentures Due 2015; and (ii) the trust indenture dated January 15, 2003 between VERT and Computershare Trust Company of Canada as trustee, providing for the issue of debentures, as supplemented by the first supplemental indenture dated October 20, 2005 in respect of the 6.40% Debentures Due 2012.

" Debenture Trustee" means, as applicable: (i) Valiant Trust Company in its capacity as the trustee in respect of the 6.5% Debentures Due 2010, 7.25% Debentures Due 2013, 7.25% Debentures Due 2014, and 7.5% Debentures Due 2015; and (ii) Computershare Trust Company of Canada in its capacity as the trustee in respect of the 6.40% Debentures Due 2012.

" 6.5% Debentures Due 2010" means the 6.5% convertible unsecured subordinated debentures of the Trust due December 31, 2010.

" 6.40% Debentures Due 2012" means the 6.40% convertible unsecured subordinated debentures of the Trust due October 31, 2012, which were assumed by the Trust from VERT on February 3, 2006 pursuant to the plan of arrangement under the ABCA by which the Trust merged with VERT.

" 7.25% Debentures Due 2013" means the 7.25% convertible unsecured subordinated debentures of the Trust due September 30, 2013.

" 7.25% Debentures Due 2014" means the 7.25% convertible unsecured subordinated debentures of the Trust due February 28, 2014.

" 7.50% Debentures Due 2015" means the 7.50% convertible unsecured subordinated debentures of the Trust due May 31, 2015.

" 7⅞% Senior Notes" means the 7⅞% Senior Notes of Harvest Operations due October 15, 2011 unconditionally guaranteed by the Trust.

" Downstream" means our petroleum refining and marketing segment operating under the North Atlantic trade name, comprised of a medium gravity sour crude hydrocracking refinery with a 115,000 bbls/d nameplate capacity and a marketing division with 64 gasoline outlets, a retail heating fuels business and a commercial and wholesale petroleum products business, all located in the Province of Newfoundland and Labrador.

" Farmout" means an agreement whereby a third party agrees to pay for all or a portion of the drilling of a well on one or more of the Properties in order to earn an interest therein, with an Operating Subsidiary retaining a residual interest in such Properties.

" GLJ" means GLJ Petroleum Consultants Ltd., independent oil and natural gas reservoir engineers of Calgary, Alberta.

" GAAP" means accounting principles generally accepted in Canada.

" Gross" means:

(a)

in relation to the Operating Subsidiaries' interest in production and reserves, its "Corporation gross reserves", which are the Operating Subsidiaries' interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Operating Subsidiaries;

(b)

in relation to wells, the total number of wells in which the Operating Subsidiaries have an interest; and

(c)

in relation to properties, the total area of properties in which the Operating Subsidiaries have an interest.

" Harvest" means, collectively, the Trust and its subsidiary corporations, trusts and partnerships.

"Harvest Board" means the board of directors of Harvest Operations.

" Harvest Operations" means Harvest Operations Corp., a corporation incorporated under the laws of the Province of Alberta and a wholly owned subsidiary of the Trust, which serves as administrator of the Trust pursuant to the Administration Agreement.

" HRGP" means Harvest Refining General Partnership, a general partnership established under the laws of the Province of Alberta.

" Independent Reserve Engineering Evaluators" means McDaniel and GLJ, who evaluated the crude oil, natural gas liquids and natural gas reserves of the Operating Subsidiaries as at December 31, 2009, in accordance with the standards contained in the COGE Handbook and the reserve definitions and other requirements contained in NI 51-101.

" KNOC" means Korea National Oil Corporation.

" KNOC Arrangement" means the plan of arrangement implemented pursuant to Section 193 of the ABCA involving, among others, Harvest, Harvest Operations, KNOC Canada, KNOC and the holders of Trust Units, which became effective on December 22, 2009.

" KNOC Canada" means KNOC Canada Ltd., a corporation incorporated under the laws of the Province of Alberta and a wholly owned subsidiary of KNOC.

" McDaniel" means McDaniel & Associates Consultants Ltd., independent oil and natural gas reservoir engineers of Calgary, Alberta.

" Net" means:

(a)

in relation to the Operating Subsidiaries' interest in production and reserves, the Operating Subsidiaries' interest (operating and non-operating) share after deduction of royalties obligations, plus the Operating Subsidiaries' royalty interest in production or reserves;

(b)

in relation to wells, the number of wells obtained by aggregating the Operating Subsidiaries' working interest in each of its gross wells; and

(c)

in relation to the Operating Subsidiaries' interest in a property, the total area in which the Operating Subsidiaries have an interest multiplied by the working interest owned by the Operating Subsidiaries.

" NI 51-101" means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

" North Atlantic" means North Atlantic Refining Limited, a private company, and all wholly owned subsidiaries of North Atlantic.

" NYSE" means the New York Stock Exchange.

" Operating Subsidiaries" means, collectively, Harvest Operations, Redearth Partnership, Breeze Resource Partnership, Breeze Trust No. 1, Breeze Trust No. 2, Hay River Partnership, and HRGP (and all direct and indirect wholly-owned subsidiaries of HRGP), each a direct or indirect wholly-owned subsidiary of the Trust other than Redearth Partnership in respect of which the Trust, indirectly, holds a 60% interest, and "Operating Subsidiary" means any of them.

" Person" includes an individual, a body corporate, a trust, a union, a pension fund, a government and a governmental agency.

" Production" means, with respect to the Upstream operations the produced petroleum, natural gas and natural gas liquids attributed to the Properties and with respect to the Downstream operations, the production of refined petroleum products at the Refinery.

" Properties" means the working, royalty or other interests of the Operating Subsidiaries in any petroleum and natural gas rights, tangibles and miscellaneous interests, including properties which may be acquired by the Operating Subsidiaries from time to time.

" Purchase and Sale Agreement" means the purchase and sale agreement dated August 22, 2006 between the Trust and Vitol Refining Group B.V. providing for the purchase of the outstanding shares of North Atlantic and the entering into of the Supply and Offtake Agreement.

" Refinery" means the 115,000 barrel per day medium gravity sour crude hydrocracking refinery located in the Province of Newfoundland and Labrador, owned by North Atlantic, which is described in "Downstream Business".

" Reserve Report" means, collectively, the reports prepared by the Independent Reserve Engineering Evaluators evaluating the crude oil, natural gas liquids and natural gas reserves of the Operating Subsidiaries as at December 31, 2009, in accordance with the standards contained in the COGE Handbook and the reserve definitions and other requirements contained in NI 51-101.

" Reserve Value" means, for any petroleum and natural gas property at any time, the present worth of all of the estimated pre-tax cash flow net of capital expenditures from the proved plus probable reserves shown in the Reserve Report for such property, discounted at 10% and using forecast price and cost assumptions (a common benchmark in the oil and natural gas industry).

" Special Resolution" means a resolution proposed to be passed as a special resolution at a meeting of Unitholders (including an adjourned meeting) duly convened for the purpose and held in accordance with the provisions of the Trust Indenture at which two or more holders of at least 10% of the aggregate number of Trust Units then outstanding are present in person or by proxy and passed by the affirmative votes of the holders of not less than 66 2/3% of the Trust Units represented at the meeting and voted on a poll upon such resolution.

" Supply and Offtake Agreement" or " SOA" means the supply and offtake agreement dated October 19, 2006 and as amended October 12, 2009 entered into between North Atlantic and Vitol Refining, S.A., the terms of which are summarized under the "Downstream Business – Supply and Offtake Agreement".

" Tax Act" means the Income Tax Act (Canada) and the regulations thereunder.

" Trust" means Harvest Energy Trust.

" Trust Fund" at any time, shall mean those monies, properties and assets of the type contemplated in the Trust Indenture that are at such time held by the Trustee on behalf of the Trust for the purposes of the Trust under the Trust Indenture.

" Trust Indenture" means the fifth amended and restated trust indenture dated May 20, 2008 between the Trustee and Harvest Operations, as amended on December 22, 2009 pursuant to the KNOC Arrangement, as such indenture may be further amended by supplemental indentures from time to time.

" Trust Unit" means a trust unit of the Trust and unless the context otherwise requires means ordinary trust units of the Trust.

" Trust Unit Rights" means the rights to purchase Trust Units at specified exercise prices issued by the Trust under the Trust Unit Rights Incentive Plan.

" Trust Unit Rights Incentive Plan" means the former trust unit rights incentive plan of the Trust, which ceased to be effective following completion of the KNOC Arrangement.

" Trustee" means 1496965 Alberta Ltd. (a wholly-owned subsidiary of KNOC Canada), or its successor as trustee of the Trust.

" TSX" means the Toronto Stock Exchange.

" Unit Awards" means unit awards to receive Trust Units, issued by the Trust under the Unit Award Incentive Plan.

" Unit Award Incentive Plan" means the former unit award incentive plan of the Trust, which ceased to be effective following the KNOC Arrangement.

" Unitholders" means the holders from time to time of one or more Trust Units.

" Upstream" means our petroleum and natural gas segment, consisting of the development, production and subsequent sale of petroleum, natural gas and natural gas liquids in Alberta, Saskatchewan and British Columbia.

" VERT" means Viking Energy Royalty Trust, a trust established under the laws of the Province of Alberta, wholly owned by the Trust.

" VHI" means Viking Holdings Inc., a corporation incorporated under the laws of the Province of Alberta that formerly acted as administrator of VERT, which amalgamated with Harvest Operations on July 1, 2006.

" Working Interest" means an undivided interest held by a party in an oil and/or natural gas or mineral lease granted by a Crown or freehold mineral owner, which interest gives the holder the right to "work" the property (lease) to explore for, develop, produce and market the lease substances but does not include, among other things, a royalty, overriding royalty, gross overriding royalty, net profits interest or other interest that entitles the holder thereof to a share of production or proceeds of sale of production without a corresponding right or obligation to "work" the property.

Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas

bbl	barrel	Mcf	thousand cubic feet
bbls	barrels	MMcf	million cubic feet
Mbbls	thousand barrels	Bcf	billion cubic feet
bbls/d	barrels per day	Mcf/d	thousand cubic feet per day
MMbbls	million barrels	MMcf/d	million cubic feet per day
NGLs	natural gas liquids	MMBTU	million British Thermal Units

Other

AECO	Carlyle/Riverstone Global Energy and Power Fund’s natural gas storage facility located at Suffield, Alberta.
ASP	alkaline surfactant polymer.
BOE	barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one bbl of oil, unless otherwise specified. 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.
BOE/d	barrels of oil equivalent per day.
EOR	enhanced oil recovery.
MBOE	thousand barrels of oil equivalent.
MMBOE	million barrels of oil equivalent.
OOIP	original oil in place.
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade.
API	The measure of the density or gravity of liquid petroleum products derived from a specific gravity.
MW	megawatts of electrical power.
3D	three dimensional.
Darcies	the measure of permeability (being the ease with which a single fluid will flow through connected pore space when a pressure gradient is applied).
Porosity	The measure of the fraction of pore space of a reservoir.
$000	thousands of dollars.
$millions	millions of dollars.

CONVERSIONS

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By

Mcf	cubic metres		28.174
cubic metres	cubic feet		35.494
bbls	cubic metres		0.159
feet	metres		0.305
metres	feet		3.281
miles	kilometres		1.609
kilometres	miles		0.621
acres	hectares		0.405
hectares	acres		2.471

EXCHANGE RATE INFORMATION

All dollar amounts set forth in this Annual Information Form are expressed in Canadian dollars, except where otherwise indicated. References to Canadian dollars, Cdn$, C$ or $ are to the currency of Canada and references to U.S. dollars or US$ are to the currency of the United States.

The following table sets forth for each period indicated, the average, high, low and end of period noon buying rates in New York for cable transfers as certified for customs purposes by the Federal Reserve Bank of New York (the "noon buying rate"). Such rates are set forth as U.S. dollars per $1.00 and are the inverse of the rates quoted by the Federal Reserve Bank of New York for Canadian dollars per US$1.00.

	Year Ended December 31,
	2009		2008		2007
High		0.9716		1.0289		1.0905
Low		0.7692		0.7711		0.8437
Period End		0.9555		0.8166		1.0120
Average (1)		0.8706		0.9332		0.9376

Note:

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this Annual Information Form and documents incorporated by reference herein, constitute forward-looking statements. These statements relate to future events and future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those included in the forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. Harvest Operations believes the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be.

In particular, this Annual Information Form, and the documents incorporated by reference herein, contain forward-looking statements pertaining to:

·	expected financial performance in future periods;

·	expected increases in revenue attributable to development and production activities;

·	estimated capital expenditures;

·	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 cash flows to repay indebtedness and invest in further development of our properties;

·	reserve estimates and estimates of the present value of our future net cash flows;

·	methods of raising capital for exploitation and development of reserves;

·	factors upon which to decide 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 petroleum and natural gas properties;

·	treatment under government regulatory regimes including without limitation, environmental and tax regulation;

·	overall demand for gasoline, low sulphur diesel, jet fuel, furnace oil and other refined products; and

·	the level of global production of crude oil feedstocks and refined products.

With respect to forward-looking statements contained in this Annual Information Form and the documents incorporate by reference herein, 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 Harvest's property holdings;

·	the ability to obtain equipment in a timely manner to carry out development activities;

·	the ability to market oil and natural gas successfully to current and new customers;

·	the impact of increasing competition;

·	the ability to obtain financing on acceptable terms;

·	the ability to add production and reserves through development and exploitation activities; and

·	the ability to produce gasoline, low sulphur diesel, jet fuel, furnace oil, and other refined products that meet customer specifications.

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

·	the volatility of oil and natural gas prices, including the differential between the price of light, medium and heavy oil;

·	the uncertainty of estimates of petroleum and natural gas reserves;

·	the impact of competition;

·	difficulties encountered in the integration of acquisitions;

·	difficulties encountered during the drilling for and production of oil and natural gas;

·	difficulties encountered in delivering oil and natural gas to commercial markets;

·	foreign currency fluctuations;

·	the uncertainty of Harvest's ability to attract capital;

·	changes in, or the introduction of new, government laws and regulations relating to the oil and natural gas business including without limitation, tax, royalty and environmental law and regulation;

·	costs associated with developing and producing oil and natural gas;

·	compliance with environmental and tax regulations;

·	liabilities stemming from accidental damage to the environment;

·	loss of the services of any of Harvest's senior management or directors;

·	adverse changes in the economy generally;

·	the volatility of refining gross margins including the price of feedstocks as well as the prices for refined products; and

·	the stability of the Refinery throughput performance.

Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward- looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Except as required by law, neither the Trust nor Harvest Operations undertakes any obligation to publicly update or revise any forward-looking statements and readers should also carefully consider the matters discussed under the heading "Risk Factors" in this Annual Information Form.

NON-GAAP MEASURES

Harvest uses certain financial reporting measures that are commonly used as benchmarks within the petroleum and natural gas industry. These measures include: "Payout Ratio", "Cash G&A", "Operating Netbacks", "Earnings from Operations" and "Gross Margin". These measures are not defined under Canadian generally accepted accounting principles and should not be considered in isolation or as an alternative to conventional Canadian GAAP measures. Certain of these measures are not necessarily comparable to a similarly titled measure of another company or trust. When these measures are used, they have been footnoted and the footnote to the applicable measure notes that the measure is "non-GAAP" and contains a description of how to reconcile the measure to the applicable financial statements. These measures should be given careful consideration by the reader.

Specifically, management uses “Payout Ratio”, “Cash G&A” and “Operating Netbacks” as they are non-GAAP measures used extensively in the Canadian energy trust sector for comparative purposes. Payout Ratio is the ratio of distributions to total Cash from Operating Activities. Operating Netbacks are always reported on a per BOE basis, and include gross revenue, royalties, transportation and operating expenses. Cash G&A are G&A expenses, excluding the effect of unit based compensation plans. “Gross Margin” is also a non-GAAP measure commonly used in the refining industry to reflect the net cash received from the sale of refined product after considering the cost to purchase the feedstock and is calculated by deducting purchased products for resale and processing from total revenue. “Earnings from Operations” is also a non-GAAP measure commonly used in the petroleum and natural gas and in the refining and marketing industries to reflect operating results before items not directly related to operations.

Unless otherwise specified, information in this Annual Information Form is as at the end of the Trust's most recently completed financial year, being the year ended December 31, 2009.

STRUCTURE OF HARVEST ENERGY TRUST

Harvest Energy Trust

Harvest Energy Trust (the “Trust”) is an open-ended, unincorporated investment trust established under the laws of the Province of Alberta and is governed pursuant to the Amended and Restated Trust Indenture dated December 22, 2009 between Harvest Operations Corp. (“Harvest Operations”), a wholly owned subsidiary and manager of the Trust, and 1496965 Alberta Ltd. as Trustee (the “Trust Indenture”). The beneficiary of the Trust is the holder of its Trust Units (the “Unitholder”). On December 22, 2009, Korea National Oil Corporation Canada Ltd. (“KNOC Canada”), a wholly owned subsidiary Korea National Oil Corporation (“KNOC”), purchased all of the issued and outstanding Trust Units of the Trust.

It is expected that Harvest will reorganize its structure in 2010 so as to, effectively convert from an investment trust issuer to a corporate issuer. The reorganization is anticipated to result in Harvest Operations becoming the parent entity of the remaining Operating Subsidiaries.

The head and principal office of the Trust and Harvest Operations is located at Suite 2100, 330 - 5th Avenue S.W., Calgary, Alberta T2P 0L4 while the registered office of Harvest Operations is located at Suite 4500, Bankers Hall East 855 – 2 nd Street S.W., Calgary, Alberta T2P 4K7.

The business of Harvest is to, indirectly through Harvest Operations and its other Operating Subsidiaries, exploit, develop and hold interests in petroleum and natural gas properties in its upstream segment as well as conduct petroleum refining and marketing operations in its downstream segment.

Operating Subsidiaries

Each of the subsidiary entities identified below is a direct or indirect wholly-owned subsidiary of the Trust other than Redearth Partnership, in respect of which the Trust indirectly holds a 60% interest.

Harvest Operations, a taxable corporation

Harvest Operations was incorporated under the ABCA on May 14, 2002. Subsequently, Harvest Operations has been amalgamated with numerous corporate subsidiaries of Harvest and continued in each case as "Harvest Operations Corp". All of the issued and outstanding common shares of Harvest Operations are by the Trust.

In addition to administering the affairs of the Trust, Harvest Operations manages the affairs of the other Operating Subsidiaries and is responsible for providing all of the technical, engineering, geological, land management, financial, administrative and commodity marketing services relating to Harvest's upstream operations.

Redearth Partnership, a general partnership

Redearth Partnership is a general partnership formed on August 23, 2002 under the laws of the Province of Alberta. In June 2004, Harvest Operations acquired its 60% ownership interest in Redearth Partnership. Redearth Partnership's assets consist of direct ownership interest in properties located in north central Alberta.

Harvest Breeze Trust No. 1, a commercial trust

Breeze Trust No. 1 is an unincorporated commercial trust established under the laws of the Province of Alberta on July 8, 2004. Breeze Trust No. 1 is wholly owned by the Trust and its assets consist of the intangible portion of direct ownership interests in petroleum and natural gas properties purchased from the Breeze Resources Partnership and the Hay River Partnership and a 99% interest in each of those partnerships.

Harvest Breeze Trust. No. 2, a commercial trust

Breeze Trust No. 2 is an unincorporated commercial trust established under the laws of the Province of Alberta on July 8, 2004. Breeze Trust No. 2 is wholly owned by the Trust and its assets consist of a 1% interest in each of the Breeze Resources Partnership and the Hay River Partnership.

Breeze Resources Partnership, a general partnership

Breeze Resources Partnership (indirectly wholly-owned by the Trust) is a general partnership formed on June 30, 2004 under the laws of the Province of Alberta. Breeze Resources Partnership was acquired in September 2004. Its assets consist of the tangible portion of direct ownership interest in petroleum and natural gas properties located in east central Alberta and southern Alberta and a promissory note due from Breeze Trust No. 1.

Hay River Partnership, a general partnership

Hay River Partnership (indirectly wholly-owned by the Trust) is a general partnership formed on December 20, 2004 under the laws of the Province of Alberta. Hay River Partnership was acquired in August 2005. Its assets consist of the tangible portion of direct ownership interests in petroleum and natural gas properties located in northeastern British Columbia and a promissory note due from Breeze Trust No. 1.

Harvest Refining General Partnership, a general partnership

Harvest Refining General Partnership is a general partnership formed on September 27, 2006 under the laws of the Province of Alberta. The Trust holds a 99% partnership interest and Calpine Natural Gas Trust, an Alberta commercial trust wholly owned by the Trust, holds the residual 1% partnership interest. Harvest Refining General Partnership's assets consist of unsecured debt owing from each of VERT and North Atlantic as well as a 100% equity interest in both VERT and North Atlantic.

North Atlantic Refining Limited, a taxable corporation

North Atlantic Refining Limited (is a wholly-owned subsidiary of HRGP amalgamated under the laws of the Province of Newfoundland and Labrador on October 19, 2006. North Atlantic's assets consist of preferred partnership units representing 75% of the total preferred partnership interest in the North Atlantic Refining Limited Partnership as well as common partnership units representing 5% of the total common partnership interest in the same partnership.

North Atlantic manages the affairs of North Atlantic Refining Limited Partnership and is responsible for providing the engineering, operations and administrative services related to Harvest's refining operations. The feedstock supply management and marketing of refined products has been contracted to Vitol Refining, S.A. pursuant to the Supply and Offtake Agreement.

Viking Energy Royalty Trust, a commercial trust

Viking Energy Royalty Trust (a, wholly-owned subsidiary of North Atlantic Refining Limited) is a trust established under the laws of the Province of Alberta on November 5, 1996. VERT's assets consist of preferred partnership units representing 25% of the total preferred partnership interest in the North Atlantic Refining Limited Partnership as well as common partnership units representing 95% of the total common partnership interest in the same partnership.

North Atlantic Refining Limited Partnership, a limited partnership

North Atlantic Refining Limited Partnership is a limited partnership formed on October 13, 2006 under the laws of the Province of Newfoundland and Labrador. North Atlantic Refining Limited Partnership's assets consist of the Refinery and related retail marketing assets.

Organizational Structure of the Trust

The structure of the Trust and its significant subsidiaries is set forth below:

Notes:

(1)	All operations and management of the Trust and the Operating Subsidiaries are conducted through Harvest Operations except for the operations of the North Atlantic Refining Limited Partnership which is conducted by the management and employees of North Atlantic Refining Limited.

(2)	Breeze Trust No. 1 and Breeze Trust No. 2 have also issued priority trust units to Harvest Operations.

GENERAL DEVELOPMENT OF THE BUSINESS

Harvest was formed in July 2002 and acquired 8,500 BOE/d of production in the same year. Harvest acquired 7,475 BOE/d in 2003, 24,000 BOE/d in 2004, and 5,200 BOE/d in 2005 for aggregate consideration of $1,127.7 million. In late 2005, Harvest agreed to a plan of arrangement with VERT to create a stronger entity with a more balanced portfolio of assets as well as providing its security holders with greater liquidity and participation in one of the largest oil and natural gas trusts in Canada. During 2006, Harvest's upstream production averaged approximately 59,729 BOE/d with a year end exit rate of approximately 65,023 BOE/d comprised of approximately 45% light and medium oil, 25% heavy oil and 30% natural gas. The acquisition of the North Atlantic refinery was completed in October 2006 and for the month of December 2006, being the first month of full operations since acquiring the Refinery, the throughput of the North Atlantic refinery totalled 101,679 BOE/d.

Year ended December 31, 2007

In August 2007, Harvest acquired all of the issued and outstanding shares of Grand Petroleum Inc. ("Grand") for an aggregate transaction cost of $139.3 million comprised of $109.7 million in cash to acquire the shares of Grand, $28.8 million to repay Grand’s bank debt and $0.8 million in respect of related acquisition costs. During the three months ended March 31, 2007, Grand’s production averaged 3,409 BOE/d comprised of 68% light oil and 32% natural gas.

During 2007, Harvest's upstream production averaged approximately 60,336 BOE/d comprised of approximately 49% light and medium oil, 24% heavy oil and 27% natural gas. Capital spending on internal development in our upstream business aggregated to $300.7 million, a decrease of $76.2 million over the prior year while capital spending in our downstream business totalled $44.1 million. For 2007, the daily throughput of feedstock for the Refinery averaged 98,617 bbls/d reflecting two planned shutdowns in the fourth quarter for turnaround and scheduled maintenance activities.

Year ended December 31, 2008

On July 24, 2008, Harvest acquired all of the issued and outstanding shares of a private corporation with production of approximately 390 bbl/d of light oil and 2,300 mcf/d of natural gas for cash consideration of $36.8 million. On September 8, 2008, Harvest acquired petroleum and natural gas producing properties in the Peace River Arch area of northern Alberta with approximately 1,250 bbl/d of light oil and 3,900 mcf/d of natural gas for cash consideration of $130.8 million plus some minor property interests which produced approximately 85 BOE/d.

During 2008, Harvest's upstream production averaged approximately 55,932 BOE/d comprised of approximately 50% light and medium oil, 22% heavy oil and 28% natural gas. Capital spending on internal development in our upstream business aggregated to $271.3 million, a reduction of $29.4 million as compared to the prior year while capital spending in our downstream business totalled $56.2 million as compared to $44.1 million in 2007. For 2008, the daily throughput of feedstock for the Refinery averaged 103,497 bbls/d as compared to 98,617 bbls/d in the prior year.

Year ended December 31, 2009

On June 15, 2009, Harvest and Pegasus Oil & Gas Inc. ("Pegasus") entered into a pre-acquisition agreement pursuant to which Harvest agreed to make an offer to purchase all of the outstanding shares of Pegasus in consideration for 0.015 of a Trust Unit for each Pegasus share. The total transaction value was composed of $4.6 million of Harvest Trust Units, $13.9 million of assumed Pegasus debt and $1.0 million of acquisition costs. Harvest completed the acquisition of 100% of the outstanding shares of Pegasus on August 12, 2009.

On October 21, 2009, Harvest and KNOC entered into a definitive arrangement agreement pursuant to which KNOC agreed to acquire the Trust in a transaction valued at approximately $4.1 billion (including debt) pursuant to a plan of arrangement under Section 193 of the ABCA. A special meeting of the holders of the outstanding Trust Units, Trust Unit Rights and Unit Awards to consider the KNOC Arrangement was held on December 15, 2009. A special resolution approving the KNOC Arrangement was passed by a majority vote of over 90% of such securityholders. The KNOC Arrangement was subsequently approved by the Court of Queen's Bench of Alberta on December 16, 2009 and became effective on December 22, 2009, whereupon the Trust become an indirect wholly-owned subsidiary of KNOC.

Pursuant to the KNOC Arrangement, all of the issued and outstanding Trust Units were acquired by KNOC Canada for cash consideration of $10.00 per Trust Unit. In addition, all outstanding Trust Unit Rights and Unit Awards of Harvest were cancelled in exchange for a cash payment equal to, for each Trust Unit Right, the greater of $0.01 and the amount, if any, by which $10.00 exceeded the exercise price thereof and, for each Unit Award, $10.00 for each Trust Unit issuable on the exercise thereof. The Trust Units were subsequently delisted from both the TSX and the NYSE.

The Debentures and the 7⅞% Senior Notes continued as obligations of the Trust and Harvest Operations, as applicable, following completion of the KNOC Arrangement. See "General Description of Capital Structure" and "Supplemental Capital Structure Information - 7⅞% Senior Notes ". The outstanding Debentures remain listed on the TSX. See "Market for Securities".

Concurrent with closing of the KNOC Arrangement, Harvest Operations repaid approximately $600 million of then existing bank indebtedness and entered into an amended $600 million credit facility with a syndicate of lenders. See "Supplemental Capital Structure Information – Credit Facility".

During 2009, Harvest's upstream production averaged approximately 51,646 BOE/d comprised of approximately 51% light and medium oil, 20% heavy oil and 29% natural gas. Capital spending on internal development in our Upstream business aggregated to $186.3 million, a reduction of $85.0 million as compared to the prior year while capital spending in our Downstream business totalled $43.9 million as compared to $56.2 million in 2008.

In the Downstream operations the Refinery averaged 83,939 bbls/d in 2009, down from 103,497 bbls/d in the prior year. A major planned turnaround was successfully completed during the second quarter, expanding our hydrocracking capacity by an additional 1,000 barrels per stream-day. Operations in the third quarter resulted in throughputs similar to the first quarter; however, margins were considerably reduced. Fourth quarter margins were also weak, and North Atlantic took advantage of this to reduce throughputs and complete maintenance activities.

Recent Developments

As completion of the KNOC Arrangement constituted a "change of control" under the Debenture Indenture, the Trust was required to make, and did on January 19, 2010 make offers to purchase all outstanding Debentures for cash consideration equal to 101% of the principal amount thereof plus accrued and unpaid interest. As at March 4, 2010 all of the offers to purchase expired and the following redemptions were made: (a) $13.3 million principal amount was tendered in respect of the 6.5% Debentures Due 2010, leaving a principal balance of $23.8 million outstanding; (b) $67.8 million principal amount was tendered in respect of the 6.40% Debentures Due 2012, leaving a principal balance of $106.8 million outstanding; (c) $48.7 million principal amount was tendered in respect of the 7.25% Debentures Due 2013, leaving a principal balance of $330.5 million outstanding; (d) $13.2 million principal amount was tendered in respect of the 7.25% Debentures Due 2014, leaving a principal balance of $60.1 million outstanding; and (e) $13.4 million principal amount was tendered in respect of the 7.50% Debentures Due 2015, leaving a principal balance of $236.6 million outstanding. See "General Description of Capital Structure – Debentures and Debenture Indenture – Change of Control of the Trust".

The indenture pursuant to which the 7⅞% Senior Notes were issued contains a similar "change of control" provision. Accordingly, on January 20, 2010, the Harvest Operations made an offer to purchase all of the outstanding 7⅞% Senior Notes for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest. On February 16, 2010, that offer expired with US$40.4 million principal amount having been tendered in acceptance of the offer, leaving a principal balance of US$209.6 million outstanding.

In early 2010, we issued an incremental $466 million of equity to KNOC Canada, which was used to further reduce bank debt in advance of the required change-of-control offers to holders of the 7⅞% Senior Notes and Debentures.

In March 2010, Harvest closed an acquisition of certain petroleum and natural gas assets for $31.0 million.

GENERAL BUSINESS DESCRIPTION

Overview

With its acquisition of North Atlantic in October 2006, Harvest became an integrated petroleum and natural gas producer with downstream operations located in Newfoundland and Labrador and upstream operations located in Alberta, Saskatchewan and British Columbia.

In the upstream operations, Harvest employs a disciplined approach to acquiring high working interest, large resource-in-place, producing properties and uses "best practice" technical and field operational processes to extract maximum value from its assets. These operational processes include hands-on approach to management with a focus on optimizing production rates, the application of enhanced oil recovery and other technologies and selective capital investment to maximize reservoir recovery while stressing operational efficiencies to control operating costs. As at March 23, 2010, Harvest employed 365 full-time employees in its upstream business 237 of which are located in the head office and 128 of which are located in the field.

Harvest's downstream business consists of a medium gravity sour crude oil hydrocracking refinery with 115,000 barrels per stream day nameplate capacity and with related docking and storage facilities as well as a marketing division with retail gasoline, home heating, commercial, wholesale and bunkers business all operated in Province of Newfoundland and Labrador. As at March 23, 2010, Harvest employed 450 full-time employees and 72 part-time employees in its downstream business, all of which are located in the Province of Newfoundland and Labrador.

Business Strategies, Policies & Practices

Harvest's business strategy is focused on cash flow generation, acquiring assets with identified operational and development opportunities and increasing the long-term value of its assets with proven development strategies. Prior to 2006, Harvest had applied its strategies to opportunities in the petroleum and natural gas industry in western Canada. With the valuation of petroleum and natural gas assets in western Canada ever increasing through 2005 and into 2006, the opportunities to acquire such assets with significant upside potential became difficult. As a result, in 2006 Harvest changed its focus in western Canada to aggressively pursuing development opportunities within our existing asset base and in 2007, implemented three enhanced oil recovery projects with modest capital requirements but the potential to add significant reserves.

In 2006, Harvest expanded its core business to include crude oil refining and a retail petroleum marketing business. This initiative was undertaken to diversify our business with a long-life asset that has considerable growth potential by increasing the throughput, shifting the yield to higher-valued refined products as well as enhancing capacity to handle a heavier, more-sour crude oil feedstock.

Upstream Segment

Within the upstream segment, Harvest employs the following operating strategies:

Acquire Properties with Operational and Development Opportunities - Harvest will continue to selectively acquire properties with an established production history and once acquired, focus on improving resource recovery, reducing costs and extending reserve life thereby creating additional value for its securityholders. Harvest will continue to evaluate future acquisitions on the basis of their net present value.

Enhanced Oil Recovery Projects - Harvest will continue to promote its enhanced oil recovery projects. At Wainwright, we implemented a polymer flood pilot to improve recovery rates. With the success of this pilot, we expect to expand the project to impact a larger portion of the reservoir at Wainwright. At both Bellshill Lake and Suffield, we have increased our injected water by introducing water produced at adjacent properties to re-pressurize the reservoir. Future enhanced oil recovery opportunities have been identified in Hayter, Hay River, Kindersley and southeast Saskatchewan, while carbon dioxide (CO2) flooding and sequestration, oilsands and coal bed methane (CBM) represent longer term recovery opportunities for Harvest.

Increase Operating Netbacks - Harvest focuses on reducing operating costs and optimizing marketing alternatives to increase its operating netback and thereby extending the life and increasing the value of its proved reserves. Cost reduction initiatives include continuous improvements to water handling and disposal alternatives and contracting for volume discounts on well servicing and purchased materials. Optimizing marketing alternatives includes blending crude oil production to meet pricing specifications and reviewing transportation alternatives to achieve the highest prices available at the wellhead.

Insurance Coverage - In addition to preventative maintenance operating practices, Harvest maintains property damage and business interruption insurance to mitigate the risk associated with its practice of controlling operations and future development by maintaining a high working interest in its petroleum and natural gas properties. Harvest's property damage coverage is subject to a $500,000 deductible per occurrence and a claim limit of $130 million while the business interruption insurance covers its five highest revenue generating properties subject to a 30 day deductible period and claim limit of $130 million. Harvest also maintains an industry standard environmental, health and safety program – See "Environmental, Health & Safety Policies & Practices" below under "Other Upstream Information".

Downstream Segment

Within the downstream segment, Harvest employs the following operating strategies:

Acquire Established Operating Facilities – The North Atlantic operations acquired by Harvest in 2006 had over ten years of continuous operations with a committed workforce and operating plan. In respect of the related feedstock procurement and marketing of refined products, Harvest has contracted with Vitol Refining S.A. to provide these services as well as the related working capital financing subject to a mutual six month termination clause after November 1, 2011. The Refinery is currently configured to produce high quality gasoline and distillates that meet or exceed the ever increasing environmental requirements, from a medium gravity sour feedstock.

Profitability Improvement and Expansion – We have identified a "Debottlenecking Project" involving an increase in the design capacity from 115,000 bbl/d to 130,000 bbl/d, improving the yield of gasoline and distillate products, enhancing feedstock receiving and storage facilities and improving process heating design and combustion technologies. In 2009, we made considerable progress toward the Debottleneck Projects. This suite of investments is estimated to cost a total of approximately US$310 million through 2010 and 2011 and has compelling economics. It involves the licensing and incorporation of demonstrated and mature process technologies into existing processes to capture additional capacities, enhanced yields and reduced expenses. We spent approximately US$11 million advancing these projects during 2009.

Insurance Coverage – North Atlantic maintains property damage and business interruption insurance on its refinery operations to a maximum annual loss limit of US$1 billion subject to a property damage deductible of US$7.5 million and a 45 day deductible period for the business interruption coverage subject to a minimum of US$20 million for any one occurrence. North Atlantic receives its crude oil feedstock via water born vessels and protects its exposure to marine pollution and related clean-up by requiring any vessel delivering feedstock to the Refinery or shipping refined products from the Refinery to carry US$1 billion of coverage per vessel and to insure the cargo for 110% of its value. In addition, North Atlantic maintains sudden and accidental pollution insurance in the amount of US$200 million subject to a deductible of US$0.5 million.

Cash Flow Risk Management

Harvest’s cash flow risk management strategies are financially integrated, reflecting that the commodity price risk of our cash flow from producing crude oil in western Canada is financially offset partially by our requirement to purchase crude oil feedstock for our downstream operations even though the crude oil produced in western Canada does not physically flow to our refinery in Newfoundland. As a result, our 2010 cash flow at risk is comprised of approximately net 33,000 bbls/d of refined product price exposure, 82,000 bbls/d of refined product crack spread exposure and 79,000 mcf/d of western Canadian natural gas price exposure.

Commencing in 2006, we limited our financial hedge counterparties to lenders in our syndicated Credit Facility as the security provided under our Credit Facility will extend to our price risk management contracts. This eliminates the requirement for margin calls and the pledging of collateral as well as enables the negotiation of a more limited number of events of default which limits the potential that these contracts could exacerbate credit concerns.

UPSTREAM BUSINESS

STATEMENT OF RESERVES DATA

The statement of reserves data and other oil and natural gas information set forth below (the " Statement") is dated March 23, 2010. The effective date of the Statement is December 31, 2009 and the preparation date of the Statement is March 23, 2010.

Disclosure of Reserves Data

Harvest retained qualified, Independent Reserves Engineering Evaluators to evaluate and prepare reports on 100% of Harvest's crude oil and natural gas reserves as of December 31, 2009. Harvest's reserves were evaluated by McDaniel (who evaluated approximately 40% of Harvest's total proved plus probable reserves), and GLJ (who evaluated approximately 60% of Harvest's total proved plus probable reserves). All of Harvest's reserves were evaluated using the price and cost assumptions of McDaniel as at January 1, 2010.

The Statement summarizes the crude oil, natural gas liquids and natural gas reserves of the Operating Subsidiaries and the net present values of future net revenue for these reserves using forecast prices and costs. The Reserve Report has been prepared by the Independent Reserve Engineering Evaluators in accordance with the standards contained in the COGE Handbook and the reserve definitions and other requirements contained in NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important to the readers of this information. Harvest engaged the Independent Reserve Engineering Evaluators to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

All of the Operating Subsidiaries' reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia 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 forecast 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.

Reserves Data (Forecast Prices and Costs) – December 31, 2009

SUMMARY OF OIL AND NATURAL GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

as of December 31, 2009

FORECAST PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM OIL (1)				HEAVY OIL (1)				NATURAL GAS
RESERVES CATEGORY	Gross (Mbbls)		Net (Mbbls)		Gross (Mbbls)		Net (Mbbls)		Gross (MMcf)		Net (MMcf)

PROVED
Developed Producing		52,299		47,125		30,612		27,095		163,734		143,896
Developed Non-Producing		872		734		2,030		1,601		13,562		11,857
Undeveloped		8,703		7,392		4,540		3,668		29,241		23,763
TOTAL PROVED		61,874		55,251		37,182		32,364		206,537		179,516

PROBABLE		25,161		22,127		17,915		14,920		79,559		67,482

TOTAL PROVED PLUS PROBABLE		87,035		77,378		55,097		47,284		286,096		246,998

	RESERVES
	NATURAL GAS LIQUIDS				TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (Mbbls)		Net (Mbbls)		Gross (MBOE)		Net (MBOE)

PROVED
Developed Producing		5,811		4,265		116,010		102,468
Developed Non-Producing		392		269		5,554		4,580
Undeveloped		627		473		18,744		15,493
TOTAL PROVED		6,830		5,007		140,309		122,541

PROBABLE		2,819		2,025		59,155		50,319

TOTAL PROVED PLUS PROBABLE		9,649		7,032		199,463		172,860

											Value Per
											Boe Before
	NET PRESENT VALUES OF FUTURE NET REVENUE										Income Tax
	BEFORE INCOME TAXES DISCOUNTED AT (%/year) (2)										Discounted
	0%		5%		10%		15%		20%		At 10%/year
RESERVES CATEGORY	($M)		($M)		($M)		($M)		($M)		($/BOE)

PROVED
Developed Producing		4,374,392		3,215,812		2,573,005		2,160,755		1,873,176		25.11
Developed Non-Producing		161,211		120,018		92,936		74,578		61,509		20.29
Undeveloped		519,311		343,482		239,289		172,512		127,176		15.45
TOTAL PROVED		5,054,914		3,679,312		2,905,230		2,407,845		2,061,861		23.71

PROBABLE		2,540,437		1,419,771		921,405		653,517		491,192		18.31

TOTAL PROVED PLUS PROBABLE		7,595,351		5,099,083		3,826,635		3,061,362		2,553,053		22.14

	NET PRESENT VALUES OF FUTURE NET REVENUE
	AFTER INCOME TAXES DISCOUNTED AT (%/year) (2)
	0%		5%		10%		15%		20%
RESERVES CATEGORY	($M)		($M)		($M)		($M)		($M)

PROVED
Developed Producing		3,972,534		2,976,906		2,415,640		2,050,517		1,792,523
Developed Non-Producing		122,150		92,362		72,708		59,292		49,645
Undeveloped		392,228		254,922		174,020		122,490		87,712
TOTAL PROVED		4,486,912		3,324,190		2,662,368		2,232,299		1,929,880

PROBABLE		1,900,340		1,063,836		691,516		491,395		370,180

TOTAL PROVED PLUS PROBABLE		6,387,252		4,388,026		3,353,884		2,723,694		2,300,060

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

as of December 31, 2009

FORECAST PRICES AND COSTS

RESERVES	REVENUE		ROYALTIES		OPERATING COSTS		DEVELOP- MENT COSTS		WELL ABANDON- MENT COSTS		FUTURE NET REVENUE BEFORE INCOME TAXES (2)		INCOME		FUTURE NET REVENUE AFTER INCOME
CATEGORY	($M)		($M)		($M)		($M)		($M)		($M)		TAXES		TAXES (2)

Proved Reserves		10,710,153		1,379,054		3,659,152		438,711		178,324		5,054,914		568,001		4,486,912

Proved Plus Probable Reserves		15,950,806		2,143,867		5,352,942		659,518		199,130		7,595,350		1,208,099		6,387,252

FUTURE NET REVENUE

BY PRODUCTION GROUP

as of December 31, 2009

FORECAST PRICES AND COSTS

		FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year)		UNIT VALUE ($/bbl or
RESERVES CATEGORY	PRODUCTION GROUP	($M) (2)		$/mcf)

Proved Reserves	Light and Medium Crude Oil (including solution gas and associated by-products)		1,109,181		26.20
	Heavy Crude Oil (including solution gas and associated by-products)		1,268,141		26.05
	Associated and Non-Associated Natural Gas (including associated by-products)		523,480		3.25
	Non-conventional Oil & Gas Activities		4,428		1.88
			2,905,230		24.58
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and associated by-products)		1,444,367		23.87
	Heavy Crude Oil (including solution gas and associated by-products)		1,683,693		24.37
	Associated and Non-Associated Natural Gas (including associated by-products)		692,311		3.13
	Non-conventional Oil & Gas Activities		6,264		1.87
			3,826,635		22.90

Notes to Reserves Data Tables

The reserves attributable to Harvest's Hay River property, which is an area that produces medium gravity crude oil (average 24° API), are subject to a heavy oil royalty regime in British Columbia and would be required, under NI 51-101, to be classified as heavy oil for that reason. We have presented Hay River reserves as medium gravity crude in the reserve tables above as they would otherwise be classified in this fashion were it not for the lower rate royalty regime applied in British Columbia. If the Hay River reserves were included in the heavy crude oil category, it would increase the gross heavy oil reserves and reduce the light/medium oil reserves by the following amounts: Proved Developed Producing: 11.9 MMbbl, Proved Undeveloped: 5.2 MMbbl, Total Proved: 17.1 MMbbl, Probable: 5.5 MMbbl and Proved plus Probable: 22.6 MMbbl, and would increase the net heavy oil reserves and reduce the light/medium oil reserves by the following amounts: Proved Developed Producing: 10.5 MMbbl, Proved Undeveloped: 4.3 MMbbl, Total Proved: 14.8 MMbbl, Probable: 4.9 MMbbl, and Proved plus Probable: 19.7 MMbbl.

2.	Columns may not add due to rounding.

3.	The crude oil, natural gas liquids and natural gas reserve estimates presented in the Reserve Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

4.	The crude oil, natural gas liquids and natural gas reserve estimates presented in the Reserve Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of these definitions are set forth below:

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on

analysis of drilling, geological, geophysical and engineering data;

the use of established technology; and

specified economic conditions.

Reserves are classified according to the degree of certainty associated with the estimates.

(a)

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b)

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

(c)

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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

(d)

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(e)

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(f)

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a)

at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

(b)

at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

Forecast Prices and Costs – January 1, 2010

Forecast prices and costs are those:

(a)

generally acceptable as being a reasonable outlook of the future; and

(b)

if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Operating Subsidiaries is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized in the Reserve Report, based on McDaniel's then current forecasts at the date of the Report, were as follows:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

as of January 1, 2010

FORECAST PRICES AND COSTS

	OIL										NATURAL GAS		NATURAL GAS LIQUIDS		INFLATION RATES (6)		U.S./ CAN EXCHANGE RATE (7)
Year	WTI Crude Oil (1) ($US/ bbl)		Edmonton Light Crude Oil (2) ($Cdn/ bbl)		Alberta Heavy Crude Oil (3) ($Cdn/ bbl)		Alberta Bow River Hardisty Crude Oil (4) ($Cdn/ bbl)		Sask Cromer Medium Crude Oil (5) ($Cdn/ bbl)		Alberta AECO Spot Price ($Cdn/ GJ)		Edmonton Cond. and Natural Gasolines ($Cdn/ bbl)		(%/Year)		($US/$Cdn)
Forecast
2010		80.0		83.2		68.1		72.3		76.5		6.05		85.2		2.0		0.95
2011		83.6		87.0		67.6		73.8		79.1		6.75		89.0		2.0		0.95
2012		87.4		91.0		68.0		74.4		81.8		7.15		93.1		2.0		0.95
2013		91.3		95.0		68.1		75.8		85.4		7.45		97.1		2.0		0.95
2014		95.3		99.2		71.1		79.2		89.2		7.80		101.4		2.0		0.95
2015		99.4		103.5		74.2		82.6		93.1		8.15		105.7		2.0		0.95
2016		101.4		105.6		75.7		84.3		94.9		8.40		107.9		2.0		0.95
2017		103.4		107.7		77.2		85.9		96.8		8.55		110.0		2.0		0.95
2018		105.4		109.8		78.7		87.6		98.7		8.70		112.1		2.0		0.95
2019		107.6		112.1		80.4		89.4		100.7		8.90		114.5		2.0		0.95
2020		109.7		114.3		81.9		91.2		102.7		9.05		116.7		2.0		0.95
2021		111.9		116.5		83.6		93.0		104.8		9.25		119.0		2.0		0.95
2022		114.1		118.8		85.2		94.8		106.8		9.45		121.3		2.0		0.95
2023		116.4		121.2		86.9		96.7		109.0		9.65		123.8		2.0		0.95
2024		118.8		123.7		88.7		98.7		111.2		9.85		126.3		2.0		0.95
There-after	+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr			2.0		0.95

Notes:

(1)

West Texas Intermediate at Cushing Oklahoma 40 degrees API/0.5% sulphur.

(2)

Edmonton Light Sweet 40 degrees API, 0.3% sulphur.

(3)

Heavy crude oil 12 degrees API at Hardisty Alberta (after deduction of blending costs to reach pipeline quality).

(4)

Bow River at Hardisty Alberta (Heavy stream).

(5)

Midale Cromer crude oil 29 degrees API, 2.0% sulphur.

(6)

Inflation rates for forecasting prices and costs.

(7)

Exchange rates used to generate the benchmark reference prices in this table.

Weighted average historical prices realized by the Operating Subsidiaries for the year ended December 31, 2009, were $4.29/mcf for natural gas, $45.03/bbl for natural gas liquids, $58.18/bbl for light/medium oil, and $52.91/bbl for heavy oil.

6.	Future Development Costs

The following table sets forth development costs deducted in the estimation of the Operating Subsidiaries' future net revenue attributable to the reserve categories noted below.

	Forecast Prices and Costs
	($M)
Year	Proved Reserves		Proved Plus Probable Reserves
2010	$	119,221	$	199,782
2011	$	114,181	$	176,598
2012	$	63,841	$	95,615
2013	$	5,440	$	22,802
2014	$	4,974	$	12,687
Thereafter	$	139,127	$	167,608
Total Undiscounted	$	446,784	$	675,092
Total Discounted at 10%	$	328,177	$	511,348

Future development costs will be funded through cash flow and the Trust's Credit Facility.

7.	Estimated future abandonment costs related to a property have been taken into account by the Independent Reserve Engineering Evaluators in determining reserves that should be attributed to a property and in determining the aggregate future net revenue there from. No allowance was made; however, for reclamation of well sites or the abandonment and reclamation of any facilities. See "Other Upstream Business Information – Additional Information Concerning Abandonment and Reclamation Costs" for more information.

8.	The forecast price and cost assumptions assume the continuance of current laws and regulations.

9.	The extent and character of all factual data supplied to the Independent Reserve Engineering Evaluators were accepted by the Independent Reserve Engineering Evaluators as represented. No field inspection was conducted.

Reconciliations of Changes in Reserves

RECONCILIATION OF

OPERATING SUBSIDIARIES COMPANY GROSS

BY PRINCIPAL PRODUCT TYPE

FORECAST PRICES AND COSTS

	LIGHT AND MEDIUM OIL									HEAVY OIL									ASSOCIATED AND NON- ASSOCIATED NATURAL GAS
	Gross Proved			Gross Probable			Gross Proved Plus Probable			Gross Proved			Gross Probable			Gross Proved Plus Probable			Gross Proved			Gross Probable			Gross Proved Plus Probable
FACTORS	(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(MMcf)			(MMcf)			(MMcf)

31-Dec-08		68,505			28,788			97,293			40,245			18,977			59,224			231,973			90,175			322,148

Extensions/ Improved Recovery		411			1,435			1,846			401			329			730			5,017			(1,141	)		3,876
Technical Revisions		2,220			(4,761	)		(2,541	)		244			(1,402	)		(1,160	)		6,738			(9,847	)		(3,109	)
Discoveries		0			0			0			0			0			0			0			0			0
Acquisitions		77			19			96			37			10			47			11,120			5,605			16,725
Dispositions		(707	)		(319	)		(1,026	)		0			0			0			(15,426	)		(5,233	)		(20,659	)
Production		(8,633	)		0			(8,633	)		(3,745	)		0			(3,745	)		(32,885	)		0			(32,885	)

31-Dec-09		61,873			25,162			87,035			37,182			17,914			55,096			206,537			79,559			286,096

	NATURAL GAS LIQUIDS									TOTAL (BOE)
	Gross Proved			Gross Probable			Gross Proved Plus Probable			Gross Proved			Gross Probable			Gross Proved Plus Probable
FACTORS	(Mbbl)			(Mbbl)			(Mbbl)			(MBOE)			(MBOE)			(MBOE)

31-Dec-08		6,847			2,865			9,712			154,260			65,660			219,919

Extensions/ Improved Recovery		243			(140	)		103			1,889			1,434			3,323
Technical Revisions		509			(30	)		479			4,097			(7,836	)		(3,739	)
Discoveries		0			0			0			0			0			0
Acquisitions		344			171			515			2,312			1,134			3,446
Dispositions		(121	)		(47	)		(168	)		(3,398	)		(1,238	)		(4,636	)
Production		(992	)		0			(992	)		(18,851	)		0			(18,851	)

31-Dec-09		6,830			2,819			9,649			140,309			59,154			199,462

Note:

(1)	Columns may not add due to rounding.

Additional Information Relating to Reserves Data

Undeveloped Reserves

Proved and probable undeveloped reserves have been estimated in accordance with procedures and standards contained in the COGE Handbook.

As at January 1, 2010, Harvest has a total of 24.3 MMBOE of gross reserves that are classified as proved non-producing, of these non-producing reserves approximately 77% are undeveloped reserves. The balance are developed non-producing reserves which would be wells that are not currently producing and are eligible to be brought on production given economics and production information as at January 1, 2010. Substantially all of the undeveloped reserves are based on Harvest's then current 2010 budget and long range development plans for the major assets noted elsewhere in this document. Approximately 80% of these reserves are expected to be developed within the next two years. The remaining undeveloped reserves are expected be developed over the next five years, in most cases due to processing facility capacity restrictions. The capital cost has been taken into account for these programs in the estimated future net revenue.

TIMING OF INITIAL UNDEVELOPED

RESERVES ASSIGNMENT

	Gross Reserves First Attributed by Year
PRODUCT TYPE	Units	Prior		2007		2008			2009		Total
Proved Undeveloped
Light and Medium Crude Oil	Mbbl		1,621		1,826		65			417		3,929
Heavy Crude Oil	Mbbl		2,028		5,290		3,663			429		11,410
Natural Gas	MMcf		6,229		22,494		(2,840	)		1,337		27,221
Natural Gas Liquids	Mbbl		242		202		6			22		472
Total Oil Equivalent	MBOE		4,929		11,067		3,261			1,091		20,348

Probable Undeveloped
Light and Medium Crude Oil	Mbbl		1,893		7,837		(48	)		1,410		11,092
Heavy Crude Oil	Mbbl		4,233		5,802		(1,179	)		492		9,348
Natural Gas	MMcf		5,068		21,972		(3,260	)		2,148		25,929
Natural Gas Liquids	Mbbl		215		775		93			41		1,124
Total Oil Equivalent	MBOE		7,186		18,076		(1,677	)		2,302		25,886

Notes:

(1)

Hay River reserves are considered to be heavy crude oil for this analysis.

(2)

First attributed volumes include additions during the year and do not include revisions to previous undeveloped reserves.

Significant Factors or Uncertainties

Information in this Annual Information Form contains forward-looking information and estimates with respect to Harvest. This information addresses future events and conditions, and as such involves risks and uncertainties that could cause actual results to differ materially from those contemplated by the information provided. These risks and uncertainties include but are not limited to factors intrinsic in domestic and international politics and economics, general industry conditions including the impact of environmental laws and regulations, imprecision of reserves estimates, fluctuations in commodity prices, interest rates or foreign exchange rates and stock market volatility. The information and opinions concerning the Trust's future outlook are based on information available at March 29, 2010.

Important economic factors that should be taken into consideration that may affect particular components of the reserve data include: oil pricing, power costs and operating expenses.

Oil and Gas Wells

The following table sets forth the number of wells in which Harvest held a working interest as at December 31, 2009:

	Oil Wells								Natural Gas Wells
	Producing				Non-Producing				Producing				Non-Producing
	Gross		Net		Gross		Net		Gross		Net		Gross		Net

Alberta		2,980		2,254		1,811		1238.6		1,241		516		790		336
British Columbia		147		147		35		35		5		3.8		28		19
Saskatchewan		1,089		866.7		443		389.8		35		23.5		11		6.6
Total		4,216		3,268		2,289		1,663		1,281		543		829		361

	Service Wells
	Active				Suspended
	Gross		Net		Gross		Net
Alberta		615		493		73		49.2
British Columbia		146		146		5		4
Saskatchewan		137		132		74		56.2
Total		898		770		152		110

Note:

(1)	"Gross Wells" are wells in which Harvest has an interest (operating or non-operating).

(2)	"Net Wells" are Harvest's interest share of the gross wells (operating or non-operating).

Exploration and Development Activities

The following table sets forth the number of exploratory and development wells which Harvest completed during its 2009 financial year:

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net

Oil Wells						42		35.1
Gas Wells						38		15.7
Service Wells		1		1		25		24.5
Dry Holes		-		-		1		0.3
Total Wells		1		1		106		75.6

Note:

(1)	"Gross Wells" are wells in which Harvest has an interest (operating or non-operating).

(2)	"Net Wells" are Harvest's interest share of the gross wells (operating or non-operating).

For a discussion of Harvest's exploration and development activities refer to the "2009 Capital Expenditures Plan" section under "Other Upstream Information".

Properties with No Attributed Reserves

The following table sets out Harvest's undeveloped land holdings as at December 31, 2009.

	Undeveloped Acres
	Gross		Net

Alberta		512,522		366,763
British Columbia		44,630		36,653
Saskatchewan		99,146		77,484
Total		656,298		480,900

	Undeveloped Acres for which rights expire within one year
	Gross		Net
Alberta		92,074		69,034
British Columbia		3,003		2,067
Saskatchewan		12,873		7,456
Total		107,950		78,557

Harvest conducts ongoing development activity to retain land that would otherwise expire. As a result of this activity, the actual land holdings that will expire within one year will be less than indicated above.

Production Estimates

The following table sets forth the volume of production from the company’s gross reserves estimated for 2010 as found in the Reserve Report:

	2009 Production Forecast
	Light and Medium Oil (bbl/d)		Heavy Oil (bbl/d)		Natural Gas (Mcf/d)		Natural Gas Liquids (bbls/d)		Total (BOE/d)
Proved Producing		13,052		17,548		74,747		2,462		45,519
Proved Developed Non-Producing		133.3		221		3,280		103.7		1,004
Proved Undeveloped		473		1,069		3,682		122.1		2,278
Total Proved		13,659		18,837		81,710		2,688		48,800
Total Probable		1,171		1,102		6,293		187.2		3,509
Total Proved Plus Probable		14,830		19,939		88,003		2,875		52,311

OTHER UPSTREAM BUSINESS INFORMATION

Oil and Natural Gas Properties

The Operating Subsidiaries’ portfolio of significant Properties is discussed below. Reserve amounts discussed are gross reserves and are stated at December 31, 2009 based on forecast prices and cost assumptions.

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 Operations is actively engaged in cost reduction, production and reserve replacement optimization efforts directed at reserve addition through extending the economic life of these producing properties beyond the limits used in the Reserve Report and developing new proven reserves previously not evaluated by the Independent Reserve Engineering Evaluators. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence levels as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

2009 Historical Production by Material Property

Material Property	Light, Medium and Heavy Crude Oil (bbls/d)		Natural gas (Mcf/d)		NGL (bbls/d)		Average Daily Production (BOE/d)

Hay River		5,143		1,618		13		5,425
Markerville		822		20,607		667		4,923
Rimbey		150		17,527		1,012		4,083
Southeast Saskatchewan		3,911		227		38		3,987
Suffield		2,835		466		32		2,945
Hayter		2,491		320		20		2,564
Bellshill Lake		2,083		645		40		2,230
Red Earth		2,086		169		58		2,171
Wainwright		1,951		-		-		1,951
Crossfield		3		6,990		375		1,543
Lloydminster		1,250		433		-		1,322
Other		11,189		41,096		464		18,502
Total		33,912		90,097		2,718		51,646

Principal Producing Properties at December 31, 2009

Hay River : Hay River was acquired by Harvest on August 2, 2005 and is located approximately 125 miles NW of Grande Prairie in northeastern British Columbia. In 2009, Hay River produced 5,143 bbl/d of medium gravity 24 ° API crude oil and 1.6 mmcf /day of natural gas from the Bluesky Formation located at a depth of approximately 450m. Produced emulsion is processed at our central emulsion processing facility with the clean oil transported via pipeline to sales points. Natural gas produced in conjunction with the oil is processed at the central facility and is either re-injected into the reservoir for pressure maintenance, or sold through a sales gas pipeline connected to the facility. Hay River is a winter only access area in that drilling operations can only be undertaken when the ground is frozen (typically between late December and late March). The Hay River medium gravity oil production is priced at a discount to the Edmonton Light oil benchmark, contributing to stronger netbacks when compared to other similar gravity crudes. Harvest has an average 100% working interest in this operated property. In 2009, Harvest drilled 45 wells including 22 producing horizontal wells and 23 water source and water injection wells with a total capital expenditure of $88 million. Since 2007, Harvest has focused on increasing water injection into the producing Bluesky Formation to improve overall production and recovery of oil from the reservoir. A gas plant constructed in 2007 was commissioned in the spring of 2008 to eliminate flaring at the site and to manage production of associated gas. Connection of commercial power to the site was also completed in 2008 which allowed for optimization of the production in the field.

Markerville : The Markerville area is located approximately 35 kilometres southwest of Red Deer, Alberta. Harvest is the operator for a majority of the production in the area and has a working interest varying from 50 to 90% in the majority of the area’s wells. Markerville averaged 4,923 BOE/d (70 % natural gas) for the 12 months ending December 31, 2009. The area offers multi-zone potential with a number of producing horizons. The Pekisko Formation, at a well depth of approximately 2,200 metres, contains sweet natural gas along with associated liquids. The formation is developed using both vertical and horizontal wells. The Edmonton sands are a tight gas reservoir located at a depth of approximately 800 metres that contains sweet natural gas that is developed exclusively with vertical wells. Harvest also has a 25 to 50% working interest in Leduc Pinnacle Reef formations that produce light oil and associated natural gas. In 2009, the company had capital expenditures of $5.6 million primarily to complete, equip and tie-in wells drilled in the latter part of 2008. Harvest has ownership in various pipelines, compressors, and gas processing facilities that service the wells in this area.

Rimbey : The Rimbey area is located approximately 50 miles NW of Red Deer. In 2009, the Rimbey area produced 4,083 BOE/d of primarily natural gas (approximately 75%) from various formations including the Rock Creek, Viking, Ostracod, and Cardium. Harvest’s working interest in this area ranges from 25% to 100%. In 2009, Harvest drilled 11gross (3.3 net) wells. Harvest continued to build on a successful exploration program into 2009 at Chedderville by drilling an additional 3 delineation wells into the Basal Mannville (Ostracod) Formation. Production from the Chedderville property accounted for 50% of the total Rimbey production on a BOE basis. Total capital expenditures in Rimbey were $10.2 million for the year ending December 31, 2009. Gas produced from this area is generally transported on company owned and third party owned infrastructure to five company owned compression facilities at Wilson Creek and Rose Creek, Willesden Green and Ferrier as well as third party gas processing facilities.

Southeast Saskatchewan : Our southeast Saskatchewan properties are located approximately 110 miles southeast of Regina. Production from southeast Saskatchewan averaged 3,987 bbl/d of average 33 ° API crude oil in 2009, primarily produced from the Tilston and Souris Valley Formations of Mississippian age. Harvest has an average working interest of over 90% in this primarily operated property. In 2009, Harvest drilled 9 gross (6 net) wells, primarily horizontal development and infill wells into defined pools. Fluid produced from the area is processed at our 100% owned Hazelwood facility and is pipeline connected to the Enbridge system . Harvest has extensive proprietary 3D seismic coverage which offers control of the opportunity, and will be used to identify further opportunities on and off our land base.

Suffield : Suffield is located 160 miles SE of Calgary and is located on the site of the Canadian Forces Base Suffield. Production from this region averaged 2,945 BOE/d of primarily heavy oil in 2009, averaging 11 to 18 ° API from the Upper Mannville Glauconitic Formation. Harvest has an average 99% working interest in this operated property. Fluid produced from the area is processed at three emulsion processing facilities located at Caen, Lark and Batus with clean oil transported via pipeline to sales points. In 2009, Harvest drilled 1 gross (1 net) water injection well as part of our enhanced water injection into this reservoir. By increasing injection, Harvest believes the ultimate recovery of oil will be increased. Harvest’s capital investment in 2009 was $5.2 million including additional pipeline infrastructure to re-distribute produced water for injection. Future development at Suffield may include step-out, extension and infill drilling in the established pools. Pool optimization and enhanced recovery projects will target increased water injection into under-injected reservoirs that have not received adequate pressure maintenance.

Hayter : Harvest acquired the Hayter property in November 2002. Production in 2009 averaged approximately 2,564 bbl/d of 14 ° to 15 ° API oil, producing from the Lower Cretaceous Cummings/Dina Formation. Harvest has an average 94% working interest in this operated property. Emulsion produced from the wells is processed at one of two central processing facilities and then transported via pipeline to sales points. In 2009, Harvest had capital expenditures of $5.5 million to complete upgrades to the infrastructure as part of a production optimization project identified in 2008. Future development at Hayter may include additional infill and step-out drilling, as well as enhanced oil recovery projects. Harvest has identified the Hayter area as being amenable for enhanced recovery and will undergo additional testing of enhanced oil recovery techniques. Operating expense reduction projects such as low pressure water disposal wells, horizontal disposal wells, and battery optimization are ongoing.

Bellshill Lake : Harvest holds an average 98% working interest in this area, including a 100% working interest in the Bellshill Lake Ellerslie Unit, as well as working interests ranging from 6.5% to 100% in non-unit leases located next to the unit, all of which is operated by Harvest. Production consists of 26° to 28° API oil produced from the Ellerslie, and Dina formations, and totalled 2,230 BOE/d in 2009 weighted 95% towards oil and liquids. The Unit and area comprises 707 gross wells of which 580 are producing oil wells. The majority of these wells are tied-in to one central facility consisting of an oil processing facility, a water injection plant and a gas processing facility. Oil is transported to market via Gibson's pipeline and the gas is sold on the spot market. In 2008 Harvest constructed a water transfer line to bring incremental injection water to improve the ultimate recovery of oil from this large oil pool. In 2009, there was evidence of the benefit of this injection as the pool Gas Oil Ratio decreased indicating the reservoir pressure was increasing, which Harvest believes will ultimately result in increased oil recovery.

Red Earth : Production in 2009 from Red Earth averaged 2,171 BOE/d (98% oil) with an average oil quality of 37 ° to 39 ° API from the Devonian Slave Point, Granite Wash and Gilwood Formations. Harvest has an average 80% working interest in this primarily operated area. In 2009, Harvest drilled 8 gross (5.7 net) wells with total capital expenditures of $11.2 million. The Slave Point has typically been exploited using vertical wells, and the application of mutlistage fractured horizontal wells has the potential to allow Harvest to access hydrocarbon previously not considered economic. Future development at Red Earth may include downspace drilling in the Slave Point G pool, application of horizontal well technology as well as potential water injection to increase the recovery factor in a number of smaller Slave Point pools by offsetting production decline. Harvest has an extensive seismic database in the Red Earth area which was instrumental in the discovery of a new oil pool in the area, and will assist our plans to infill drill our identified Granite Wash and Slave Point pools.

Wainwright : Harvest acquired the Wainwright properties in September 2004. Production in 2009 from this pool averaged approximately 1,951 BOE/d of 22 ° to 24 ° API medium gravity oil, produced from the Cretaceous Upper Mannville Sparky Formation. Harvest has an average 99% working interest in these operated properties. In 2009, Harvest completed the construction and start-up of a polymer injection facility. This was a follow-up to a 2007 engineering study to evaluate the feasibility of using a polymer based injection fluid to increase waterflood sweep efficiencies and ultimate recoveries in this large oil pool. Total capital expenditures at Wainwright in 2009 were $8.0 million including approximately $6.0 million on the polymer facility alone.

Crossfield : Crossfield is located approximately 20 miles NW of Calgary. Production in 2009 from this region was primarily natural gas (75%) with some liquids and averaged approximately 1,543 BOE/d from the Lower Cretaceous Basal Quartz Formation. Harvest has an average 75% working interest in this operated and non-operated property. Harvest continues to evaluate opportunities to downspace and drill additional locations at Crossfield including the application of multi-stage fractured horizontal wells which have been successfully applied in similar geological formations. Capital expenditures in 2009 were $1.6 million to install a gas liquids separator package as part of a production optimization project.

Lloydminster : Harvest has an approximately 95% working interest in this heavy oil field located 10 miles south of the town of Lloydminster. Production of 12 ° to 14 ° API heavy crude oil is from the Lloydminster Sandstone Formation, and averaged 1,322 BOE/d (98% oil) in 2009. Harvest drilled 3 gross (1.5 net) horizontal wells in 2009 with total capital expenditures of $3.1 million. Production from the area wells is processed at a central processing facility with solution gas conservation and then trucked to Harvest’s Bellshill Lake pipeline terminal sales point. Future plans include downspacing the pool with additional horizontal wells and assessing the potential impact of water injection for pressure maintenance and enhanced recovery.

Capital Expenditures

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) related to Harvest's activities for the year ended December 31, 2009:

Property acquisition costs	($millions)
Proved properties		(62.1	)
Undeveloped properties		3.5
Total property acquisition costs		(58.6	)
Exploration costs		-
Development costs		182.8
Total Capital Expenditures		124.2

2010 Capital Expenditure Plan

Harvest’s expected total capital spending on its oil and natural gas properties for 2010 is expected to be approximately $ 320 million. The primary areas of focus for Harvest’s capital program during 2010 are the following:

·	Hay River – Expenditures of approximately $28 million to drill 11 producing multi-leg horizontal oil wells and water injection wells as well as upgrading our processing infrastructure

·	Red Earth – Drill 18 gross light oil wells for a net expenditure of $34 million with up to 10 multistage fractured horizontal wells for the Slave Point Formation

·	SE Saskatchewan – Drill 31 gross wells for a total expenditure of $48 million pursuing infill and step out horizontal wells in the Tilston, Souris Valley and Bakken Formations

·	Kindersley, Saskatchewan – Drill 10 multistage fractured horizontal wells into the Viking Formation for a total expenditure of $17 million

·	Lloydminster – Drill 18 gross horizontal wells for a total expenditure of $15 million

·	Various Areas – Expenditures of approximately $51 million to pursue production optimization including pump upsizing, facility debottlenecking and zonal recompletion.

Incremental Exploitation and Development Potential

Management of Harvest Operations has identified numerous development opportunities, many of which provide the potential for capital investment and incremental production beyond that identified in the Reserve Report. Opportunities being considered include:

·	Implementation or optimization of enhanced waterfloods in selected pools such as Hay River and Kindersley resulting in increased production and recovery;

·	Increasing water handling and water disposal capacity at key fields such as Hayter, Suffield and Bellshill Lake to add incremental oil volumes. This includes additional use of free water knock-outs and additional disposal wells;

·	De-bottlenecking existing fluid handling facilities and surface infrastructure;

·	Optimizing field oil cut management through the shut-in of select wells and increased total fluid from offset higher oil cut wells. Shut-in wells would be available for restart as oil cuts vary;

·	Uphole completions of bypassed or untested reserves in existing wellbores, including recompletion of existing shut-in wells to access undrained reserves;

·	Selected infill and step-out development drilling opportunities for various proven targets generally defined by 3D seismic;

·	Numerous exploratory opportunities defined by seismic from which value might be extracted by sale, Farmout or joint venture;

·	Opportunity to increase recovery factors in established pools using available and evolving enhanced recovery technologies such as Alkaline Surfactant Polymer at Wainwright, carbon dioxide injection at Bashaw and acid gas injection at Hayter;

·	Utilizing multistage fracture technology in horizontal wells to increase oil recovery from tight oil and gas formations at Red Earth (Slave Point Formation), Crossfield (Basal Quartz), Kindersley (Viking), Rimbey (Cardium) and SE Saskatchewan (Bakken).

Marketing Arrangements

Crude Oil and Natural Gas Liquids (NGL’s)

Harvest's crude oil and NGL production is marketed to a diverse portfolio of intermediaries and end users with the majority of contracts on 30 day continuously renewing basis and the NGL contracts on one year terms with both commodities receiving the prevailing monthly market prices. Harvest has a small number of condensate purchase contracts, required for blending heavy oil to meet pipeline specifications, that are a combination of one year and monthly spot contracts both at the prevailing monthly price.

Harvest received an average sales price, excluding the effects of commodity price risk management contracts, of $58.18/bbl for its light and medium crude oil, $52.91/bbl for its heavy crude oil and $45.03/bbl for its NGL’s for the year ending December 31, 2009 compared to $89.72/bbl, $77.22/bbl and $75.16/bbl for the year ending December 31, 2008, respectively.

Natural Gas

Approximately 95% of Harvest's natural gas production is currently being sold at the prevailing daily spot market price in Alberta with the remaining 5% of its production dedicated to aggregator contracts which are also reflective of market prices and are under contract until 2015.

Harvest received an average sales price, excluding the effects of commodity price risk contracts, of $4.29/mcf for its natural gas for the year ending December 31, 2009 compared to $8.60/mcf in 2008.

Additional Information Concerning Abandonment and Reclamation Costs

The following table sets forth information respecting future abandonment and reclamation costs for surface leases, wells, facilities and pipelines which are expected to be incurred by Harvest and for the periods indicated:

Period	Abandonment & Reclamation costs (undiscounted and using a 2% inflation rate) ($000)		Abandonment & Reclamation costs (discounted at 10% using a 2% inflation rate) ($000)

Total as at December 31, 2009		1,281,802		255,170
Anticipated to be paid in 2010		10,907		9,915
Anticipated to be paid in 2011		22,872		18,902
Anticipated to be paid in 2012		14,913		11,204

The number of net wells for which the Independent Reserve Engineering Evaluators estimated that Harvest would incur abandonment and reclamation costs is 4,806.5 wells (Proved plus Probable).

Abandonment costs (excluding salvage values) associated only with wells to which reserves were attributed were deducted by the Independent Reserve Engineering Evaluators in estimating future net revenue in the Reserve Report. The estimated future undiscounted expense related to facilities, pipelines and no reserve addition wells is 1,082.7 million ($204.9 million discounted at 10%). The nature of these expenses are not expected to change the anticipated costs for the next three years as they will not be incurred until the end of a field's reserve life profile.

Production History

The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:

Average Daily Production Volumes	2009
(before the deduction of royalties)		Q1	Q2	Q3	Q4	Total

Light & Medium Oil (bbls/d) (1)		24,233	24,316	22,793	23,281		23,651
Heavy Oil (bbls/d)		11,141	10,365	10,066	9,491		10,261
Total Oil (bbls/d)		35,374	34,681	32,859	32,772		33,912
NGL (bbls/d)		2,837	2,675	2,648	2,714		2,718

Natural Gas(Mcf/d)		95,421	92,335	89,163	83,610		90,097
Total Daily Production (BOE/d)		54,115	52,745	50,368	49,421		51,646

Total Sales Production	2009
		Q1	Q2	Q3	Q4	Total

Light and Medium Oil (bbls) (1)		2,180,993	2,212,779	2,096,979	2,141,864		8,632,615
Heavy Oil (bbls)		1,002,713	943,238	926,095	873,219		3,745,265
Total Oil (bbls)		3,183,706	3,156,017	3,023,074	3,015,083		12,377,880
NGL (bbls)		255,330	243,425	243,616	249,699		992,070

Natural Gas (Mcf)		8,587,867	8,402,462	8,202,973	7,692,103		32,885,405
Total Production (BOE)		4,870,347	4,799,852	4,633,852	4,546,799		18,850,851

Average Sales Prices Received	2009
		Q1	Q2	Q3	Q4	Total

Light & Medium oil ($/bbl) (1)		40.99	57.54	64.57	70.09		58.18
Heavy Oil ($/bbl)		37.16	55.12	58.57	62.62		52.91
Total Oil ($/bbl)		39.78	56.82	62.73	67.93		56.59

Natural Gas ($/Mcf)		41.22	42.26	44.71	51.95		45.03
NGL ($/bbl)		5.33	3.87	3.22	4.76		4.29
Total BOE ($/BOE)		37.56	46.28	48.97	55.94		47.02

Royalties Paid	2009
		Q1	Q2	Q3	Q4	Total

Light & Medium Oil ($000) (1)		11,666	17,972	21,085	27,817		78,540
Heavy Oil ($000)		4,353	6,972	9,759	7,091		28,175
Natural gas & NGL's ($000)		8,510	3,255	4,950	5,430		22,145
Total BOE ($000)		24,529	28,199	35,794	40,338		128,860

Light & Medium Oil ($/bbl) (1)		5.35	8.12	10.05	12.99		9.10
Heavy Oil ($/bbl)		4.34	7.39	10.54	8.12		7.52
Natural gas & NGL's ($/BOE)		5.05	1.98	3.07	3.55		3.42
Total BOE ($/BOE)		5.04	5.88	7.72	8.87		6.84

Operating Expenses (2)	2009
		Q1	Q2	Q3	Q4	Total

Light & Medium Oil ($000) (1)		39,937	32,413	31,663	32,013		136,026
Heavy Oil ($000)		14,725	12,211	12,459	12,623		52,018
Natural gas & NGL's ($000)		20,673	16,693	16,208	17,057		70,631
Total BOE ($000)		75,335	61,317	60,330	61,693		258,675

Light & Medium Oil ($/bbl) (1)		18.31	14.65	15.10	14.95		15.76
Heavy Oil ($/bbl)		14.69	12.95	13.45	14.46		13.89
Natural gas & NGL's ($/BOE)		12.26	10.15	10.06	11.14		10.91
Total BOE ($/BOE)		15.47	12.77	13.02	13.57		13.72

Netback Received (3)	2009
		Q1	Q2	Q3	Q4	Total

Light & Medium Oil ($/bbl) (1)		17.33	34.77	39.42	42.15		33.32
Heavy Oil ($/bbl)		18.13	34.78	34.58	40.04		31.50
Natural gas & NGL's ($/BOE)		16.07	13.91	10.03	17.68		14.37
Total BOE ($/BOE)		17.05	27.63	28.23	33.50		26.46

Notes:

(1)	Medium oil production includes production from our Hay River property. The crude oil from this property has an average API of 24 o (medium grade); however, it benefits from a heavy oil royalty regime and therefore, would be classified as heavy oil according to NI 51-101.

(2)	Before gains or losses on commodity derivatives.

(3)	Netbacks are calculated by subtracting royalties and operating expenses before gains or losses on commodity derivatives and transportation expenses.

Potential Acquisitions

Harvest continues to evaluate potential acquisitions of all types of petroleum and natural gas and other energy-related assets as part of its ongoing acquisition program. Harvest is normally in the process of evaluating several potential acquisitions at any one time which individually or together could be material. Except as otherwise disclosed herein, of the date hereof, Harvest has not reached an agreement on the price or terms of any potential material acquisitions and cannot predict whether any current or future opportunities will result in one or more acquisitions for Harvest.

Tax Horizon

In our structure, taxable income from the Operating Subsidiaries is transferred to the Trust on an annual basis and taxable income of the Trust was transferred to our Unitholders with the payment of distributions. The transfer of taxable income from the Operating Subsidiaries was primarily accomplished with the payment of the various net profits interests and the interest on the unsecured debt obligations owing to the Trust which are both deductible by the Operating Subsidiaries for income tax purposes. No material income taxes were paid by either the Trust or its subsidiaries in 2009. See "Risk Factors – Risks Related to Harvest’s Structure - Re-assessment of Prior Years’ Income Tax Returns."

Harvest is expected to convert to a corporate structure in 2010. Harvest currently has $3 billion of tax pools to shelter its taxable income. Harvest anticipates that there will be no income tax liability payable prior to 2013. Harvest’s future capital spending will further delay the tax horizon while a strengthening of commodity prices beyond that anticipated by the forward curve would result in tax pools being utilized earlier and the tax horizon accelerated. However, providing guidance on the timing of future cash income taxes is difficult in an industry with highly volatile commodity prices and significant fluctuations in the level of capital spending, both of which impact the tax horizon.

Environment, Health and Safety Policies and Practices

Harvest continues to maintain its Platinum-level status in the Canadian Association of Petroleum Producers’ (CAPP) Stewardship program. In 2009, Harvest was an active member of the CAPP Stewardship Redesign Committee making important contributions to this collaborated industry effort that has resulted in more meaningful stewardship benchmarks and metrics. The Stewardship reporting framework focuses on continuous improvement, Environment, Health and Safety (EH&S) management systems and reporting of environmental, health, safety and social performance.

Harvest continues to evolve and develop the existing environmental, health and safety management system as a means for mitigating the risk to our personnel, assets, the environment and the public. In 2009, updates to the EH&S management system included revisions to the existing system and the addition of key safe work practices, the medium for the delivery of the EH&S program manual hard copy to electronic and the formalization of contractor selection, engagement and safety performance tracking.

Harvest’s Upstream Manager of Environment, Health and Safety is responsible for monitoring regulatory requirements and when required, implementing appropriate compliance procedures and causing our operations practices to be carried out in accordance with the applicable environmental requirements with adequate safety precautions. At the conclusion of 2009 Harvest had implemented its Fugitive Emissions Program in accordance with the requirements set forth by the regulatory agencies.

In 2009, Harvest spent $7 million on the management and retirement of environmental liabilities. This work included: the restoration of recent and historic spill sites; the assessment, monitoring and remediation of sites with identified environmental impacts; and the reclamation of abandoned well sites and unused access roads. In 2009, Harvest had 268 active (operated) reclamation sites and 25 of these sites were submitted to regulators for reclamation certification. In 2010, it is expected that Harvest will have 300 active reclamation sites and will submit approximately 40 for reclamation certification.

Impact of Volatility in Commodity Prices

Harvest's operational results and financial condition will be dependent on the prices received for petroleum and natural gas production. Petroleum and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, which are influenced by weather and general economic conditions. Any decline in petroleum and natural gas prices could have an adverse effect on Harvest's financial condition. Harvest mitigates such price risk through closely monitoring the various commodity markets and establishing commodity price risk management programs, as deemed necessary, to provide stability to its cash flows.

A summary of financial and physical contracts in respect of price risk management activities can be found in Note 20 to Harvest's consolidated financial statements for the year ended December 31, 2009 and under the heading "Cash Flow Risk Management" in Harvest's management’s discussion and analysis for the year ended December 31, 2009, both of which are filed on SEDAR at www.sedar.com. Both Note 20 of Harvest's audited consolidated financial statements for the year ended December 31, 2009 and the "Risk Management, Financing and Other" discussion in Harvest's management’s discussion and analysis for the year ended December 31, 2009 are incorporated herein by reference.

Industry Conditions

The petroleum and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of petroleum and natural gas by agreements among the governments of Canada, Alberta, British Columbia and Saskatchewan, all of which should be carefully considered by investors in the petroleum and gas industry. It is not expected that any of these controls or regulations will affect Harvest's operations in a manner materially different than they would affect other petroleum and natural gas entities of similar size. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the petroleum and natural gas industry.

Pricing and Marketing – Petroleum, Natural Gas and Associated Products

In the provinces of Alberta, British Columbia and Saskatchewan, petroleum, natural gas and associated products are generally sold at market index based prices. These indices are generated at various sales points depending on the commodity and are reflective of the current value of the commodity adjusted for quality and location differentials. While these indices tend to track industry reference prices (i.e. West Texas Intermediate crude oil at Cushing, Oklahoma or natural gas at Henry Hub, Louisiana), some variances can occur due to specific supply-demand imbalances. These differentials can change on a monthly or daily basis depending on the supply-demand fundamental at each location as well as other non-related changes such as the value of the Canadian dollar and the cost of transporting the commodity to the pricing point of the particular index.

The producers of crude oil are entitled to negotiate sales contracts directly with purchasers, with the result that the market determines the price of crude oil. Crude oil prices are primarily based on worldwide supply and demand. The specific price depends in part on quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance and other contractual terms. Crude oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such exports has been obtained from the National Energy Board of Canada (the " NEB"). Any crude oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council.

The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than 2 years or for a term of 2 to 20 years (in quantities of not more than 30,000 m 3/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council.

The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Pipeline Capacity

Although pipeline expansions are ongoing, pipeline capacity is an important consideration and may impact the oil and natural gas industry by limiting the ability to export oil and natural gas.

Provincial Royalties and Incentives

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 crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the Working Interest owner's interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

From time to time, the federal and provincial governments in Canada have established incentive programs which have included royalty rate reductions (including for specific wells), royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects. However, the trend in recent years has been to eliminate these types of programs in favour of long term programs which enhance predictability for producers. If applicable, oil and natural gas royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments.

Alberta

The Government of Alberta (the “Government”) implemented its New Royalty Framework (the “NRF”) effective January 1, 2009. Conventional oil royalties are set by a single sliding rate formula containing separate elements that account for oil price and well production, with royalty rates ranging up to 50% and rates capped when oil prices reach $120 Cdn per barrel. Natural gas royalties are also set by a single sliding rate formula, with royalty rates ranging from 5% to 50% and rates capped when natural gas prices reach $17.50 Cdn/MMBtu. Oil sands base royalty rates start at 1%, and increase for every dollar when oil is priced above $55 per barrel to a maximum of 9% when oil prices reach $120 Cdn per barrel. Once the oil sands project has recovered specified allowed costs, the royalty rate will range from 25% to 40%.

In November 2008, the Government announced that companies drilling new natural gas and conventional oil wells at depths between 1,000 and 3,500 metres, which are spudded between November 19, 2008 and December 31, 2013, will have a one-time option of selecting new transitional royalty rates or new royalty framework rates. The transition option provides lower royalties in the initial years of a well's life. For example, under the transition option, royalty rates for natural gas wells will range from 5% to 30%. The election must be made prior to the end of the first calendar month in which the leased substance is produced.

The Deep Oil Exploration Program ("DOEP") and the Natural Gas Deep Drilling Program ("NGDDP") are new programs that began January 1, 2009. These programs provide upfront royalty adjustments to new wells. To qualify for such royalty adjustments under the DOEP, exploration wells must have a vertical depth greater than 2,000 metres with a Crown interest and must be spudded after January 1, 2009. These oil wells qualify for a royalty exemption on either the first $1 million of royalty or the first 12 months of production. The NGDDP applies to wells producing at a true vertical depth greater than 2,500 metres. The NGDDP will have an escalating royalty credit in line with progressively deeper wells from $625 per metre to a maximum of $3,750 per metre. There are additional benefits for the deepest wells. Both the DOEP and the NGDDP are five year programs. Any wells spud after December 31, 2013, or any wells that choose the transition option, will not qualify under either program. No royalty adjustments will be granted under either the DOEP or the NGDDP after December 31, 2018.

On March 3, 2009, the Government of Alberta announced a new three-point stimulus plan. On June 25, 2009 the Government extended the first two points by one year to March 2011:

Drilling royalty credit for new conventional oil and natural gas wells – effective for wells spud on or after April 1, 2009, this two-year program will provide a $200 per-metre-drilled royalty credit, with the maximum credit determined on a sliding scale based on the individual company’s total Alberta-based 2008 Crown oil and gas production.

Royalty rate cap for new conventional oil and natural gas wells – effective April 1, 2009, this program will provide a maximum 5% royalty rate for the first 12 months of production, to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas per well, to all new wells that begin producing conventional oil or natural gas between April 1, 2009 and March 31, 2011.

·	Abandonment and reclamation fund – the province will provide $30 million to be invested by the Orphan Well Association to abandon and reclaim old well sites where there is no legally responsible or financially able party available.

On March 11, 2010, the Alberta Government announced its intention to adjust royalty rates effective January 1st, 2011. This adjustment includes making the current incentive program royalty rate of 5% on new natural gas and conventional oil wells a permanent feature of the royalty system with current time and volume limits. The maximum royalty rate will be reduced from the current levels of 50% to 40% for conventional oil and to 36% for natural gas. The transitional royalty framework for oil and gas will continue until December 31, 2013 as announced and no new wells will be allowed to select transitional royalty rates effective January 1, 2011; wells that have selected the transitional royalty rates will be allowed to switch to the new rates effective January 1, 2011. All royalty curves will be finalized and announced by May 31, 2010. The implementation of the royalty adjustments is subject to certain risks and uncertainties, including changes to existing legislation and the regulation and development of proprietary software to support the calculation and collection of royalties. Certain proposed changes may require further consultation and there may be modifications introduced prior to implementation of the royalty adjustments on January 1, 2011.

Saskatchewan

Crown natural gas royalty rates are sensitive to the individual productivity of each well. The rates are applied to the respective portions of each classification of gas ("fourth tier gas", "third tier gas", "new gas" and "old gas") produced from a well.

Each month, the royalty rates are adjusted based on the level of the Provincial Average Gas Price ("PGP") established by the Province monthly. The PGP represents the weighted average fieldgate price (expressed in $/103m3) received by producers during the month for the sale of all gas subject to royalty. Crown royalty of the production volume is calculated on each individual well using the applicable royalty rate to the volume of gas produced by each well on a monthly basis. The operator must elect to use either the PGP or the Operator Average Gas Price ("OGP") for purposes of valuing the Crown's royalty share of the production volume from each well. The OGP is determined each month by the operator and represents the weighted average fieldgate price ($/103m3) received by the operator for sales of gas during the month. The Crown royalty share is calculated by multiplying the Crown royalty volume determined for each well by the wellhead value of the gas for the month.

Crown royalty rates for conventional oil are sensitive to the individual productivity of each well and the type of oil produced from the well. Each month, royalty rates are adjusted based on the level of the reference price established by the Province for each type of oil. For Crown royalty purposes, crude oil is classified as "heavy oil", "southwest designed oil" or "non-heavy oil other than southwest designated oil". There are separate reference prices established for each type of oil which represent the average wellhead price (in $/m3) received by producers during the month for sales of that oil type in Saskatchewan.

The Crown royalty share of production volume is calculated on each individual well using the applicable royalty rate to the volume of oil produced from the well each month. The Crown royalty share is calculated by multiplying the Crown royalty volume determined for each well by the wellhead value of the oil for the month. A separate cost sensitive royalty structure applies to incremental production from enhanced oil recovery projects, which incorporates lower royalty and freehold production tax rates before the project reaches payout of investment and operating expenditures.

Saskatchewan has introduced a new orphan oil and gas well and facility program, solely funded by oil and gas companies to cover the cost of cleaning up abandoned wells and facilities where the owner cannot be located or has gone out of business. The program is composed of a security deposit, based upon a formula considering assets of the well and the facility licensee against the estimated cost of decommissioning the well and facility once it is no longer producing, and an annual levy assessed to each licensee.

British Columbia

The British Columbia natural gas royalty regime is price-sensitive, using a "select price" as a parameter in the royalty rate formula. When the reference price, being the greater of the producer price or the Crown set posted minimum price ("PMP"), is below the select price, the royalty rate is fixed. The rate increases as prices increase above the select price. The Government of British Columbia determines the producer prices by averaging the actual selling prices for gas sales with shared characteristics for each company minus applicable costs. If this price is below the PMP, the PMP will be the price of the gas for royalty purposes.

Natural gas is classified as either "conservation gas" or "non-conservation gas". There are three royalty categories applicable to non-conservation gas, which are dependent on the date on which title was acquired from the Crown and on the date on which the well was drilled. The base royalty rate for non-conservation gas ranges from 9% to 15%. A lower base royalty rate of 8% is applied to conservation gas. However, the royalty rate may be reduced for low productivity wells.

The royalty regime for oil is dependent on age and production. Oil is classified as "old", "new" or "third tier" and a separate formula is used to determine the royalty rate depending on the classification. The rates are further varied depending on production. Lower royalty rates apply to low productivity wells and third tier oil to reflect the increased cost of exploration and extraction. There is no minimum royalty rate for oil.

In May 2008, the Government of British Columbia introduced the Net Profit Royalty Program to stimulate development of high risk and high cost natural gas and oil resources in British Columbia that are not economic under other royalty programs. The program allows for the calculation of royalties based on the net profits of a particular project and is governed under the Net Profit Royalty Regulation, which came into effect in May 2008.

On August 6, 2009, the Province of British Columbia announced an Oil and Gas Stimulus package providing for:

A one-year, two per cent royalty rate for all natural gas wells drilled in a 10 month window (September 2009 - June 2010).

An increase of 15 per cent in the existing royalty deductions for natural gas deep drilling.

Qualification of horizontal wells drilled between 1,900 and 2,300 metres into the Deep Royalty Credit Program.

An additional $50 million was allocated in the fall of 2009 for the Infrastructure Royalty Credit Program to stimulate investment in oil and gas roads and pipelines.

Land Tenure

Crude oil and natural gas located in western Canada is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms from 2 years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

In Alberta, environmental compliance is governed by the Alberta Environmental Protection and Enhancement Act. In British Columbia, environmental compliance is governed by the Environmental Assessment Act and in Saskatchewan by the Environmental Assessment Act.

Canada is a signatory to the United Nations Framework Convention on Climate Change. The Canadian federal government previously released the Regulatory Framework for Air Emissions, updated March 10, 2008 entitled Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions (collectively, the "Regulatory Framework"), for regulating greenhouse gas ("GHG") emissions by proposing mandatory emissions intensity reduction obligations on a sector by sector basis. Legislation to implement the Regulatory Framework had been expected to be put in place this year, but the federal government has delayed the release of any such legislation and potential federal requirements in respect of GHG emissions are unclear. On January 30, 2010, the Canadian federal government announced its new target to reduce overall Canadian GHG emissions by 17% below 2005 levels by 2020, from the previous target of 20% from 2006 levels by 2020, to align itself with U.S. policy. In 2009, the Canadian federal government announced its commitment to work with the provincial governments to implement a North American-wide cap and trade system for GHG emissions, in cooperation with the United States. Canada would have its own cap-and-trade market for Canadian-specific industrial sectors that could be integrated into a North American market for carbon permits.

The Canadian federal government currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. It is uncertain whether either federal GHG regulations or an integrated North American cap and trade system will or will not be implemented, or what obligations might be imposed under any such system.

As the details of the implementation of any federal legislation for GHGs have not been announced, the effect on Harvest's operations cannot be determined at this time.

Alberta regulates GHG emissions under the Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation (the "SGRR"), which imposes GHG emissions reporting requirements, and the Specified Gas Emitters Regulation (the "SGER") which imposes GHG emissions limits. Under the SGRR, Harvest must report if it has GHG emissions of 100,000 tonnes or more from a facility in any year. Under the SGER, GHG emission limits apply once a facility has direct GHG emissions in a year of 100,000 tonnes or more. Under the SGER, any facility coming into commercial production after 2000 will be considered a new facility and will be required to reduce its emission intensity (e.g. tonnes of GHGs emitted per unit of production) by 2% per year beginning in its fourth year of commercial operation. The SGER permits Harvest to meet the applicable emission limits by making emissions intensity improvements at facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring 'fund credits' by making payments of $15/per tonne to the Alberta Climate Change and Management Fund. The Alberta government recently announced its intention to raise the price of fund credits and increase the required reductions in GHG emissions intensity to unspecified levels. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations imposed in permits and under environmental regulations.

The Province of British Columbia intends to reduce its GHG emissions to 33% below 2007 levels by 2020 and has set interim targets of 6% below 2007 levels by 2012 and 18% below 2007 levels by 2016 and, accordingly, has implemented the Greenhouse Gas Reduction Targets Act. The Crown is obligated to report every second year on the amount of reductions achieved in the province, although there is no mechanism in place to measure compliance nor is there any consequence for failing to reach the target. A carbon tax was implemented on the purchase or use of fossil fuels within the Province of British Columbia, starting at $10/ton on July 1, 2008 and rising by $5 per year to $30/ton in 2012. Fuel sellers are required to pay a security equal to the tax payable on the final sale to end purchasers, and end purchasers are required to pay the tax. Fuel sellers collect carbon tax at the time fuel is sold at retail to the end purchaser. Carbon capture and storage is required for all new coal-fired electricity generation facilities and a 0.4% levy tax has been implemented at the consumer level on electricity, natural gas, grid propane and heating oil that goes towards establishing the Innovative Clean Energy Fund.

On May 11, 2009, the Province of Saskatchewan introduced Bill 95 an Act Respecting the Management and Reduction of Greenhouse Gases and Adaptation to Climate Change. The new legislation will establish a provincial plan for reducing GHG emissions to meet provincial targets and promote investments in low-carbon technologies. The Province has indicated that it intends to enter into an equivalency agreement with the federal government to achieve equivalent environmental outcomes under provincial regulation.

In 2009, following the United Nations Climate Change Conference (the “Copenhagen Summit”) Canada committed to reducing its greenhouse gas emissions by 17% below 2005 levels by 2020. However, the Federal government has not indicated how it will achieve the greenhouse gas reductions.

DOWNSTREAM BUSINESS

Harvest’s downstream business, operating under the North Atlantic trade name, is composed of a medium gravity sour crude oil hydrocracking refinery with a 115,000 barrels per stream day nameplate capacity, and a marketing division with 64 gasoline outlets, a retail heating fuels business and a commercial and wholesale petroleum products business, all located in the Province of Newfoundland and Labrador. The daily sales volume of our retail and wholesale marketing division averages over 14,000 barrels, representing approximately 43% of the Newfoundland market.

Brief History

The construction of the Refinery commenced in 1971 with the crude oil distillation unit commissioned in late 1973 and most other process units in 1974. The Refinery was shut down two years later as the owner filed for bankruptcy protection during the oil price shock. In 1980, Petro-Canada purchased the Refinery but did not operate it, and in late 1986, sold the Refinery to a third-party private company. From 1986 through 1994, the new owner invested approximately $132 million in the Refinery including the construction of a new hydrogen unit. On April 24, 1994, the Refinery experienced a fire at the vacuum tower and, as a consequence, the entire facility was again shut down as the owner was unable to finance the restoration of the Refinery.

The Vitol Refining Group B.V. (“ Vitol Group”) acquired the Refinery in August 1994 and commenced a major restoration and successfully recommissioned the Refinery in late 1994. More than US$400 million was invested to maintain, upgrade and expand the facility prior to our acquisition of the Refinery on October 19, 2006. These investments significantly improved the Refinery's operating performance in terms of refinery throughput, reliability, saleable yield, product quality, safety and environmental performance.

In 2009, the Refinery averaged 83,939 bbls/d, down from 103,497 bbls/d in the prior year. A major planned turnaround was successfully completed during the second quarter, expanding our hydrocracking capacity by an additional 1,000 barrels per stream-day. Operations in the third quarter resulted in throughputs similar to the first quarter; however, margins were considerably reduced. Fourth quarter margins were also weak and North Atlantic took advantage of this to reduce throughputs and complete maintenance activities.

Overview of Refinery Operations

The Refinery's crude oil and other feedstocks are waterborne cargos originating primarily from Iraq, Russia and Venezuela. The Refinery produces high quality gasoline, ultra low sulphur diesel, jet fuel, and furnace oil, and high sulphur fuel oil (" HSFO"). Approximately 10% of our refined products are sold in the Province of Newfoundland and Labrador while approximately 90% are export cargos sold in U.S. east coast markets, such as Boston, New York City, and Europe or farther abroad when economics justify the increased shipping charges. The Refinery enjoys a significant transportation advantage as a result of its ice-free, deep water docking facility and it has approximately seven million barrels of tankage, including six 575,000 barrel crude tanks enabling the receipt of crude oil transported on very large crude carriers which typically result in significantly lower per barrel transportation charges. North Atlantic’s dock facilities are used for off-loading refinery feedstocks and for loading refined products. The dock facilities handle approximately 220 vessels each year with North Atlantic owning and operating two tugboats to assist with berthing and unberthing tankers.

The following map illustrates the refinery’s proximity to the key Atlantic crude oil and product shipping lanes.

Refinery Feedstock

Crude oil and other feedstocks are delivered to the Refinery via waterborne cargos. Typically, there are approximately 20 days of crude oil feedstock in tankage at the Refinery to mitigate the effects of any supply disruptions. Over the past three years, the country of origin of the feedstock has been as follows:

	2009			2008			2007
	(Mbbls)			(Mbbls)			(Mbbls)

Iraq		18,098			21,218			23,230
Venezuela		4,690			7,102			5,180
Russia		5,816			5,973			3,367
Other		2,033			3,586			4,218
Total Feedstock		30,637			37,879			35,995
As % of nameplate capacity		73	%		90	%		86	%

Refined Products

Over the past three years, the Refinery has produced the following refined products:

	2009		2008		2007
	(Mbbls)		(Mbbls)		(Mbbls)

Gasoline products		10,499		12,068		11,515
Distillate products		12,196		15,668		14,406
High sulphur fuel oil(

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