Harvest Operations Corp.: Form 20-F - Filed by newsfilecorp.com

20-F 1 form20f.htm FORM 20-F Harvest Operations Corp.: Form 20-F - Filed by newsfilecorp.com

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 20-F

(Mark One)

[ ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: DECEMBER 31, 2010

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

[ ] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from n/a to n/a

Commission file number 333-121627

     HARVEST OPERATIONS CORP.
(Exact name of Registrant as specified in its charter)

             HARVEST OPERATIONS CORP.
(Translation of Registrant’s name into English)

                  ALBERTA, CANADA
(Jurisdiction of incorporation or organization)

   2100, 330 - 5th Ave. SW Calgary, Alberta, Canada T2P 0L4
(Address of principal executive offices)

John Zahary, President & CEO
2100, 330 - 5th Ave. SW Calgary, Alberta, Canada T2P 0L4
john.zahary@harvestenergy.ca
403-268-3189
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act.
(none)

Securities registered or to be registered pursuant to Section 12(g) of the Act.
(none)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
(none)

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Common shares as of December 31, 2010: 335,535,047

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

[ ] Yes [X] No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

[X] Yes [ ] No

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.*

[ ] Yes [ ] No

*Harvest Operations Corp. is a “voluntary filer” and submits this Form 20-F pursuant to its obligation under its indenture relating to its 6⅞% senior notes due October 2017.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). **

[ ] Yes [ ] No

**Harvest Operations Corp. is a “voluntary filer” and submits this Form 20-F pursuant to its obligation under its indenture relating to its 6⅞% senior notes due October 2017; therefore, this requirement is not applicable.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

[ ] Large accelerated filer

[ ] Accelerated filer

[X] Non-accelerated filer

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

[ ] U.S. GAAP
[ ] International Financial Reporting Standards as issued by the International Accounting Standards Board
[X] Other

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

[X] Item 17 [ ] Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

[ ] Yes [X] No

TABLE OF CONTENTS
		Page
GLOSSARY OF TERMS		3
ABBREVIATIONS		7
CONVERSIONS		7
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		8
NON-GAAP MEASURES		9
PREDECESSOR PRESENTATION		9
Item 1.	Identity of Directors, Senior Management and Advisers	11
Item 2.	Offer Statistics and Expected Timetable	11
Item 3.	Key Information	11
	Selected Financial Data	11
	Capitalization and Indebtedness	12
	Reasons for the Offer and Use of Proceeds	12
	Risk Factors	13
Item 4.	Information on the Company	23
	History and Development	23
	Business Overview	26
	Organizational Structure	41
	Property, Plant and Equipment	43
Item 5.	Operating and Financial Review and Prospects	47
	Operating Results	47
	Liquidity and Capital Resources	70
	Research and Development	72
	Trend Information	72
	Off-balance Sheet Arrangements	72
	Tabular Disclosure of Contractual Obligations	72
	Safe Harbor	73
Item 6.	Directors, Senior Management and Employees	73
	Directors and Senior Management	73
	Compensation	76
	Board Practices	77
	Employees	81
	Share Ownership	81
Item 7.	Major Shareholders and Related Party Transactions	81
	Major Shareholers	81
	Related Party Transactions	82
	Interest of Experts	82
Item 8.	Financial Information	82
	Consolidated Statements and Other Financial Information	82
	Significant Changes	82
Item 9.	The Offer and Listing	82
Item 10.	Additional Information	82
	Share Capital	82
	Memorandum and Articles of Association	82
	Material Contracts	84
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	89
Item 12.	Description of Securities Other than Equity Securities	89
Item 13.	Defaults, Dividend Arrearages and Delinquencies	89
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	89
Item 15.	Controls and Procedures	89
Item 16A.	Audit Committee Financial Expert	90
Item 16B.	Code of Ethics	90
Item 16C.	Principal Accountant Fees and Services	90
Item 16D.	Exemptions from the Listing Standards for Audit Committees	91
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	91
Item 16F.	Change in Registrant‘s Certifying Accountant	91
Item 16G.	Corporate Governance	91
Item 17.	Financial Statements	91
Item 18.	Financial Statements	91
Item 19.	Exhibits	91
SIGNATURES		93

GLOSSARY OF TERMS

In this annual report, 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.

“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.

“BlackGold” means the BlackGold oil sands project acquired by the Corporation from KNOC on August 6, 2010, more fully described in Note 4 to the Corporation’s audited consolidated financial statements for the year ended December 31, 2010 included in this annual report.

“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 Corporation.

“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 Corporation.

“Canadian GAAP” means accounting principles generally accepted in Canada.

“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.

“Corporation” means Harvest Operations Corp.

“Credit Facility” means the $500 million revolving credit facility, as amended, provided by a syndicate of lenders to Harvest Operations as more fully described in Note 9 to the Corporation’s audited consolidated financial statements for the year ended December 31, 2010 included in this annual report.

“Debentures” means, collectively, the 6.50% Debentures Due 2010, the 6.40% Debentures Due 2012, the 7.25% Debentures Due 2013, the 7.25% Debentures Due 2014 and the 7.50% Debentures Due 2015.

“Debenture Indenture” means, collectively (i) the trust indenture dated January 29, 2004 among 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 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.

“6.50% Debentures Due 2010” means the 6.50% convertible unsecured subordinated Debentures of the Corporation due December 31, 2010.

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

“7.25% Debentures Due 2013” means the 7.25% convertible unsecured subordinated Debentures of the Corporation due September 30, 2013.

“7.25% Debentures Due 2014” means the 7.25% convertible unsecured subordinated Debentures of the Corporation due February 28, 2014.

“7.50% Debentures Due 2015” means the 7.50% convertible unsecured subordinated Debentures of the Corporation due May 31, 2015.

“Downstream” means the Corporation’s 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 55 gasoline outlets, 3 commercial cardlock locations, 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.

“Gross” means:

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

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

	(c)	in relation to properties, the total area of properties in which Harvest and the Operating Subsidiaries have an interest.

“Harvest Board” means the board of directors of Harvest Operations.

“Harvest” and “Harvest Operations” means Harvest Operations Corp., a corporation amalgamated under the laws of the Province of Alberta.

“Independent Reserve Evaluators” means McDaniel and GLJ, who evaluated the crude oil, natural gas liquids and natural gas reserves of Harvest and the Operating Subsidiaries as at December 31, 2010, in accordance with the standards contained in the COGE Handbook and the reserve definitions and other requirements contained in NI 51-101 and Rule 4–10 of Regulation S–X.

“KNOC” means Korea National Oil Corporation.

“KNOC Acquisition” means the purchase by KNOC Canada of all of the issued and outstanding Trust Units of the Trust for total consideration of approximately $1.8 billion and the assumption of approximately $2.3 billion of debt.

“KNOC Arrangement” means the plan of arrangement for the KNOC Acquisition implemented pursuant to Section 193 of the ABCA involving, among others, the Trust, 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.

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

“Net” means:

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

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

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

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

“Note Indenture” means the trust indenture made as of October 4, 2010 between U.S. Bank National Association as trustee thereunder and Harvest Operations, providing for the issuance of the 6⅞% Senior Notes.

“NYSE” means the New York Stock Exchange.

“Operating Subsidiaries” means, collectively, Redearth Partnership (prior to September 30, 2010), Breeze Resource Partnership, Breeze Trust No. 1, Breeze Trust No. 2, and Hay River Partnership, each (other than Redearth Partnership with respect to which the Corporation held a 60% interest prior to its dissolution) a direct or indirect wholly-owned subsidiary of the Corporation, 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 Harvest and the Operating Subsidiaries in any petroleum and natural gas rights, tangibles and miscellaneous interests, including properties which may be acquired by Harvest and the Operating Subsidiaries from time to time.

“Purchase and Sale Agreement” means the purchase and sale agreement dated August 22, 2006 between the Corporation 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.

“Reserve Report” means, collectively, the reports prepared by the Independent Reserve Evaluators evaluating the crude oil, natural gas liquids and natural gas reserves of Harvest and the Operating Subsidiaries as at December 31, 2010, in accordance with the standards contained in the COGE Handbook and the reserve definitions and other requirements contained in NI 51-101 and SEC regulations.

“6⅞% Senior Notes” means the 6⅞% Senior Notes of the Corporation due October 1, 2017.

“7⅞% Senior Notes” means the 7⅞% Senior Notes of the Corporation due October 15, 2011.

“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 66⅔% 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 Item 10.C of this annual report.

“Trust” means Harvest Energy Trust.

“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.

“Trust Unit” means a trust unit of the Trust and unless the context otherwise requires means ordinary Trust Units of the Trust.

“Trust Unit Awards Incentive Plan” means the former trust unit awards incentive plan of the Trust, which ceased to be effective following completion of the KNOC Arrangement.

“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 in its capacity 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.

“Upstream” means Harvest’s petroleum and natural gas segment, consisting of the exploitation, production and subsequent sale of petroleum, natural gas and natural gas liquids in Alberta, Saskatchewan and British Columbia.

“U.S. GAAP” means accounting principles generally accepted in the United States.

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

“Viking” 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 SEC regulations and, unless the context otherwise requires, shall have the same meanings herein as in SEC regulations.

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
		GJ	gigajoule

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
ºAPI	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’s	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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this annual report 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 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 report should not be unduly relied upon. These statements speak only as of the date of this annual report or as of the date specified in the documents incorporated by reference into this annual report, as the case may be.

In particular, this annual report, and the documents incorporated by reference herein, contains forward-looking statements pertaining to:

the operation of our facilities;
expected operational and 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 Harvest’s properties;
reserve estimates and estimates of the present value of Harvest’s 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 report 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;
future interest rates, foreign exchange rates and royalty rates;
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:

global supply and demand for crude oil and natural gas;
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 production at the Refinery.

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 report and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Except as required by law, Harvest Operations does not undertake any obligation to publicly update or revise any forward-looking statements and readers should also carefully consider the matters discussed under “Item 3.D Risk Factors".

NON-GAAP MEASURES

Throughout this annual report we have referred to certain measures of financial performance that are not specifically defined under Canadian GAAP, such as “operating netbacks”, “gross margin”, “net revenue”, “earnings from operations”, “cash contributions from operations”, “cash from operations”, “total debt”, “total capitalization” and “EBITDA”. “Operating netbacks” are always reported on a per boe basis and used extensively in the Canadian energy sector for comparative purposes. “Operating netbacks” include “net revenue”, operating expenses, and transportation and marketing expenses. “Net revenues” includes revenue and royalties. “Gross margin” is commonly used in the refining industry to reflect the net funds received from the sale of refined products 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”, “cash contributions from operations” and “cash from operations” are commonly used for comparative purposes in the petroleum and natural gas and refining industries to reflect operating results before items not directly related to operations. “Total debt”, “total capitalization” and “EBITDA” are used to assist management in assessing liquidity and the Company’s ability to meet financial obligations. The non-GAAP measures may not be comparable to similar measures by other issuers.

PREDECESSOR PRESENTATION

On December 22, 2009, KNOC Canada purchased all of the issued and outstanding Trust Units of Harvest Energy Trust. The acquisition of all the issued and outstanding Trust Units of the Trust resulted in a change of control in which KNOC Canada became the sole unitholder of the Trust. On May 1, 2010, an internal reorganization was completed pursuant to which the Trust was dissolved and the Trust’s wholly owned subsidiary and the manager of the Trust, Harvest Operations Corp., was amalgamated into KNOC Canada to continue as one corporation under the name Harvest Operations Corp. The carrying values of Harvest’s assets and liabilities were determined from the existing carrying values of KNOC Canada’s assets and liabilities and therefore reflect the fair values established through the purchase. Refer to Item 4.A of this annual report for more information on the KNOC Acquisition and subsequent transactions and reorganization.

The Trust meets the definition of a predecessor as described in Exchange Act Rule 12b-2 and Securities Act Rule 405; therefore, certain historical financial information related to the Trust is included in this annual report. Accordingly, the financial information presented in this annual report for the year ended and as at December 31, 2010 is that of Harvest Operations Corp. (the successor company) while any comparative periods represent the financial information of Harvest Energy Trust (the predecessor company). As at December 31, 2009 the internal reorganization had not yet taken place; therefore, both Harvest Energy Trust and KNOC Canada existed at this date. However, KNOC Canada was incorporated on October 9, 2009 and did not have any results of operations or cash flows between October 9, 2009 and December 31, 2009, aside from capital contributions from KNOC to finance the KNOC Acquisition and cash used in the KNOC Acquisition; as such, the financial information presented for the year ended and as at December 31, 2009 is that of the Trust, unless otherwise stated, as this provides more relevant information in comparing the results of operations.

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. KEY INFORMATION A. Selected Financial Information

We have derived the financial data presented below from Harvest Operations’ and Harvest Energy Trust’s audited consolidated financial statements including those included in Item 17 of this annual report. The consolidated financial statements of Harvest Operations and the Trust have been prepared in accordance with Canadian GAAP, which differs in some material respects from U.S. GAAP. The amounts presented below reflect the adjustments made to conform with U.S. GAAP; for a discussion of the principal differences between Canadian GAAP and U.S. GAAP and the resulting adjustments, refer to the Supplemental U.S. GAAP Notes included under Item 17 of this annual report.

($000's except where noted)		2010⁽¹⁾		2009⁽²⁾			2008⁽²⁾			2007⁽²⁾			2006⁽²⁾
Income statement data
Net revenues⁽³⁾
Upstream	$	852,248	$	757,448		$	1,294,769		$	971,044		$	920,466
Downstream		2,949,930		2,381,637			4,194,595			3,098,556			460,359
Total	$	3,802,178	$	3,139,085		$	5,489,364		$	4,069,600		$	1,380,825

Earnings (loss) from operations	$	131,810	$	(603,762	)	$	550,681		$	339,430		$	236,692
Net income (loss)	$	62,732	$	(641,906	)	$	(1,343,337	)	$	159,194		$	(468,841	)
Net income (loss) per common share or Trust Unit
Basic	$	0.21	$	(3.69	)	$	(8.79	)	$	1.15		$	(4.61	)
Diluted	$	0.21	$	(3.69	)	$	(8.79	)	$	1.14		$	(4.61	)

Distributions/dividends declared	$	-	$	164,770		$	551,325		$	610,280		$	468,787
Distributions/dividends declared - U.S. dollars⁽⁴⁾	$	-	$	143,449		$	514,496		$	572,199		$	414,548
Distributions declared, per Trust Unit	$	-	$	1.00		$	3.60		$	4.40		$	4.53

Balance sheet data
Total assets	$	4,536,433	$	2,476,415		$	3,561,515		$	4,953,634		$	5,139,247
Net assets	$	2,498,813	$	(2,073,824	)	$	(997,695	)	$	(976,476	)	$	(638,690	)
Shareholders’ capital	$	3,355,350	$	-		$	-		$	-		$	-
Temporary equity	$	-	$	2,422,133		$	1,562,806		$	2,997,136		$	2,680,017

Capital expenditures
Upstream	$	953,911	$	124,160		$	400,085		$	438,830		$	2,843,978
Downstream		71,234		43,875			56,162			44,111			1,619,369
Total	$	1,025,145	$	168,035		$	456,247		$	482,941		$	4,463,347

Share data
Weighted average common shares outstanding
Basic and diluted		303,005,645		-			-			-			-
Weighted average Trust Units outstanding
Basic		-		173,785,806			152,836,717			138,440,869			101,590,850
Diluted		-		173,785,806			152,836,717			139,088,543			101,590,850

⁽¹⁾	The financial data is derived from Harvest Operations’ audited financial statements and Item 17 US GAAP reconciliation
⁽²⁾	The financial data is derived from Harvest Energy Trust’ audited financial statements and Item 17 US GAAP reconciliation
⁽³⁾	These are non-GAAP measures; please refer to “Non-GAAP Measures” in this annual report
⁽⁴⁾	Translated using the average noon buying rate as disclosed in “Exchange Rate Information” under Item 3.A below

EXCHANGE RATE INFORMATION

All dollar amounts set forth in this annual report 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 exchange rate information presented below is based on the Bank of Canada noon rates. Such rates are set forth as U.S. dollars per $1.00.

The exchange rate between the Canadian dollar and the U.S. dollar on June 29, 2011 was US$1.0304.

The high and low exchange rates between the Canadian dollar and the U.S. dollar for each month during the previous six months are as follows:

	High	Low
May	1.0537	1.0195
April	1.0542	1.0319
March	1.0324	1.0083
February	1.0268	1.0045
January	1.0140	0.9978
December	1.0054	0.9825

The average exchange rates between the Canadian dollar and the U.S. dollar for the five most recent financial years are as follows:

	Average
2010	0.9706
2009	0.8706
2008	0.9332
2007	0.9376
2006	0.8843

B. Capitalization and Indebtedness

Not applicable.

C. Reasons for the Offer and Use of Proceeds

Not applicable.

D. Risk Factors

Both the Upstream and Downstream operations are conducted in the same business environment as most other operators in the respective businesses. The risk factors set forth below have been separated into those applicable to Upstream operators, those applicable to Downstream operators and those applicable to Harvest’s structure.

RISKS RELATED TO THE UPSTREAM OPERATIONS

Prices received for petroleum and natural gas have fluctuated widely in recent years and are also impacted by volatility in the Canadian/U.S. currency exchange ratio.

Cash flow from the Upstream Operations is dependent on the prices received from the sale of petroleum, natural gas and natural gas liquids production. Prices for petroleum, natural gas and natural gas liquids have fluctuated widely during recent years and are determined by supply and demand factors beyond the Corporation’s control, including weather, general economic conditions, conditions in other oil producing regions, market uncertainty, the availability of alternative fuel sources, actions of the Organization of Petroleum Exporting Countries (“OPEC”), the price of foreign imports of crude oil and gas, concern over climate changes or greenhouse gas (“GHG”) emissions and government regulations. Oil prices received from production in Canada also reflect changes in the Canadian/U.S. currency exchange rate. A decline in petroleum and/or natural gas prices or an increase in the Canadian/U.S. currency exchange rate could have a material adverse effect on the Corporation’s cash from operating activities and financial condition as well as funds available for the development of its petroleum and natural gas reserves.

Any prolonged period of low oil and natural gas prices could result in a material reduction of Harvest’s operating and financial results, production revenue, reserves and overall value and may lead to a decision by the Corporation to suspend or reduce production. Any such suspension or reduction of production would result in a corresponding substantial decrease in revenues and earnings and could materially impact Harvest’s ability to meet its debt servicing obligations and could expose the Corporation to significant additional expense as a result of any future long-term contracts. If production was not suspended or reduced during such period, the sale of the petroleum products produced by Harvest at such reduced prices would lower its revenues.

Harvest conducts an assessment of the carrying value of its assets to the extent required by Canadian GAAP. If crude oil and/or natural gas prices decline, the carrying value of Harvest’s assets could be subject to downward revision and the Corporation’s earnings could be adversely affected. The substantial volatility in crude oil prices over recent years has affected the profitability of the oil and gas industry and Harvest. Although under Canadian GAAP Harvest did not incur any “ceiling test” write downs of the oil and gas assets or impairment charges to other assets in 2010, there can be no assurance that further declines in crude oil prices or other circumstances will not result in such “ceiling test” write downs or impairment charges at some future date.

The differential between light oil and heavy oil compounds the fluctuations in benchmark oil prices.

At the end of 2010, Harvest’s production was approximately 54% light and medium gravity crude oil, 19% heavy oil and 27% natural gas. Processing and refining heavy oil is more expensive than processing and refining light oil and accordingly, producers of heavy oil receive lower prices for their production. The differential between light oil and heavy oil has fluctuated widely during recent years and when compounded with the fluctuations in the benchmark prices for light oil, the result is a substantial increase in the volatility of heavy oil prices. An increase in the heavy oil differential usually results in us receiving lower prices for Harvest’s heavy oil and could have a material adverse effect on the Corporation’s cash from operating activities and financial condition as well as funds available for the development of the Corporation’s petroleum and natural gas reserves. The heavy oil price differential is normally the result of the seasonal supply and demand for heavy oil, pipeline constraints and heavy oil processing capacity of refineries, all of which are beyond Harvest’s control.

The operation of petroleum and natural gas properties involves a number of operating and natural hazards which may result in blowouts, environmental damage and other unexpected and/or dangerous conditions against which Harvest may not be insured or that may result in damages in excess of existing insurance coverage.

The operation of oil and natural gas wells involves a number of operating and natural hazards which may result in blowouts, explosions, fire, gaseous leaks, migration of harmful substances, spills, environmental damage and other unexpected and/or dangerous conditions resulting in damage to Harvest’s assets and potentially assets of third parties. In addition, all of Harvest’s operations are subject to all of the risks normally incident to the transportation, processing and storing of crude oil, natural gas and other related products, drilling and completion of crude oil and natural gas wells, and the operation and development of crude oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks. Harvest’s corporate EH&S manual has a number of specific policies to minimize the risk of environmental contamination, including emergency response should an incident occur. If areas of higher risk are identified, Harvest will undertake to analyze and recommend changes to reduce the risk including replacement of specific infrastructure. Harvest employs prudent risk management practices and maintains liability insurance in amounts consistent with industry standards. In addition, business interruption insurance has been purchased for selected facilities. The Corporation may become liable for damages arising from such events against which it cannot insure, which it may elect not to insure or that may result in damages in excess of existing insurance coverage. Costs incurred to repair such damage or pay such liabilities will reduce Harvest’s cash flow. The occurrence of a significant event against which the Corporation is not fully insured could have a material adverse effect on Harvest’s financial position.

The operation of petroleum and natural gas properties requires physical and equipment on a regular basis, which could be affected by factors beyond the Corporation’s control.

Access for people and equipment may be restricted due to weather, accidents, natural disasters, government regulations or third party actions. Because of these factors, Harvest may be unable to develop or produce from its petroleum or natural gas properties.

If the third party operators of Harvest’s joint venture properties fail to perform their duties properly, production may be reduced and proceeds from the sale of production may be negatively impacted.

Continuing production from a property and to a certain extent, the marketing of production therefrom, are largely dependent upon the capabilities of the operator of the property. To the extent the operator fails to perform its duties properly, production may be reduced and proceeds from the sale of production from properties operated by third parties may be negatively impacted. Although Harvest maintains operative control over the majority of its properties, there is no guarantee that the Corporation will remain operator of such properties or that the Corporation will operate other properties that may be acquired.

Harvest is subject to risks related to deregulation of electrical power systems and the volatility of electrical power prices.

A portion of Harvest’s operating expenses are electrical power costs. As a result of the deregulation of the electrical power system in Alberta, electrical power prices have been set by the market based on supply and demand and recently, electrical power prices in Alberta have been volatile. To mitigate the Corporation’s exposure to the volatility in electrical power prices, it may enter into fixed priced forward purchase contracts for a portion of the Corporation’s electrical power consumption in Alberta. In respect of the operations in Saskatchewan, the Saskatchewan power system is regulated and as such, electrical power costs are not subject to significant volatility. However, there can be no certainty that the Saskatchewan power system will not deregulate in the future.

Defects in title may defeat Harvest’s claims to certain properties.

Although title reviews will generally be conducted on the properties in accordance with industry standards, such reviews do not guarantee or certify that a defect in title may not arise to defeat Harvest’s claim to certain properties. If such were the case, Harvest’s entitlement to the production and reserves associated with such properties could be jeopardized, which could have a material adverse effect on the Corporation’s financial condition and results of operations.

The markets for petroleum and natural gas depend upon available capacity to refine crude oil and process natural gas, pipeline capacity to transport the products to customers, and other factors beyond the Corporation’s control.

Harvest’s ability to market petroleum and natural gas from its wells depends upon numerous factors beyond the Corporation’s control, including:

the availability of capacity to refine heavy oil;
the availability of natural gas processing capacity;
the availability of pipeline capacity;
the availability of diluent to blend with heavy oil to enable pipeline transportation;
the price of oilfield services;
the accessibility of remote areas to drill and subsequently service wells and facilities; and
the effects of inclement weather.

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

The reservoir and recovery information in reserve reports are estimates and actual production and recovery rates may vary from the estimates and the variations may be significant.

The reserve and recovery information contained in the Reserve Report prepared by the Independent Reserve Evaluators (the “Reserve Report”) are complex estimates and the actual production and ultimate reserves recovered from the Corporation’s properties may differ from the estimates prepared by the independent reserve engineering evaluators. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves, including many factors beyond the Corporation’s control. The reserves data in this annual report represents estimates only. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows are based upon a number of variable factors and assumptions, such as product prices, future operating and capital costs, historical production from the properties and the assumed effects of regulation by governmental agencies (including regulations related to royalty payments), all of which may vary considerably from actual results. All such estimates are to some degree uncertain, and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Harvest’s actual production, revenues, taxes and development and operating expenditures with respect to the Corporation’s reserves may vary from such estimates, and such variances could be material.

Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations, probabilistic methods and upon analogy to similar types of reserves or resources, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves or resources based upon production history will result in variations, which may be material, in the estimated reserves or resources.

The reserve value of Harvest’s Properties as estimated by Independent Reserve Evaluators is based in part on cash flows to be generated in future years as a result of future capital expenditures. The reserve value of the properties as estimated by the Independent Reserve Evaluators may not be realized to the extent that such capital expenditures on the properties do not achieve the level of success assumed in such engineering reports.

Prices paid for acquisitions are based in part on reserve report estimates and the assumptions made in preparing the reserve report are subject to change as well as geological and engineering uncertainty.

The prices paid for acquisitions were based, in part, on engineering and economic assessments made by the independent reserve engineering evaluators in the related reserve report. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of crude oil, natural gas and natural gas liquids, future prices of oil, natural gas and natural gas liquids, operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond Harvest’s control. In particular, the prices of and markets for petroleum and natural gas may change from those anticipated at the time of making such acquisitions. In addition, all engineering assessments involve a measure of geological and engineering uncertainty which could result in lower production and reserves than those currently attributed to Harvest’s properties.

Absent capital reinvestment, production levels from petroleum and natural gas properties will decline over time and absent commodity price increases, cash generated from operating these assets will also decline.

Harvest’s cash from operating activities, absent commodity price increases or cost effective acquisition and development activities of properties, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. Accordingly, absent additional capital investment from other sources, production levels and reserves attributable to Harvest’s properties will decline.

Harvest’s future oil and natural gas reserves and production, and therefore Harvest’s cash flows, will be highly dependent on the Corporation’s success in exploiting its resource base and acquiring additional reserves. Without reserve additions through acquisition or development activities, Harvest’s reserves and production will decline over time as reserves are produced. There can be no assurance that Harvest will be successful in developing or acquiring additional reserves on terms that meet its investment objectives.

Harvest may be adversely affected by changes in income and capital tax laws, government incentive programs and regulations relating to the petroleum and natural gas industry.

There can be no assurance that income and capital tax laws, government incentive programs and regulations relating to the petroleum and natural gas industry, such as environmental and operating regulations, will not change in a manner which adversely affects the Corporation.

Harvest will be responsible for abandonment and reclamation costs which may be substantial.

Harvest will be responsible for compliance with terms and conditions of environmental and regulatory approvals and all laws and regulations regarding the abandonment and reclamation of the surface leases, wells, facilities and pipelines at the end of their economic life as well as those for any future expansions. Abandonment and reclamation costs may be substantial. A breach of such legislation and/or regulations may result in the imposition of fines and penalties, including an order for cessation of operations at the site until satisfactory remedies are made. It is not possible to accurately predict the abandonment and reclamation costs since they will be a function of regulatory requirements at the time and the value of the salvaged equipment may be more or less than the abandonment and reclamation costs. In addition, in the future Harvest may determine it prudent or may be required by applicable laws, regulations or regulatory approvals to establish and fund one or more reclamation funds to provide for payment of future abandonment and reclamation costs. See “Business—Other Upstream Business Information—Additional Information Concerning Abandonment and Reclamation Costs.”

Harvest’s operating cash flows will be directly affected by the applicable royalty regime.

Harvest is currently required to pay a royalty to the Governments of the Provinces of British Columbia, Alberta and Saskatchewan on Harvest’s oil and natural gas production. These royalty regimes may be amended or supplemented from time to time. For example, the Province of Alberta implemented a new royalty regime effective January 1, 2009 and a program for royalty adjustments for new horizontal wells in 2010. To the extent that royalty regimes are sensitive to commodity prices, the impact on Harvest of any such regime, or any amendment thereto, cannot be accurately predicted.

Harvest will be subject to risks related to the BlackGold Oil Sands Project.

The development of the BlackGold oil sands project requires substantial capital investment to develop the asset. While Harvest makes every effort to properly and accurately forecast capital and operating expenditures, the possibility remains that capital cost overruns or schedule delays will occur as a result of fluctuating market conditions and unexpected challenges. Such cost overruns and schedule delays have the potential to affect the Corporation’s future financial position and cash flows. As is the case with any large scale, technically complex project, the ongoing development of BlackGold subjects Harvest to risks associated with scheduling delays and unforeseen technical challenges. Working with a variety of vendors and suppliers, that in some cases are transporting materials across great distances, increases the risk of delays. During the third quarter of 2010, Harvest signed an engineering, procurement and fixed price construction contract with a third party to build required facilities at the BlackGold project site, including the central processing facility. To the extent that the third party fails to perform its duties as expected, risk remains that design objectives may be not be achieved and production may be reduced and/or delayed.

The BlackGold project is subject to government regulation. The initial phase of the project, targeting production of 10,000 bbl/d, has been approved by provincial regulators. The proposed expansion phase of the BlackGold project is in the application stage and remains subject to approval by provincial regulators. The delay of such approval could impact Harvest’s ability and/or timing of reaching the targeted production of 30,000 bbl/d.

Industry competition

There is strong competition relating to all aspects of the petroleum and natural gas industry. The Upstream operations actively compete for capital, skilled personnel, undeveloped land, acquisitions, access to drilling rigs, service rigs and other equipment, access to processing facilities and pipeline and refining capacity, and in all other aspects of the Upstream operations with a substantial number of other petroleum and natural gas organizations, many of which may have greater technical and financial resources than us. Some of those organizations carry on a more diverse set of petroleum and natural gas related operations and market petroleum and other products on a world-wide basis and as such have greater and more diverse resources on which to draw.

RISKS RELATED TO HARVEST'S DOWNSTREAM OPERATIONS

The market prices for crude oil and refined products have fluctuated significantly, the direction of the fluctuations may be inversely related and the relative magnitude may be different, resulting in volatile refining margins.

The Downstream earnings and cash flows from refining and wholesale and retail marketing operations are dependent on a number of factors including fixed and variable expenses (including the cost of crude oil and other feedstocks) and the price at which Harvest are able to sell refined products. In recent years, the market prices for crude oil and refined products have fluctuated substantially. These prices depend on a number of factors beyond Harvest’s control, including the supply and demand for crude oil and refined products, which are subject to, among other things:

changes in the global demand for crude oil and refined products;
the level of foreign and domestic production of crude oil and refined products and their price;
threatened or actual terrorist incidents, acts of war, and other worldwide political conditions in both crude oil producing and refined product consuming regions;
the availability of crude oil and refined products and the infrastructure to transport crude oil and refined products;
supply and operational disruptions including accidents, weather conditions, hurricanes or other natural disasters;
concern over climate change or GHG emissions;
actions of the OPEC;
government regulations including changes in fuel specifications required by environmental and other laws;
local factors including market conditions and the operations of other refineries in the markets in which Harvest competes; and
the development and marketing of competitive alternative fuels.

The Downstream operations are also sensitive to refined products margins. In addition to the factors above, margin volatility is also impacted by numerous conditions including: labor, maintenance, electricity, chemicals and other inputs, unplanned production disruptions due to equipment failure, power disruptions and other factors including weather. It is expected that all of these and other factors will continue to impact Downstream margins for the foreseeable future. As a result, it can be reasonably expected that Downstream results will fluctuate over time and from period to period.

Generally, fluctuations in the price of gasoline and other refined products are correlated with fluctuations in the price of crude oil; however, the prices for crude oil and prices for refined products can fluctuate in different directions as a result of worldwide market conditions. Further, the timing of the relative movement in prices as well as the magnitude of the change could significantly influence refining margins as could price changes occurring during the period between purchasing crude oil feedstock and selling refined products manufactured from the feedstock. Harvest does not produce crude oil that can be economically transported to the Refinery and, as a result, purchase all of its crude oil feedstock at prices that fluctuate with worldwide market conditions and this could significantly impact Harvest’s earnings and cash flows. Harvest also purchases refined products from third parties for sale to its customers and price changes during the period between purchasing and selling these products could also have a material adverse effect on Harvest’s business and results of operations, as well as its financial condition and cash from operating activities.

Harvest purchases approximately 250,000 megawatt hours of electrical power from Newfoundland and Labrador Hydro, a provincial crown corporation. A substantial proportion of Newfoundland and Labrador Hydro’s electricity is generated by hydroelectric power, a relatively inexpensive source compared to fossil fuel generators. The Refinery’s cost of electrical power has remained relatively constant averaging $0.0415 per kilowatt hour in 2010. Electricity prices have been and will continue to be affected by supply and demand for service in both local and regional markets and continued price increases could also have a material adverse effect on Harvest’s business and results of operations, as well as its financial condition and the cash from operating activities.

The prices for crude oil and refined products are generally based in U.S. dollars while Harvest’s operating costs are denominated in Canadian dollars, which introduces currency exchange rate exposure.

The prices for crude oil and refined products are generally based on market prices in U.S. dollars while Harvest’s Downstream operating costs and capital expenditures are primarily in Canadian dollars. Fluctuations in the exchange rates between the U.S. and Canadian dollar result in currency exchange rate exposure. Although this currency exchange rate exposure may be hedged, there can be no assurance that a currency exchange rate risk management program will effectively cover all of Harvest’s exposure.

Crude oil feedstock is delivered to the Refinery via waterborne vessels which could experience delays in transporting supplies due to weather, accidents, government regulations or third party actions.

The Refinery receives all of its crude oil and other feedstocks and its customers lift approximately 90% of its refined products via water borne vessels including very large crude carriers. In addition to environmental risks of handling such vessels discussed below, Harvest could experience a disruption in the supply of crude oil because of accidents, governmental regulation or third party actions. A prolonged disruption in the availability of vessels to deliver crude oil to the Refinery and/or to deliver refined products to market would have a material adverse effect on Harvest’s business and results of operations, as well as the financial condition and cash from operating activities.

Since Harvest’s acquisition of North Atlantic, over 68% of its crude oil feedstock has been from sources in the Middle East. The Corporation does not maintain supply commitments with any of its crude oil producers. To the extent that crude oil producers reduce the volume of crude oil produced as a result of declining production or competition or otherwise, the business, financial condition and results of operations may be adversely affected to the extent that the Corporation is not able to find a substantial amount and similar type of crude oil. Further, the Corporation has no control over the level of development in the fields that currently produce the crude oil it process at the Refinery nor the amount of reserves underlying such fields, the rate at which production will decline or the production decisions of the producers which are affected by, among other things, prevailing and projected crude oil prices, demand for crude oil, geological considerations, government regulation and the availability and cost of capital.

If Vitol terminates the SOA prior to expiration or does not agree to renew the SOA upon expiration, Harvest’s business could be adversely affected.

Under the SOA, the Refinery receives all of its feedstock from Vitol and sells almost all of the refined product produced to Vitol. If Vitol terminates the SOA prior to expiration or does not agree to renew the SOA upon expiration, Harvest would seek to enter into a similar agreement with another party that has a similar credit profile or expertise to that of Vitol’s. If Harvest were unable to enter into such a replacement agreement, it would be required to enter into separate agreements for the supply of feedstock to the Refinery and the sale of the Refinery’s refined products. No assurance can be given that Harvest will be able either to enter into an agreement similar to the SOA with another party or to enter into agreements with a number of different parties to replicate the economics of the SOA. If the SOA were terminated and Harvest was unable to enter into replacement agreements, revenues and cash flows from the Refinery would likely decrease, which could have a material adverse affect on Harvest’s business.

Harvest is relying on the creditworthiness of Vitol for Harvest’s purchase of feedstock and should their creditworthiness deteriorate, crude oil suppliers may restrict the sale of crude oil to Vitol.

Vitol purchases Harvest’s crude oil feedstock pursuant to the SOA and Harvest enters into price risk management contracts to reduce exposure to adverse fluctuations in the prices of crude oil and refined products. Accordingly, should Harvest’s creditworthiness or the creditworthiness of Vitol deteriorate, crude oil producers and suppliers as well as financial counterparties may change their view on contracting with us for the supply of crude oil and/or price risk management contracts, respectively, and induce them to shorten the payment terms or require additional credit support, such as letters of credit. Due to the large dollar amount of credit associated with the volume of crude oil purchases and long-term price risk management contracts, any imposition of more burdensome payment terms may have a material adverse effect on Harvest’s financial liquidity which could hinder its ability to purchase sufficient quantities of crude oil to operate the Refinery at full capacity. In addition, if the price of crude oil increases significantly, the credit requirements to purchase enough crude oil to operate the Refinery at full capacity will also increase. A failure to operate the Refinery at full capacity could have an adverse material effect on its business and results of operations, as well as its financial condition and cash from operating activities.

The Refinery is a single train integrated interdependent facility which could experience a major accident, be damaged by severe weather or otherwise be forced to shutdown which may reduce or eliminate Harvest’s cash flow.

The Refinery is a single train integrated and interdependent facility which could experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down. A shutdown of one part of the Refinery could significantly impact the production of refined products and may reduce, and even eliminate, cash flow. Any one or more of the Refinery’s processing units may require a planned turnaround or encounter unexpected downtime for maintenance or repair and the time required to complete the work may take longer than anticipated. There are no assurances that the Refinery will produce refined products in the quantities or at the cost anticipated, or that it will not cease production entirely in certain circumstances, which could have a material adverse effect on Harvest’s business and results of operations, as well as its financial condition and cash from operating activities.

Harvest’s refining operations are adjacent to environmentally sensitive coastal waters, and are subject to hazards and similar risks such as fires, explosions, spills and mechanical failures, any of which may result in personal injury, damage to Harvest’s property and/or the property of others along with significant other liabilities in connection with a discharge of materials.

Harvest’s refining operations, including the transportation of and storage of crude oil and refined products, are subject to hazards and inherent risks typical of similar operations such as fires, natural disasters, explosions, spills and mechanical failure of the equipment or third-party facilities, any of which can result in personal injury claims as well as damage to Harvest’s properties and the properties of others. While Harvest carries property, casualty and business interruption insurance, the Corporation does not maintain insurance coverage against all potential losses, and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on Harvest’s business and results of operations, as well as its financial condition and cash from operating activities. Currently, the Corporation has the opportunity and intends to consider opportunities to grow its business through the reconfiguration and enhancement of its Refinery assets with the suite of expansion or debottlenecking projects. However, if unanticipated costs occur or the revenues decrease as a result of lower refining margins, operating difficulties or other matters, there may not be sufficient capital to enable us to fund all required capital and operating expenses. There can be no assurance that cash generated by Harvest’s operations or funding available from debt financings will be available to meet its capital and operating requirements.

The operation of refineries and related storage tanks is inherently subject to spills, discharges or other releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of Harvest’s storage tanks, or in connection with any facilities to which the Corporation sends wastes or byproducts for treatment or disposal, other than events for which the Corporation are indemnified, the Corporation could be liable for all costs and penalties associated with their remediation under federal, provincial and local environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills. The penalties and clean-up costs that the Corporation may have to pay for releases or spills, or the amounts that the Corporation may have to pay to third parties for damage to their property, could be significant and the payment of these amounts could have a material adverse effect on the Corporation’s business and results of operations, as well as its financial condition and cash from operating activities.

Harvest operates in environmentally sensitive coastal waters where tanker operations are closely regulated by federal, provincial and local agencies and monitored by environmental interest groups. Transportation of crude oil and refined products over water involves inherent risk and subjects us to the provisions of Canadian federal laws and the laws of the Province of Newfoundland and Labrador. Among other things, these laws require us to demonstrate Harvest’s capacity to respond to a “worst case discharge” to a maximum 10,000 metric tonne oil spill. Harvest’s marine division manages vessel traffic to the Refinery and works with regulatory authorities on measures to prevent and mitigate the risk of oil spills and other marine related matters. The marine division has two tugboats to assist in berthing and unberthing tankers at Harvest’s dock with one tugboat equipped with fire fighting capability. The tugboat operations have a safety management system certified under the International Safety Management Code and are also certified under the International Ship and Port Security Code. In addition, Harvest has contracted with the Eastern Canada Response Corporation to supplement Harvest’s resources. However, there may be accidents involving tankers transporting crude oil or refined products, and response services may not respond in a manner to adequately contain a discharge and Harvest may be subject to a significant liability in connection with a discharge.

Harvest has in the past operated service stations with underground storage tanks and currently operates 55 retail gasoline stations and three commercial cardlock locations with underground storage tanks in the Province of Newfoundland and Labrador. Harvest is required to comply with provincial regulations governing such storage tanks in the Province of Newfoundland and Labrador and compliance with these requirements can be costly. The operation of underground storage tanks also poses certain other risks, including damages associated with soil and groundwater contamination. Leaks from underground storage tanks which may occur at one or more of Harvest’s service stations, or which may have occurred at previously operated service stations, may impact soil or groundwater and could result in fines or civil liability. While Harvest maintains insurance in respect of such risks, there are no assurances that such insurance will be adequate to fully compensate for any liability Harvest may incur if such risks were to occur.

The production of aviation fuels subjects us to liability should contaminants in the fuel result in aircraft engines being damaged and/or aircraft accidents.

The Corporation produces aviation fuels, which involves inherent risks and subjects it to the provisions of Canadian federal laws. Harvest’s product quality assurance programs are extensive; however, these procedures may not be sufficient to detect and prevent contaminants from entering into the aviation fuels which could result in aircraft engines being damaged and/or aircraft accidents. While the Corporation maintains insurance in respect of such risks, there are no assurances that such insurance will be adequate to fully compensate for any liability the Corporation may incur if such risks were to occur.

Refinery operations are subject to environmental regulation pursuant to local, provincial and federal legislation and require us to obtain and maintain regulatory approvals. A breach of such legislation may subject us to substantial liability and result in the imposition of fines as well as higher operating standards that may increase costs.

The Downstream operations and related properties are subject to extensive federal, provincial and local environmental and health and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management and characteristics and composition of gasoline and diesel fuels. If the Corporation fails to comply with these regulations, it may be subject to administrative, civil and criminal proceedings by governmental authorities as well as civil proceedings by environmental groups and other entities and individuals. A failure to comply, and any related proceedings, including lawsuits, could result in significant costs and liabilities, penalties, judgments against us or governmental or court orders that could alter, limit or stop the operations.

Consistent with the experience of other Canadian refineries, environmental laws and regulations have raised operating costs and required significant capital investments at the Refinery. Harvest believes that the Refinery is materially compliant with existing laws and regulatory requirements. However, material expenditures could be required in the future for the Refinery to comply with evolving environmental, health and safety laws, regulations or requirements that may be adopted or imposed in the future.

The Refinery operates under permits issued by the federal and provincial governments and these permits must be renewed periodically. The federal and provincial governments may make operating requirements more stringent which may require additional spending.

In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make unanticipated expenditures in the Downstream Operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. Harvest is not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, there could be a material adverse effect on Harvest’s business and results of operations as well as its financial condition and cash from operating activities.

Harvest is presently subject to litigation and investigations with respect to the use of methyl tertiary butyl ether (“MTBE”) and the delivery of contaminated sulphur and although indemnified by the previous owner, with respect to the MTBE litigation, there is no assurance that such indemnity will be sufficient to offset Harvest’s costs and liabilities. Harvest may become involved in further litigation or other proceedings, or may be held responsible in any existing or future litigation or proceedings, the costs of which could be material.

Collective bargaining agreements with Harvest’s employees and the United Steel Workers of America with respect to the Downstream operations may not prevent a strike or work stoppage and future agreements may result in an increase in operating costs.

As of December 31, 2010, Harvest had approximately 444 full-time employees and 37 part-time employees in the Downstream operations of which approximately 66% and 95%, respectively, are represented by the United Steel Workers of America pursuant to collective bargaining agreements. The Corporation may not be able to renegotiate future collective agreements on satisfactory terms, or at all, which may result in an increase in operating costs. In addition, the existing collective agreements may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse effect on the Downstream business and Harvest’s results of operations as well as the financial condition and cash from operating activities.

The demand for skilled labor remains high in Newfoundland and the supply of skilled labor remains limited.

There is a risk that our Downstream operations may have difficulty in sourcing skilled labor and the cost of replacement labor would result in increased operating and capital costs.

RISKS RELATED TO HARVEST’S STRUCTURE

Debt Service and Repayment

As of May 31, 2011, Harvest had indebtedness of approximately $95 million under the Credit Facility. In addition, letters of credit have been issued to third parties totaling approximately $6.8 million on behalf of Harvest Operations to secure services for its Upstream operations. The principal amount outstanding under the 6⅞% Senior Notes was $US500 million, and semi-annual interest payments of approximately $US17.2 million are payable April 1 and October 1. The principal amount of Debentures outstanding totaled $734 million. Interest is paid semi-annually on the dates prescribed by the applicable trust indenture for each series of Debentures.

Under the Credit Facility, Harvest Operations and certain subsidiaries of Harvest Operations (designated as restricted subsidiaries) have provided the lenders security over all of the assets of Harvest Operations and of the restricted subsidiaries, excluding the BlackGold assets. If an event of default (as defined under the Credit Facility) has occurred the lenders may demand repayment and exercise rights under the security, including sale of the secured assets. Certain payments by Harvest or the restricted subsidiaries are prohibited upon an event of default. Any indebtedness of Harvest or of restricted subsidiaries which is owed to a restricted subsidiary is subordinate to payments to lenders pursuant to the Credit Facility, under subordination agreements between the lenders and the restricted subsidiaries.

Harvest must meet certain ongoing financial and other covenants under each of the Credit Facility and the Note Indenture. The covenants include customary provisions and restrictions related to Harvest Operations’ and the restricted subsidiaries' operations and activities, and are described further for each of the Credit Facility and the Note Indenture in Item 10.C of this annual report.

Harvest is permitted to borrow funds to finance the purchase of assets, incur capital expenditures, repay other obligations and finance working capital. Variations in interest rates could result in significant changes in the amount required to be applied to debt service.

Interest and principal amounts payable pursuant to the 6⅞% Senior Notes are payable in U.S. dollars. Harvest is permitted to borrow funds under the Credit Facility in U.S. dollars and would be required to settle interest and principal amounts in the same currency. Variations in the Canadian/U.S. currency exchange rate could result in a significant increase in the amount of the interest and principal payments under the Credit Facility and the 6⅞% Senior Notes.

Access to External Capital Resources

There is a risk that the Corporation will not be able to meet the covenants associated with its indebtedness, repay all or part of its indebtedness, or refinance all or part of its indebtedness on commercially reasonable terms. The occurrence of any one of these events may have a significant adverse effect on the Corporation’s ability to access external capital resources. As well, to the extent that external capital, including debt financing, from banks or other creditors, becomes limited, unavailable or available on less economic terms, Harvest’s ability to fund the necessary capital investments to maintain, develop, and/or expand its petroleum and/or natural gas reserves, continue construction on its BlackGold assets and to debottleneck its refinery operations will be impaired.

Reliance on Management of Harvest Operations

Holders of securities of Harvest will be dependent on the management of Harvest Operations in respect of the administration and management of all matters relating to Harvest and the Operating Subsidiaries and the Properties. Investors who are not willing to rely on the management of Harvest Operations should not invest in the Corporation.

Re-assessment of Prior Years’ Income Tax Returns

From time to time, Harvest Operations may take steps to organize its affairs in a manner that minimizes taxes and other expenses payable with respect to the operation of the Corporation and the Operating Subsidiaries. Harvest’s prior years’ income tax and royalty filings are subject to reassessment by government entities. The reassessment of previous filings may result in additional income tax expenses, royalties, interest and penalties which may adversely affect the Corporations cash flows, results from operation and financial position.

In January 2009 Canada Revenue Agency issued a Notice of Reassessment to the Trust and to Harvest Sask Energy Trust (“HSET”) in respect of their 2002 through 2004 taxation years, claiming past taxes, interest and penalties totaling $6.2 million for the Trust and $1.2 million for HSET. The CRA adjusted the Trust’s and HSET’s taxable income to include their net profits interest royalty income on an accrual basis, whereas the tax returns filed by the Trust and HSET had reported this revenue on a cash basis. A Notice of Objection was filed with CRA requesting the adjustments to an accrual basis be reversed followed by Notices of Appeal filed by the Trust and HSET in the Tax Court of Canada with respect to tax years 2003 and 2004. On January 25, 2011, CRA indicated that they will not pursue the original reassessments, and CRA, HSET and the Trust have since agreed, pursuant to minutes of settlement, to the issuances of new reassessments to reverse the effect of the original reassessments, to resolve all outstanding issues relating thereto, and to deal with other adjustments not related to the original reassessment. On April 29, 2011 the reassessments were issued.

Risk Management Activities

The nature of Harvest’s operations results in exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. The Corporation monitors its exposure to such fluctuations and, where deemed appropriate, utilizes derivative financial instruments and physical delivery contracts to help mitigate the potential impact of declines in crude oil, natural gas and refined product prices, changes in interest rates and foreign exchange rates. The utilization of derivative financial instruments may introduce significant volatility into Harvest’s reported net earnings, comprehensive income and cash flows. The terms of our various hedging agreements may limit the benefit to the Corporation of commodity price increases or changes in interest rates and foreign exchange rates. The Corporation may also suffer financial loss because of hedging arrangements if:

Harvest is unable to produce oil, natural gas or refined products to fulfill delivery obligations;
Harvest is required to pay royalties based on market or reference prices that are higher than hedged prices; or
counterparties to the hedging agreements are unable to fulfill their obligations under the hedging agreements.

To the extent that Harvest engages in these risk management activities, Harvest will be subject to counterparty risk.

Adoption of International Financial Reporting Standards

Effective January 1, 2011, Harvest is required to adopt the International Financial Reporting Standards ("IFRS") which may result in materially different reported financial results and may require amendments to its credit agreements to reflect the changes in accounting principles. The financial impact of transitioning to IFRS is summarized in Note 22 of the unaudited consolidated financial statements dated March 31, 2011 filed on www.sec.gov/edgar.shtml on June 20, 2011

ITEM 4. INFORMATION ON THE COMPANY A. History and Development of the Company

Harvest Operations was incorporated under the ABCA on May 14, 2002. All of the issued and outstanding common shares of Harvest Operations are owned by KNOC. Established in 1979, KNOC is a leading international oil and gas exploration and production company wholly owned by the Government of Korea with current credit ratings of A (Stable) from S&P and A1 (Stable) from Moody’s. KNOC’s founding principle is to secure oil supplies for the nation of Korea by exploring for and developing oilfields and holding petroleum reserves. As at December 31, 2010, Harvest’s net proved reserves represented approximately 35% of KNOC’s consolidated crude oil and natural gas reserves and resources and for year ended December 31, 2010, Harvest’s crude oil and natural gas production represented 27% of KNOC’s consolidated crude oil and natural gas production.

Harvest Operations manages the affairs of the Operating Subsidiaries and North Atlantic, 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.

The head and principal office of Harvest is located at Suite 2100, 330 - 5th Avenue S.W., Calgary, Alberta T2P 0L4 and the telephone number is (403) 265-1178. The registered office of Harvest is located at Suite 4500, Bankers Hall East 855 – 2nd Street S.W., Calgary, Alberta T2P 4K7.

RECENT DEVELOPMENTS

KNOC ACQUISITION

On October 21, 2009, Harvest and KNOC entered into an agreement pursuant to which KNOC agreed to acquire the Trust in a transaction valued at approximately $4.1 billion (including debt) pursuant to the KNOC Arrangement. 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 security holders. 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 the Trust 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; the outstanding Debentures remain listed on the TSX.

On May 1, 2010, an internal reorganization was completed so as to effectively convert from an investment trust issuer to a corporate issuer, pursuant to which the Trust was dissolved and the wholly owned subsidiary and manager of the Trust, Harvest Operations Corp., was amalgamated with KNOC Canada to continue as one corporation under the name Harvest Operations Corp. The carrying values of Harvest’s assets and liabilities were determined from the existing carrying values of KNOC Canada’s assets and liabilities and therefore reflect the fair values established through the KNOC Acquisition.

KNOC Canada was incorporated on October 9, 2009 and did not have any results of operations or cash flows between October 9, 2009 and December 31, 2009, aside from capital contributions from KNOC to finance the KNOC Acquisition and cash used in the KNOC Acquisition.

EQUITY

Prior to the KNOC Acquisition the Trust Units were listed and traded on the TSX and the NYSE under the trading symbols "HTE.UN" (TSX) and "HTE" (NYSE), respectively. The Trust Units were delisted from both the TSX and the NYSE shortly after the December 22, 2009 completion of the KNOC Arrangement.

Concurrent with closing of the KNOC Arrangement, KNOC purchased an additional 60 million Trust Units at $10 per unit. The $600 million of proceeds from this equity issue were used to repay approximately $600 million of then existing bank indebtedness.

In early 2010, Harvest 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 (see sections entitled “Convertible Debentures” and “Senior Notes” under this Item 4.A regarding the change of control provisions).

On August 6, 2010, Harvest completed the acquisition of the BlackGold oil sands project from KNOC for $374.2 million, which was paid for through the issuance of additional equity to KNOC. Harvest subsequently issued $85.7 million of shares to KNOC for funding of BlackGold’s initial capital expenditures.

CONVERTIBLE DEBENTURES

As completion of the KNOC Arrangement constituted a "change of control" under the Debenture Indenture, the Trust made offers to purchase all outstanding Debentures for cash consideration equal to 101% of the principal amount thereof plus accrued and unpaid interest as required by the Debenture Indenture on January 20, 2010. 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 6.50% 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.

SENIOR NOTES

The indenture pursuant to which the 7⅞% Senior Notes was issued contained a similar "change of control" provision. Accordingly, on January 20, 2010, Harvest Operations made an offer to purchase all 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.

On September 17, 2010, Harvest Operations issued an Offer To Purchase And Consent Solicitation Statement (the “Offer”) to purchase all of the outstanding 7⅞% Senior Notes and solicit consent for amendments of the related indenture. Harvest Operations offered US$983.50 for each US$1,000 principal amount of notes tendered; in addition, for consent to the amendments of the indenture a payment of US$20.00 was offered for each US$1,000 principal amount of notes tendered by September 30, 2010. On October 4, 2010, all conditions of the Offer were met and Harvest Operations redeemed US$178.3 million of the US$209.6 million principal amount outstanding for total consideration of $179.0 million. On October 19, 2010, Harvest Operations redeemed the remaining US$31.3 million senior notes at par under the terms of the amended indenture.

Concurrently with the Offer, Harvest completed an offering of US$500 million principal amount of 6⅞% Senior Notes for net cash proceeds of US$484.6 million. The 6⅞% Senior Notes are unsecured, incur interest payments semi-annually on April 1 and October 1 each year, mature on October 1, 2017 and are unconditionally guaranteed by all of the Corporation’s wholly-owned subsidiaries that guarantee the Credit Facility and every future restricted subsidiary that guarantees certain debt.

CREDIT FACILITY

Concurrent with closing of the KNOC Arrangement, Harvest Operations entered into an amended $600 million credit facility with a syndicate of lenders. On April 30, 2010, Harvest Operations amended and extended the Credit Facility with a new maturity date of April 30, 2013, under which the available commitment was reduced from $600 million to $500 million. On April 29, 2011, Harvest extended the term of the Credit Facility by two years to April 30, 2015. The minimum rate charged on the credit facility was also amended from 200 bps to 175 bps over bankers’ acceptance rates as long as Harvest’s secured debt to EBITDA ratio remains below or equal to one. The borrowing capacity of the Credit Facility remains at $500 million and the financial covenants remain unchanged.

CAPITAL EXPENDITURES

The following table provides a summary of Harvest’s capital expenditures for the year ending December 31, 2010:

		2010			2009			2008

Upstream capital expenditures	$	412,124		$	186,276		$	271,312
Downstream capital expenditures		71,234			43,875			56,162
Total capital expenditures		483,358			230,151			327,474
Acquisitions
Business		145,144			-			36,756
Property		397,083			2,635			138,493
Divestitures
Property		(440	)		(64,751	)		(46,476	)
Net acquisition and divestiture activities		541,787			(62,116	)		128,773
Net capital investment	$	1,025,145		$	168,035		$	456,247

Refer to Item 5.A of this annual report for a detailed discussion on the capital expenditures made in the Upstream and Downstream operations.

In 2010, Harvest Operations acquired the remaining 40% interest in Redearth Partnership and other petroleum and natural gas properties for total cash consideration of $145.1 million. As a result of the acquisition, $168.1 million was added to property, plant and equipment, $7.4 million to asset retirement obligations and $5.3 million to future income tax liability. Harvest also recognized a gain on acquisition of $10.3 million, which reflects the excess of fair value of the acquired net assets over the cash consideration paid. In 2010, Harvest also acquired certain petroleum and natural gas assets for $31.6 million.

On August 6, 2010, Harvest completed the acquisition of the BlackGold oil sands project from KNOC for $374 million. BlackGold is located in northeastern Alberta. The project has Energy Resource Confirmation Board (“ERCB”) approval for a Phase 1 production of 10,000 bbls/d and an application in process for a Phase 2 expansion that would increase production to 30,000 bbl/d. The project will utilize steam assisted gravity drainage (“SAGD”), an established in situ technology that uses horizontal drilling. Harvest has entered into a fixed-price engineering, procurement and construction (“EPC”) contract to build a central processing facility for BlackGold. The contracted cost is $311 million of which $43.5 million, including the $31.1 million deposit, was paid in 2010 and the remaining balance will be paid in 2011 and 2012. The development of the BlackGold assets is expected to be completed by the fourth quarter of 2012 and first oil is expected in early 2013. Harvest expects to fund the future capital expenditures with the $85.7 million capital injection already funded by KNOC, future cash flow from operating activities and the undrawn Credit Facility.

On December 14, 2010 Harvest signed a purchase and sale agreement to purchase the assets of Hunt Oil Company of Canada, Inc. and Hunt Oil Alberta, Inc. (collectively “Hunt”). On February 28, 2011, the transaction was closed and total cash consideration of $505.5 million was paid solely funded by KNOC equity injection. An additional $25 million payment to Hunt is payable in the event that Canadian natural gas prices exceed certain pre-determined levels over the next 2 years.

Hunt also agreed to reimburse Harvest for costs associated with restoring production as well as the lost revenues relating to certain properties between October 1, 2010 and April 3, 2011, when production was resumed. A portion of the reimbursement may be reverted to Hunt if the future revenues earned by Harvest during the six months after the gas plant restored production exceeds the reimbursed amount.

B. Business Overview

Harvest is an oil and gas producer with upstream and downstream operations. The Corporation’s crude oil and natural gas business focuses on the operation and further development of its oil-focused assets in western Canada, including its recently acquired oil sands project, Black Gold. Harvest’s refining and marketing business focuses on the safe and efficient operation of the medium gravity sour-crude refinery located in the Province of Newfoundland and Labrador and the associated retail and marketing operations.

UPSTREAM

In the Upstream Operations, Harvest employs a disciplined approach to acquiring, developing and operating large resource-in-place producing properties using best-in-class technologies. Our Upstream Operations are principally located in the western Canadian sedimentary basin and our material properties are described in Item 4.D below. We have a high degree of operational control as we are the operator on properties that generated the majority of our production. We believe that this “hands on” approach allows us to achieve lower development and production costs, better manage our capital expenditures and accumulate institutional expertise in our operating regions. Our engineering and technical personnel focus on optimizing production rates, through the application of Enhanced Oil Recovery and other technologies, while targeting operational efficiencies to control costs. All of our Upstream production is sold in the Canadian market; see Item 5.A of this annual report for a breakdown of total sales by product type.

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, geopolitical 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 16 to Harvest's consolidated financial statements for the year ended December 31, 2010.

MARKETING CHANNELS

Crude Oil and Natural Gas Liquids (NGLs)

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

Natural Gas

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

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. If western Canada is short export capacity it will result in oil and gas being unable to get to market which will result in discounted pricing.

COMPETITIVE CONDITIONS, SEASONALITY, AND TRENDS

Competitive conditions are included in the description of Harvest’s risk factors in Item 3.D of this annual report. The exploitation and development of oil and natural gas reserves is dependent on physical access to production areas. Seasonal weather conditions, including freeze-up and break-up, affect such access. The seasonal accessibility increases competition for equipment and human resources during those periods.

ENVIRONMENT, HEALTH AND SAFETY POLICIES AND PRACTICES

Harvest takes an active role in the Canadian Association of Petroleum Producers (CAPP) Responsible Canadian Energy (RCE) program (formerly the Stewardship Program) that is an association-wide performance reporting program designed to track progress of the CAPP membership in environmental, health, safety, and social performance.

In 2010, Harvest took steps to build on its existing environmental, health and safety (EH&S) management systems using the RCE framework for continuous improvement. This included conducting a third party assessment of Harvest’s existing environmental management systems and identifying areas of process improvement. In 2011, Harvest expects to build and formalize the environment and regulatory components of the EH&S management system. Improvements to the health and safety program included the implementation of a formalized system for evaluating and approving third party contractors that are solicited to work at Harvest sites. Additional improvements included the launch of a newly designed online safety orientation system, and a formal process to verify and document worker competence pertaining to critical work procedures.

In 2010, as part of Harvest’s Fugitive Emission Management Program, leak detection testing was conducted at 278 facilities. All emission sources detected were repaired representing a reduction in greenhouse gas emissions (GHGs). Also, in 2010 Harvest continued to improve on its GHG inventory as well ensuring compliance with provincial regulatory bodies, including preparation for the new British Columbia GHG Reporting Regulation that was released in January 2010.

In 2010, Harvest spent $9.4 million on the management and retirement of environmental liabilities which included restoration of spill sites, remediation of sites with historical contamination, and the reclamation of abandoned well sites and access roads. In 2010, Harvest had 295 active (operated) reclamation sites with 38 of these sites being submitted to regulators for reclamation certification. It is expected that in 2011, Harvest will have 325 active reclamation sites with the goal of submitting approximately 48 for reclamation certification.

CONTROLS AND REGULATIONS

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. 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 Harvest is 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 directionally track industry benchmark 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 market imbalances. These relationships to industry reference prices can change on a monthly or daily basis depending on the supply-demand fundamentals at each location as well as other non-related market changes such as the value of the Canadian dollar and the cost of transporting the commodity to the pricing point of the particular index.

Although the market ultimately determines the price of crude oil and natural gas, producers are entitled to negotiate sales contracts directly with purchasers. 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.

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 m3/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.

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% (40% effective January 2011). Natural gas royalties are also set by a single sliding rate formula, with royalty rates ranging from 5% to 50% (36% effective January 2011). 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%.

On April 10, 2008, the Government introduced two new royalty programs for the development of deep oil and natural gas reserves. A five-year oil program for exploratory wells over 2,000 meters will provide royalty adjustments up to $1 million or 12 months of royalty offsets, whichever comes first, while a natural gas deep drilling program (the “NGDDP”) for wells deeper than 2,500 meters will create a sliding scale of royalty credit according to depth of up to $3,750/meter. Modifications to the NGDDP were announced on May 27, 2010 and include adjusting the vertical depth requirement to 2,000 metres and making the program an on-going feature of the Alberta royalty regime.

In November 2008, the Government announced the introduction of a five year program of Transitional Royalty Plan (the “TRP”) which offers companies drilling new natural gas or conventional deep oil wells (between 1,000 and 3,500 meters) a one-time option, on a well-by-well basis, to reduced royalty rates for new wells for a maximum period of five years to December 31, 2013 after which all wells convert to the NRF. To qualify for this program, wells must be drilled between November 19, 2008 and December 31, 2013. This program was amended on May 27, 2010 such that no new wells will be allowed to select transitional royalty rates effective January 1, 2011 and wells that have selected the transitional royalty rates will have the option to switch to the new rates effective January 1, 2011.

On March 3, 2009, the Government announced a new three-point stimulus plan and extended the plan to two years on June 25, 2009. The Drilling Royalty Credit for new conventional oil and natural gas wells is a two-year program effective for wells spud on or after April 1, 2009. It 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. The New Well Royalty Rate is also effective April 1, 2009 for new conventional oil and natural gas wells. It will provide a maximum 5% royalty rate for the first 12 months of production, up 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 (announced as a permanent feature of the Alberta royalty regime on May 27, 2010). The third point is an abandonment and reclamation fund which 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 May 27, 2010, in addition to announcing changes to existing programs, the Government implemented the Horizontal Oil and Gas New Well Royalty Rates, retroactive to wells that commence drilling on or after May 1, 2010, to provide upfront royalty adjustments to new horizontal wells. Qualifying oil wells will receive a maximum royalty rate of 5 percent for all products with volume and production month limits set according to the depth of the well. Qualifying gas wells will also receive a maximum royalty rate of 5 percent for all products for 18 producing months, with a volume limit of 500 million cubic feet of gas equivalent production.

On January 28, 2011, the Minister of Energy, Ron Liepert, announced that the Alberta Government had accepted the recommendations of the Regulatory Enhancement Task Force, including the proposal to consolidate a variety of upstream oil and gas regulatory functions into the authority of a single regulator. These changes are intended to streamline the approval process for projects, resulting in more consistency, less duplication and greater certainty to the regulatory regime in Alberta.

Saskatchewan

In Saskatchewan, the amount payable as a Crown royalty or freehold production tax in respect of crude oil depends on the type, value, quantity produced in a month and vintage. Crude oil type classifications are “heavy oil”, “southwest designated oil” or “non-heavy oil other than southwest designated oil”. Vintage categories applicable to each of the three crude oil types are old, new, third tier and fourth tier. Crude oil rates are also price sensitive and vary between the base royalty rates of 5% for all fourth tier oil to 20% for old oil. Marginal royalty rates, applied to the portion of the price that is above the base price, are 30% for all fourth tier oil to 45% for old oil.

The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the amount obtained by the producer and a prescribed minimum price. As an incentive for the marketing of natural gas produced in association with oil, a lower royalty rate is assessed than the royalty payable on non-associated natural gas. The rates and vintage categories of natural gas are similar to oil.

On June 19, 2007, a new orphan oil and gas well and facility program was introduced, 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.

On May 27, 2010, the Government of Saskatchewan announced an incentive to encourage increased natural gas exploration and production in the province. The volume-based incentive establishes a maximum Crown royalty rate of 2.5 per cent and a freehold production tax rate of zero per cent on the first 25 million cubic meters of natural gas produced from every horizontal gas well drilled between June 1, 2010 and March 31, 2013.

British Columbia

The British Columbia 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.

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.

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, and a qualification of horizontal wells drilled between 1,900 and 2,300 meters 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, licenses 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.

In 2007, the Government of Alberta introduced the Climate Change and Emissions Management Amendment Act which intends to reduce greenhouse gas emissions intensity from large emitting facilities. On January 24, 2008, the Government of Alberta announced their plan to reduce projected emissions in the province by 50% under the new climate change plan by 2050. This will result in real reductions of 14% below 2005 levels. The Government of Alberta stated they will form a government-industry council to determine a go-forward plan for implementing technologies, which will significantly reduce greenhouse gas emissions by capturing air emissions from industrial sources and locking them permanently underground in deep rock formations.

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.

The Canadian Government has indicated its commitment to reduce greenhouse gas emissions and will be making changes to environmental legislation for criteria air contaminants and renewable fuels but has provided no specific target guidelines or policies that relate to the oil and gas industry. Such legislation could have potentially adverse effects on both Harvest’s Upstream and Downstream financial results. Harvest will participate in the discussion of any initiatives whether at a Federal or Provincial government level, and will be able to determine if there is any financial impact once guidelines are established. On an ongoing basis, Harvest continues to undertake projects that reduce emission of greenhouse gases, such as evaluating the injection of carbon dioxide into oil reservoirs and the further capture of fugitive emissions in our field operations as part of our annual capital program.

In 2002, the Government of Canada ratified the Kyoto Protocol which calls for Canada to reduce its greenhouse gas emissions to specified levels. On April 26, 2007, the Government of Canada released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the “Action Plan”) which includes a regulatory framework for air emissions. This Action Plan is to regulate the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. On March 10, 2008, the Government of Canada released “Turning the Corner” outlining additional details to implement their April 2007 commitment to cut greenhouse gas emissions by an absolute 20% by 2020. “Turning the Corner” sets out a framework to establish a market price for carbon emissions and sets up a carbon emission trading market to provide incentives for Canadians to reduce their greenhouse gas emissions. In addition, the regulations include new measures for oil sands developers that require an 18% reduction from 2006 levels by 2010 for existing operations and for oil sands operations commencing in 2012, a carbon capture and storage capability. There is no mention of targeting reductions for unintentional fugitive emissions for conventional producers. Companies will be able to choose the most cost effective way to meet their emissions reduction targets from in-house reductions, contributions to time-limited technology funds, domestic emissions trading and the United Nations’ Clean Development Mechanism. Companies that have already reduced their greenhouse gas emissions prior to 2006 will have access to a limited one-time credit for early adoption. Giving the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, and the lack of detail in the Government of Canada’s announcement, it is not possible to assess the impact of the requirements on our operations and financial performance.

RESERVES AND OTHER OIL AND GAS INFORMATION

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, 2010. Harvest’s reserves were evaluated by McDaniel (who evaluated approximately 20% of Harvest’s total proved plus probable reserves), and GLJ (who evaluated approximately 80% 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, 2011 and the 2010 constant prices as per SEC regulations. See Item 19.15.1 and .2 of this annual report for Independent Reserve Evaluators’ reports on evaluation methodology.

The following summarizes the crude oil, natural gas liquids and natural gas reserves of Harvest and the net present values of future net revenue for these reserves, in accordance with U.S. disclosure requirements. Additional information not required under the U.S. disclosure requirements has been presented to provide additional information which Harvest believes 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 Harvest’s 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 Harvest’s 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.

Description of Harvest’s internal controls used in reserve estimation

The person primarily responsible for overseeing the year-end reserves evaluation is the Chief Operating Officer (COO) Rob Morgan, Professional Engineer and has been COO at Harvest since February 2006 and has over 25 years of experience in the oil and gas industry.

Independent Reserve Evaluators are selected and appointed by one of Harvest’s Board committees, the Upstream Reserves, Safety and Environment Committee (“Reserves Committee”), with assistance from the COO. Each evaluator’s qualifications, industry experience and experience with Harvest’s Assets are reviewed to enable the Reserves Committee to approve the selection of Independent Reserve Evaluators. Normally, more than one Independent Reserve Evaluator would be appointed to ensure independence. The allocation of assets to be reviewed by each Independent Reserve Evaluator is based on the evaluator’s expertise, information databases and past experience in evaluating the relevant properties. The allocations are reviewed by the COO to ensure that there is no duplication of areas.

For 2010, Harvest engaged two firms, GLJ and McDaniels to undertake the year-end evaluation. Harvest supplied accounting data, land data and well files for any new drills to the evaluators in order for them to initiate their review process. Internally, Harvest also conducted technical review meetings on major properties to highlight activity that was undertaken through the course of the year. The evaluators took the initial data and prepared draft reports for review. Reports were logged by Harvest’s reserves coordinator and then forwarded to individual property teams for detailed review. This process continued until the final updated report was received.

The COO reviews the final report, ensuring that it is consistent with the previous report and that appropriate changes have been made.

After completing the review, the COO presents the report to the Reserves Committee together with a memo highlighting the significant changes from the prior year, including a reconciliation to gain an understanding of the additions, deletions and revisions made since the previous report. This memo is reviewed with the Reserves Committee by the COO and key areas and significant differences between Management and the Independent Reserve Evaluators are discussed.

A due diligence check list is used by the Reserves Committee in reviewing the process to ensure comfort over the use of definitions, independence and qualifications. In addition, the Independent Reserve Evaluator attests to the Reserves Committee that the Reserve Report satisfies NI 51-101 and SEC definitions; this representation is also included in the final signed report.

Net Reserves (Harvest Share After Royalties)

The following table sets forth a summary of oil and natural gas reserves prepared by Harvest using constant pricing in accordance with the SEC’s guidelines as of December 31, 2010. The year-end numbers represent estimates derived from the Reserve Reports. Refer to Item 3.D “Risk Factors” of this annual report for discussion on the uncertainties involved in estimating our reserves.

	Reserves
	Light and Medium
	Oil⁽¹⁾		Heavy Oil⁽¹⁾		Bitumen
	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)

Proved
Developed producing	55,651	50,661	29,798	27,041	-	-
Developed non-producing	1,048	917	1,587	1,322	-	-
Undeveloped	10,928	9,484	3,830	3,188	93,483	86,702
Total proved	67,627	61,062	35,215	31,551	93,483	86,702

Probable	25,304	23,036	15,844	13,583	165,762	147,537

Total proved plus probable	92,931	84,098	51,059	45,134	259,245	234,239

	Reserves
	Natural Gas		Natural Gas Liquids		Total Oil Equivalent
	Gross	Net	Gross	Net	Gross	Net
	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBOE)	(MBOE)

Proved
Developed producing	151,452	134,644	5,588	4,127	116,278	104,270
Developed non-producing	10,048	9,091	353	262	4,664	4,015
Undeveloped	23,940	19,959	494	395	112,726	103,096
Total proved	185,440	163,694	6,435	4,784	233,668	211,381

Probable	73,609	65,207	2,695	1,997	221,872	197,021

Total proved plus probable	259,049	228,901	9,130	6,781	455,540	408,402

(1)	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: 11.3 MMbbl, Proved Undeveloped: 5.6 MMbbl, Total Proved: 17.0 MMbbl, Probable: 5.5 MMbbl and Proved plus Probable: 22.5 MMbbl, and would increase the net heavy oil reserves and reduce the light/medium oil reserves by the following amounts: Proved Developed Producing: 9.9 MMbbl, Proved Undeveloped: 4.7 MMbbl, Total Proved: 14.7 MMbbl, Probable: 4.9 MMbbl, and Proved plus Probable: 19.6 MMbbl.

(2)	The crude oil, natural gas liquids and natural gas reserve estimates presented are based on the definitions and guidelines in the SEC’s disclosure rules. A summary of these definitions are set forth below:

	(a)	Net reserves are the remaining reserves of Harvest, after deduction of estimated royalties and including royalty interests.
	(b)	Proved reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate withreasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.
	(c)	Probable reserves estimates are provided as optional disclosure under the Final Rule. Probable reserves are those additional reserves that are less certain to be recovered than proved, however, together with proved are as likely as not to be recovered.

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

	(a)	Developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
	(b)	Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(3)	Estimates of total net proved crude oil or natural gas reserves are not filed with any U.S. federal authority or agency other than the SEC.

Undeveloped Reserves

As at January 1, 2011, Harvest has a total of 117.4 MMBOE of gross reserves that are classified as proved non-producing, of these non-producing reserves approximately 96% 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, 2011. Substantially all of the undeveloped reserves are based on Harvest’s then current 2011 budget and long range development plans for the major assets noted elsewhere in this document. Approximately 40% of these reserves are expected to be developed within the next two years. The remaining conventional undeveloped reserves are expected be developed over the next five years, in most cases due to processing facility capacity restrictions. The undeveloped reserves assigned to the Black Gold oilsands project are forecast to be developed over the next 25 years. The capital cost has been taken into account for these programs in the estimated future net revenue.

During 2010 Harvest drilled a gross total of 171 wells (141.4 net) with the vast majority of the development taking place in the following properties: Red Earth, Lloydminster, Markerville, SE Saskatchewan and Hay River. The bulk of the wells drilled had been previously assigned proved undeveloped (PUD) reserves and therefore these reserves were converted to proved developed. Total PUD reserves converted during 2010 were 4.6 MMboe with related capital expenditures of approximately $86.4 million.

New PUD reserves were also assigned during the 2010 year-end evaluation recognizing the ongoing development of Harvest’s properties. Total gross PUD reserves added for the 2010 year-end evaluation was 98.6 MMboe.

There are no material amounts of PUD reserves that have remained undeveloped for five years or more after disclosure as proved undeveloped reserves.

Timing of Initial Undeveloped Reserves Assignment

	Gross Reserves First Attributed by Year

	Units	Prior	2008		2009	2010	Total
Proved undeveloped
Light and Medium Crude Oil	Mbbl	3,447	65		417	2,891	6,820
Heavy Crude Oil⁽¹⁾	Mbbl	7,318	3,663		429	1,326	12,736
Natural Gas	MMcf	28,723	(2,840	)	1,337	3,787	31,007
Natural Gas Liquids	Mbbl	444	6		22	148	621
Bitumen	Mbbl	-	-		-	93,604	93,604
Total Oil Equivalent	MBOE	15,996	3,261		1,091	98,600	118,948
Probable undeveloped
Light and Medium
Crude Oil	Mbbl	9,730	(48	)	1,410	2,604	13,696
Heavy Crude Oil⁽¹⁾	Mbbl	10,035	(1,179	)	492	1,512	10,860
Natural Gas	MMcf	27,040	(3,260	)	2,148	9,491	35,419
Natural Gas Liquids	Mbbl	990	93		41	177	1,301
Bitumen	Mbbl	-	-		-	165,640	165,640
Total Oil Equivalent	MBOE	25,262	(1,677	)	2,302	171,514	197,400

⁽¹⁾	Hay River reserves are considered to be heavy crude oil for this analysis.

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

Production Volumes

	Production Volumes — 2010
	Year	Q4	Q3	Q2	Q1


Natural Gas (Mcf/d)	80,881	82,837	79,147	79,797	81,752
Oil and Natural Gas Liquids (bbls/d)
Light and Medium Oil⁽¹⁾	24,077	24,079	22,886	24,874	24,487
Heavy Oil	9,253	9,433	9,235	9,090	9,250
Natural Gas Liquids	2,587	2,736	2,465	2,334	2,816
Total Oil and Natural Gas Liquids	35,917	36,248	34,586	36,298	36,553
Total (BOE/d)	49,397	50,054	47,777	49,597	50,178

	Production Volumes — 2009
	Year	Q4	Q3	Q2	Q1


Natural Gas (Mcf/d)	90,097	83,610	89,163	92,335	95,421
Oil and Natural Gas Liquids (bbls/d)
Light and Medium Oil⁽¹⁾	23,651	23,281	22,793	24,316	24,233
Heavy Oil	10,261	9,491	10,066	10,365	11,141
Natural Gas Liquids	2,718	2,714	2,648	2,675	2,837
Total Oil and Natural Gas Liquids	36,630	35,486	35,507	37,356	38,211
Total (BOE/d)	51,646	49,421	50,368	52,745	54,115

	Production Volumes — 2008
	Year	Q4	Q3	Q2	Q1


Natural Gas (Mcf/d)	96,315	96,079	93,628	93,014	102,570
Oil and Natural Gas Liquids (bbls/d)
Light and Medium Oil⁽¹⁾	25,093	24,295	25,210	25,365	25,509
Heavy Oil	12,162	12,099	11,485	12,092	12,980
Natural Gas Liquids	2,624	2,770	2,627	2,614	2,484
Total Oil and Natural Gas Liquids	39,879	39,164	39,322	40,071	40,973
Total (BOE/d)	55,932	55,178	54,926	55,573	58,067

Per-Unit Results

	Per-Unit Results — 2010
	Year	Q4	Q3	Q2	Q1
Natural Gas and Natural Gas Liquids ($/boe)
Average sales price	30.67	29.12	27.39	30.34	35.80
Royalties	4.69	3.15	2.99	4.32	8.29
Operating expenses⁽²⁾	11.16	10.68	11.83	11.92	10.27
Netback⁽³⁾	14.82	15.29	12.57	14.10	17.24
Crude Oil — Light and Medium⁽¹⁾($/bbl)
Average sales price	71.09	73.44	67.71	68.78	74.35
Royalties	10.48	10.97	10.29	11.59	9.01
Operating expenses⁽²⁾	16.28	17.43	15.48	15.64	16.55
Netback⁽³⁾	44.33	45.04	41.94	41.55	48.79
Crude Oil — Heavy ($/bbl)
Average sales price	59.94	58.82	58.52	56.51	65.98
Royalties	10.42	10.36	9.11	10.66	11.57
Operating expenses⁽²⁾	16.90	17.03	16.17	19.31	15.10
Netback⁽³⁾	32.62	31.43	33.24	26.54	39.31
Crude Oil — Total ($/bbl)
Average sales price	68.00	69.33	65.07	65.49	72.06
Royalties	10.46	10.80	9.95	11.34	9.71
Operating expenses⁽²⁾	16.45	17.32	15.68	16.62	16.16
Netback⁽³⁾	41.09	41.21	39.44	37.53	46.19
Total ($/boe)
Average sales price	55.85	56.03	52.71	54.41	60.17
Royalties	8.58	8.27	7.67	9.13	9.25
Operating expenses⁽²⁾	14.73	15.12	14.42	15.14	14.23
Netback⁽³⁾	32.54	32.64	30.62	30.14	36.69

	Per-Unit Results — 2009
	Year	Q4	Q3	Q2	Q1
Natural Gas and Natural Gas Liquids ($/boe)
Average sales price	28.70	32.37	23.16	26.04	33.38
Royalties	3.42	3.55	3.07	1.98	5.05
Operating expenses⁽²⁾	10.91	11.14	10.06	10.15	12.26
Netback⁽³⁾	14.37	17.68	10.03	13.91	16.07
Crude Oil — Light and Medium⁽¹⁾($/bbl)
Average sales price	58.18	70.09	64.57	57.54	40.99
Royalties	9.10	12.99	10.05	8.12	5.35
Operating expenses⁽²⁾	15.76	14.95	15.10	14.65	18.31
Netback⁽³⁾	33.32	42.15	39.42	34.77	17.33
Crude Oil — Heavy ($/bbl)
Average sales price	52.91	62.62	58.57	55.12	37.16
Royalties	7.52	8.12	10.54	7.39	4.34
Operating expenses⁽²⁾	13.89	14.46	13.45	12.95	14.69
Netback⁽³⁾	31.50	40.04	34.58	34.78	18.13
Crude Oil — Total ($/bbl)
Average sales price	56.59	67.93	62.73	56.82	39.78
Royalties	8.62	11.58	10.20	7.90	5.03
Operating expenses⁽²⁾	15.19	14.80	14.59	14.14	17.17
Netback⁽³⁾	32.78	41.55	37.94	34.78	17.58
Total ($/boe)
Average sales price	47.02	55.94	48.97	46.28	37.56
Royalties	6.84	8.87	7.72	5.88	5.04
Operating expenses⁽²⁾	13.72	13.57	13.02	12.77	15.47
Netback⁽³⁾	26.46	33.50	28.23	27.63	17.05

		Per-Unit Results — 2008
	Year	Q4	Q3	Q2	Q1

Natural Gas and Natural Gas Liquids ($/bbl)
Average sales price	54.91	42.55	56.05	68.58	53.28
Royalties	9.43	7.49	9.97	11.26	9.12
Operating expenses⁽²⁾	11.43	10.65	11.77	12.12	11.24
Netback⁽³⁾	34.05	24.41	34.31	45.20	32.92
Crude Oil — Light and Medium⁽¹⁾($/bbl)
Average sales price	89.72	52.37	110.70	109.26	86.54
Royalties	14.51	8.59	17.24	17.61	14.38
Operating expenses⁽²⁾	16.80	19.46	15.84	15.89	16.10
Netback⁽³⁾	58.41	24.32	77.62	75.76	56.06
Crude Oil — Heavy ($/bbl)
Average sales price	77.22	42.44	99.21	96.79	69.04
Royalties	11.40	3.43	15.68	16.00	10.80
Operating expenses⁽²⁾	15.38	18.20	15.92	14.94	12.63
Netback⁽³⁾	50.44	20.81	67.61	65.85	45.61
Crude Oil — Total ($/bbl)
Average sales price	85.64	49.29	107.10	105.23	80.64
Royalties	13.49	6.88	16.75	17.09	13.18
Operating expenses⁽²⁾	16.34	19.04	15.87	15.58	14.93
Netback⁽³⁾	55.81	23.37	74.48	72.56	52.53
Total ($/BOE)
Average sales price	75.39	46.99	90.15	93.29	71.41
Royalties	12.14	7.08	14.50	15.19	11.81
Operating expenses⁽²⁾	14.70	16.19	14.51	14.45	13.69
Netback⁽³⁾	48.55	23.72	61.14	63.65	45.91

(1)	Medium oil production includes production from Harvest’s Hay River property. The crude oil from this property has an average API of 24 (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.

Drilling Activity

The following tables summarize Harvest’s gross participation and net interest in wells drilled for the periods indicated.

	2010
	Exploratory Wells		Development Wells
	Gross ⁽¹⁾	Net ⁽²⁾	Gross ⁽¹⁾	Net ⁽²⁾
Oil Wells	12	10.6	139	118.1
Gas Wells	5	4.4	9	3.2
Service Wells	-	-	5	5.0
Dry Holes	1	0.1	-	-
Total Wells	18	15.1	153	126.3

	2009
	Exploratory Wells		Development Wells
	Gross ⁽¹⁾	Net ⁽²⁾	Gross ⁽¹⁾	Net ⁽²⁾
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

	2008
	Exploratory Wells		Development Wells
	Gross ⁽¹⁾	Net ⁽²⁾	Gross ⁽¹⁾	Net ⁽²⁾
Oil Wells	-	-	119	101.8
Gas Wells	2	2	120	41.0
Service Wells	2	2	4	3.5
Dry Holes	-	-	-	-
Total Wells	4	4	243	146.3

⁽¹⁾	“Gross” wells are the total number of wells in which Harvest has an interest.
⁽²⁾	“Net” wells are the number of wells obtained by aggregating Harvest’s working interests in each of its gross wells.

Present Activities

At December 31, 2010 Harvest was in the process of drilling a gross total of 13 wells (10.7 net) which was the beginning of the 2011 capital program (estimated to be approximately $400 million with a focus on oil projects). There were 8 oil wells, 4 gas wells and one service well, 10 of which were drilled horizontally. Of the 8 oil wells (one well with 40% working interest and the rest are 100% working interest) 3 were drilled at Hay River targeting the Bluesky formation and 5 were drilled in the Red Earth area, four of which are targeting the Slave Point formation. Three out of the four gas wells were drilled in the Rimbey area. Harvest also plans to continue with its enhanced oil recovery projects in the larger oil reservoirs at Hay River, Bellshill Lake, Wainwrights and Suffield.

Location of Wells

The following table summarizes Harvest’s interests in producing wells and wells capable of producing as at December 31, 2010.

	Gas				Oil				Total⁽³			⁾⁽⁴⁾
	Gross⁽¹	⁾	Net⁽²	⁾	Gross⁽¹	⁾	Net⁽²	⁾	Gross⁽¹	⁾	Net⁽²	⁾
Alberta	2,532		895		5,032		3,646		7,564		4,541
British Columbia	104		13		293		247		397		260
Saskatchewan	58		48		1,577		1,293		1,635		1,341
Total	2,694		956		6,902		5,186		9,596		6,142

(1)	“Gross” wells are the total number of wells in which Harvest has an interest.
(2)	“Net” wells are the number of wells obtained by aggregating Harvest’s working interests in each of its gross wells.
(3)	Harvest has varying royalty interests in 413 natural gas wells and 194 crude oil wells which are producing or capable of producing.
(4)	Includes wells containing multiple completions as follows: 42 gross natural gas wells (21.1 net wells) and 18 gross crude oil wells (13.6 net well).

Developed and Undeveloped Acreage

The following table summarizes Harvest’s developed, undeveloped and total landholdings as at December 31, 2010.

	Developed⁽¹⁾		Undeveloped⁽²⁾		Total
	Gross	Net	Gross	Net	Gross	Net
	(thousands of acres)
Alberta	1,028	590	583	408	1,611	998
British Colombia	125	66	195	100	320	166
Saskatchewan	88	80	94	79	182	159
Total	1,241	736	872	587	2,113	1,323

(1)	Developed acreage is acreage assignable to productive wells; productive wells include producing wells and wells mechanically capable of producing.
(2)	Undeveloped acreage encompasses those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves. Do not confuse undeveloped acreage with undrilled acreage held by production under the terms of the lease.

Acquisitions, Divestitures and Capital Expenditures

Harvest’s growth in recent years has been achieved through a combination of internal growth and acquisitions. Harvest has a large inventory of internal growth opportunities and continues to examine select acquisition opportunities to develop and expand its key resource plays. Acquisition opportunities may include corporate or asset acquisitions. Harvest may finance any such acquisitions with debt, equity, cash generated from operations, proceeds from asset divestitures or a combination of these sources.

The following table summarizes Harvest’s net capital investment in oil and gas producing activities for 2010, 2009 and 2008

($ millions)	2010		2009		2008

Capital Investment	412.1		186.3		271.3
Acquisitions
Business	145.1		-		36.7
Property	31.6⁽¹⁾		2.6		138.5
Divestitures
Property	(0.4	)	(64.8	)	(46.5	)
Net acquisition and divestiture activities	176.3		(62.2	)	128.7
Net capital investment	588.4		124.1		400.0

(1)	Excludes $374 million BlackGold oil sand acquisition as it was paid through the issuance of additional equity to KNOC.

Delivery Commitments

Harvest does not have any material delivery commitments.

DOWNSTREAM

Harvest’s Downstream business, operating under the North Atlantic trade name, is comprised of a medium gravity sour crude oil hydrocracking refinery with a 115,000 barrels per stream day nameplate capacity and a petroleum marketing business (the "Marketing Division") that is composed of five business segments. All of the Downstream operations are located in the Province of Newfoundland and Labrador.

Refining is primarily a margin based business in which the feedstocks and the refined products are commodities. Both crude oil and refined products in each regional market react to a different set of supply/demand and transportation pressures and refiners must balance a number of competing factors in deciding what type of crude oil to process, what kind of equipment to invest in and what range of products to manufacture. As most refinery operating costs are relatively fixed, the goal is to maximize the yield of high value refined products and to minimize crude oil and other feedstock costs. The value and yield of refined products are a function of the refinery equipment and the characteristics of the crude oil feedstock, while the cost of feedstock depends on the type of crude oil. The refining industry depends on its ability to earn an acceptable rate of return in its marketplace where prices are set by international as well as local markets.

PRODUCTS AND MARKETS

An oil refinery is a manufacturing facility that uses crude oil and other feedstocks as raw materials and produces a variety of refined products. The actual mix of refined products from a particular refinery varies according to the refinery's processing units, the specific refining process utilized and the nature of the feedstocks. The refinery processing units generally perform one of three functions: separating different types of hydrocarbons in crude oil, converting the separated hydrocarbons into more desirable or higher value products, or chemically treating the products to remove unwanted elements and components such as sulphur, nitrogen and metals. Refined products are typically differing grades of gasoline, diesel fuel, jet fuel, furnace oil and heavier fuel oil.

The Refinery produces high quality gasoline, ultra low sulphur diesel, jet fuel, furnace oil, and High Sulphur Fuel Oil (“HSFO”). See Item 5.A of this annual report for a breakdown of total sales by product type. Approximately 10-15% of Harvest’s refined products are sold in the Province of Newfoundland and Labrador while approximately 85-90% are export cargos sold, under the SOA, in U.S. east coast markets, such as Boston, New York City, and Europe or farther abroad when economics justify the increased shipping charge. See Item 8.A of this annual report for total export sales in each of the last three years. In 2010, we sold our distillates, gasoline products and our HSFO to Vitol pursuant to the SOA (see Item 10.C for a summary of the terms of the SOA), with the exception of products sold in Newfoundland through our petroleum marketing division and spot sales of HSFO products sold to various credit approved customers. Throughout 2008 and 2009, our HSFO was sold to a wholly-owned affiliate of one of the world’s largest integrated energy companies.

The Marketing Division is headquartered in St. John's, Newfoundland and is composed of the following five business segments:

Retail Gasoline Business

Harvest’s retail gasoline business operates 55 retail gasoline stations and three commercial cardlock locations with 42 locations branded as "North Atlantic" and 11 locations branded as "Home Town" (a secondary brand for small market areas) with the remaining five locations unbranded. Most locations include a convenience store which is independently operated, except for six branded locations, which are fully operated by North Atlantic and are referred to as “Orange Stores.” In 2010, the volume of gasoline sold at these retail locations represented a market share of approximately 20% of the Newfoundland market. The major competitors in the Newfoundland market are Irving Oil, Imperial Oil and Ultramar.

Retail Heating Fuels Business

Harvest’s retail heating fuels business delivers furnace oil and propane to approximately 20,000 residential heating and commercial customers throughout Newfoundland with about 75% of the demand for furnace oil, 24% for propane and 1% for kerosene.

Commercial Business

North Atlantic delivers distillates, jet fuel, propane and high sulphur fuel oil to commercial heating, marine, aviation, trucking and construction industries from seven storage terminals.

Wholesale Business

North Atlantic provides distillates, jet fuel and propane to a number of wholesale customers from both its wharf and truck rack facilities.

Bunker Business

North Atlantic sells bunkers to crude oil and refined product vessels at its wharf facilities.

TRANSPORTATION

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. This enables 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.

GROSS MARGIN

Our refining gross margin is a function of the sales value of the refined products produced and the cost of crude oil and other feedstocks purchased as well as the yield of refined products from various feedstocks. We continuously evaluate the market and relative refinery values of several different crude oils and vacuum gas oils (“VGO”) to determine the optimal feedstock mix. We analyze the refining gross margin for our sales revenue relative to refined product benchmark prices and the WTI benchmark prices. With respect to feedstock costs, we analyze our price discounts relative to the WTI benchmark prices and segregate crude oil sources by country of origin for reporting. See the Downstream risks included in Item 3.D of this annual report for a discussion on the volatility of refining margins due to fluctuations in market prices for crude oil feedstocks and refined products.

FEEDSTOCK

The Refinery's crude oil and other feedstocks are waterborne cargos originating primarily from Iraq, Russia and Venezuela. We purchase substantially all of our refinery feedstock from Vitol pursuant to the SOA. Typically, there are approximately 20 days of crude oil feedstock in tankage at the Refinery to mitigate the effects of any supply disruptions. A discussion on the volatility of feedstock prices is included in Item 3.D “Risk Factors” of this annual report.

ENVIRONMENT, HEALTH AND SAFETY POLICIES AND PRACTICES

The Downstream business has an active and comprehensive Integrated Management System to promote the integration of safety, health and environmental awareness into the Refinery and related businesses. The Refinery is continuing to benefit from previous Workplace Health, Safety and Compensation Commission audits and claims history with workers' compensation assessment rates reduced again for the eighth consecutive year. In 2010, the Refinery was in compliance with Provincial Air Quality and Federal Effluent Regulations.

CONTROLS AND REGULATIONS

The petroleum refining industry is subject to extensive controls and regulations governing its operations (including marine transportation, product specifications, refining emissions and market pricing) imposed by legislation enacted by various levels of government all of which should be carefully considered by investors. It is not expected that any of these controls or regulations will affect the Downstream operations in a manner materially different than they would affect other petroleum refining entities of similar size. All current legislation is a matter of public record and Harvest is unable to predict what additional legislation or amendments may be enacted.

Pricing (Marketing Division)

Since 2001, the sales price of residential home heating fuels and automotive gasoline and diesel fuel sold for consumption within the Province of Newfoundland and Labrador is subject to regulation under the Petroleum Products Act (Newfoundland), administered by the Public Utilities Board. Under this act, the Pricing Commissioner has the authority to set the maximum wholesale and retail prices that a wholesaler and a retailer may charge and to determine the minimum and maximum mark-up between the wholesale price to the retailer and the retail price to the consumer in the Province of Newfoundland and Labrador. The wholesale and retail prices of petroleum products are adjusted weekly based on the New York Harbour benchmark price for these products.

C. Organizational Structure

Each of the subsidiary entities identified below is a direct or indirect wholly-owned subsidiary of Harvest Operations (other than the Redearth Partnership for the period prior to September 2010, in respect of which Harvest Operations held a 60% interest).

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 Harvest Operations Corp. 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 Harvest Operations Corp. 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 Harvest Operations) 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.

Hay River Partnership, a general partnership

Hay River Partnership (indirectly wholly-owned by Harvest Operations) 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.

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. On September 30, 2010, Harvest Operations acquired the remaining 40% interest in Redearth Partnership, resulting in 100% ownership interest. As a result, the Redearth Partnership was dissolved and Harvest Operations became the owner of all the assets and assumed all of the liabilities of the Redearth Partnership.

North Atlantic Refining Limited, a taxable corporation

North Atlantic Refining Limited is a wholly owned subsidiary of Harvest Operations. North Atlantic’s assets consist of the Refinery and related retail marketing assets. North Atlantic is responsible for providing the engineering, operations and administrative services related to Harvest's Downstream 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.

The corporate structure including significant subsidiaries is set forth below. Harvest’s remaining subsidiaries and partnerships did not have assets or sales and operating revenues which, in the aggregate, exceeded 20 percent of the total consolidated assets or total consolidated sales and operating revenues of Harvest as at and for the year ended December 31, 2010:

D. Property, Plant and Equipment

UPSTREAM

MATERIAL PROPERTIES

In general, the material 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 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.

2010 Historical Production by Material Property

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

Hay River	5,849	2,561	20	6,296
Markerville	671	17,321	606	4,164
Rimbey	415	15,788	944	3,990
Southeast Saskatchewan	3,424	278	10	3,480
Lloydminster Heavy Oil	2,751	795	0	2,883
Red Earth	2,731	79	55	2,799
Suffield	2,374	542	25	2,489
Hayter	2,140	312	11	2,203
Peace River Arch	1,090	6,090	70	2,175
Bellshill Lake	1,940	947	45	2,143
Wainwright	1,910	2	0	1,910
Crossfield	29	7,735	395	1,713
Other	8,005	28,434	409	13,152
Total	33,329	80,884	2,590	49,397

Hay River: Hay River was acquired by Harvest on August 2, 2005 and is located approximately 125 miles NW of Grande Prairie in north-eastern British Columbia. In 2010, Hay River produced 5,849 bbl/d of medium gravity 24° API crude oil and 2.6 mmcf /day of natural gas from the Bluesky Formation located at a depth of approximately 450m. Produced emulsion is processed at the 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 November 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 a 100% working interest in this operated property. In 2010, Harvest drilled 10 wells including 5 producing horizontal wells and 5 water source and water injection wells with a total capital expenditure of $36 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 4,164 boe/d (69% natural gas) for the 12 months ending December 31, 2010. 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 2010, the Corporation had capital expenditures of $11.4 million to drill 4 gross wells targeting the Ellerslie (light oil) formation. 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 2010, the Rimbey area produced 3,990 boe/d (approximately 66% natural gas) from various formations including the Rock Creek, Viking, Ostracod, and Cardium. Harvest’s working interest in this area ranges from 25% to 100%. In 2010, Harvest drilled 24 gross wells for a total expenditure of $41 million. One specific area of focus was the Cardium formation where Harvest drilled 12 horizontal wells with multi-staged fracture completions pursuing both light oil and natural gas. 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: The southeast Saskatchewan properties are located approximately 110 miles southeast of Regina. Production from southeast Saskatchewan averaged 3,480 bbl/d of average 33° API crude oil in 2010, 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 2010, Harvest drilled 20 gross (19.5 net) wells, primarily horizontal development and infill wells, into defined pools for a total expenditure of $27 million. Fluid produced from the area is processed at the 100% owned Hazelwood facility and is pipeline connected to the Enbridge system. Harvest has extensive proprietary 3D seismic coverage of these properties, which offers control of the opportunity and will be used to identify further opportunities on and off Harvest’s land base.

Lloydminster Heavy Oil: Harvest has various working interests in this area, which is located near the town of Lloydminster, Alberta. Production of 12° to 15° API heavy crude oil is from Cretaceous aged sandstone formations within the Mannville group. Production averaged 2,883 boe/d (95% oil) in 2010. Harvest drilled 29 gross (26.8 net) wells in 2010 with total capital expenditures of $27.9 million. The majority of the wells drilled were horizontal in the Lloydminster formation. Production from the area’s 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.

Red Earth: Production in 2010 from Red Earth averaged 2,799 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 increased its working interest in this area to over 90% following the acquisition of a 40% interest in the Red Earth partnership in the fall of 2010. In 2010, Harvest drilled 36 gross (30.5 net) wells with total capital expenditures of $70.4 million. A majority of the drilling was horizontal wells in the Slave Point formation using multi-staged fracture completions. 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 that was instrumental in the discovery of a new oil pool in the area and that will assist Harvest’s plans to infill drill its identified Granite Wash and Slave Point pools.

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 2,489 boe/d of primarily heavy oil in 2010, with average API gravity of 11 to 18° 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 2010, Harvest drilled 6 gross (6 net) horizontal wells, undertook upgrades to its water injection systems and installed a polymer flood pilot at its Caen field for a total expenditure of $15.7 million. By increasing injection and using chemical enhancements such as polymers, Harvest believes the ultimate recovery of oil will be increased. 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 as well as the introduction of polymer flooding to further enhance sweep efficiencies.

Hayter: Harvest acquired the Hayter property in November, 2002. Production in 2010 averaged approximately 2,140 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 2010, Harvest had capital expenditures of $6.6 million to drill 2 gross (1.8 net) wells to pursue heavy oil in the Sparky formation as well as complete upgrades to the infrastructure as part of ongoing production optimization. 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.

Peace River Arch: Production from the Peace River Arch area in 2010 averaged approximately 2,175 boepd (53% weighted to liquids. The major asset within the Peace River Arch area is the Cecil asset which produces 24-26API oil from the Charlie Lake formation. Harvest has working interests that vary from 40-100% and operates approximately 25% of the producing wells with an average 100% working interest.

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 are operated by Harvest. Production consists of 26° to 28° API oil produced from the Ellerslie and Dina formations, totaling 2,143 boe/d in 2010 and weighted 93% 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.

Wainwright: Harvest acquired the Wainwright properties in September, 2004. Production in 2010 from this pool averaged approximately 1,910 boe/d of 22° to 24° API medium gravity oil, produced from the Cretaceous Upper Manville 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 flood pilot. Production in 2010 was virtually identical to 2009 which Harvest attributes in part to the impact of the pilot. Harvest will continue to evaluate the performance of the pilot and consider expansion in the future. Total expenditures for 2010 were $11.0 million.

Crossfield: Crossfield is located approximately 20 miles NW of Calgary. Production in 2010 from this region was primarily natural gas (75%) with some liquids and averaged approximately 1,713 boe/d from the Lower Cretaceous Basal Quartz Formation. Harvest has an average 75% working interest in this operated and non-operated property. In 2010, Harvest applied horizontal well technology with multi-staged fracture completions to both the Basal Quartz and the Ellerslie formations and drilled four gross (3.5 net) wells as well as infrastructure upgrades to facilitate re-direction of produced gas to a third party processing facility, for a total expenditure of $24.4 million. Harvest continues to evaluate opportunities to downspace and drill additional locations at Crossfield based on the application of multi-stage fractured horizontal wells.

BlackGold Oil Sands: Harvest acquired BlackGold in 2010. Regulatory approval for the first phase of development (estimated 10,000 bpd) was received in February, and construction began in the fall. Total expenditures in 2010 were $21.5 million to undertake the site preparation and preliminary facility and infrastructure construction.

2011 CAPITAL EXPENDITURE PLAN

Harvest’s expected total capital spending on its oil and natural gas properties for 2011 is expected to be approximately $807 million. These expenditures will be financed primarily with cash from operation activities and available undrawn credit capacity. The primary areas of focus for Harvest’s capital program during 2011 are the following:

BlackGold – Expenditures of approximately $240 million to complete construction of the infrastructure and central processing facility as well initiating the drilling of 10 horizontal well pairs and 12 observation and monitoring wells;
Hay River – Expenditures of approximately $71 million to drill 34 producing multi-leg horizontal oil wells and water injection wells as well as upgrading the processing infrastructure;
Red Earth – Drill 47 gross light oil wells for a net expenditure of $80 million with up to 40 multistage fractured horizontal wells for the Slave Point Formation;
Markerville/Rimbey – Drill 17 gross wells targeting the Cardium (light oil) Ellerslie (light oil) and Ostracod (liquids rich natural gas) formations for an expenditure of $27 million;
Kindersley, Saskatchewan – Drill 23 multistage fractured horizontal wells into the Viking Formation for a total expenditure of $26 million;
Lloydminster and Suffield Heavy Oil – Drill 29 gross wells for a total expenditure of $23 million; and
Various Areas – Expenditures of approximately $54 million to pursue production optimization including pump upsizing, facility debottlenecking and zonal recompletion.

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 Bellshill Lake 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 flooding at Wainwright and Suffield, carbon dioxide injection at Bashaw and acid gas or solvent injection at Hayter; and
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).

DOWNSTREAM

In our Downstream operations the only material asset is the Refinery. While the nameplate capacity is 115,000 bbl/d, the average daily throughput was 86,142 bbl/d for the year ended December 31, 2010 due to unplanned downtime. For further explanation on the cause of this downtime refer to the “Summary of Gross Margin” section in the 2010 management discussion under Item 5.A.

We have identified de-bottlenecking projects at our Refinery which we anticipate will increase throughput capacity from 115,000 bbl/d to 120,000 bbl/d, improve the yield of distillate products, enhance feedstock receiving and storage facilities and improve process heating design and combustion technologies. The anticipated completion date for the final project is 2013 with total estimated expenditures of approximately $404 million to complete all projects. The debottlenecking projects began in 2009 and $49.3 million had been incurred to date as at December 31, 2010. The project will be funded through cash flows from operations as well as capital available to the Corporation through its capital resources as discussed in Item 5.B of this annual report.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The information presented below for the years ended December 31, 2009 and 2008 are for Harvest Energy Trust, the Corporation’s predecessor; as such, certain amounts may not be comparable to the amounts reported for Harvest Operations Corp. for the year ended December 31, 2010.

A. Operating Results

The following management's discussion and analysis of financial condition and results of operations should be read in conjunction with Item 3.A “Key Information – Selected Financial Information", Item 4 “Information on the Company" and our historical consolidated financial statements and accompanying notes included under Item 17 of this annual report.

YEAR ENDED DECEMBER 31, 2010 COMPARED WITH YEAR ENDED DECEMBER 31, 2009
UPSTREAM OPERATIONS

Summary of Operating Results

		Year Ended December 31
(in $000’s except where noted)		2010			2009		Change

Revenues	$	1,007,005		$	886,308		14%
Royalties		(154,757	)		(128,860	)	20%
Net revenues⁽¹⁾		852,248			757,448		13%

Operating expenses		265,593			258,675		3%
General and administrative		44,974			36,452		23%
Transportation and marketing		9,394			14,228		(34%	)
Depreciation, depletion, amortization and accretion		448,091			450,291		0%
Goodwill impairment		-			677,612		(100%	)

Earnings (Loss) from operations⁽¹⁾	$	84,196		$	(679,810	)	1,124%

Cash contribution⁽¹⁾	$	532,367		$	443,328		20%

Capital expenditures (excluding acquisitions)	$	404,015		$	186,276		117%

Daily sales volumes
Light to medium oil (bbl/d)		24,077			23,651		2%
Heavy oil (bbl/d)		9,253			10,261		(10%	)
Natural gas liquids (bbl/d)		2,587			2,718		(5%	)
Natural gas (mcf/d)		80,881			90,097		(10%	)
Total (boe/d)		49,397			51,646		(4%	)

⁽¹⁾	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this annual report.

Commodity Price Environment

	Year Ended December 31
Benchmarks	2010	2009	Change
West Texas Intermediate crude oil (US$ per barrel)	79.53	61.80	29%
Edmonton light crude oil ($ per barrel)	77.58	65.93	18%
Bow River blend crude oil ($ per barrel)	68.25	59.97	14%
AECO natural gas daily ($ per mcf)	4.00	3.95	1%
Canadian / U.S. dollar exchange rate	0.971	0.880	10%

Differential Benchmarks		2010		2009
Bow River Blend differential to Edmonton Par ($/bbl)	$	9.33	$	5.96
Bow River Blend differential as a % of Edmonton Par		12.0%		9.0%

The average Edmonton light price increased from 2009, due to the higher WTI benchmark price and a tighter sweet differential, partially offset by the stronger Canadian dollar relative to the US dollar. The Bow River price in 2010 increased by 14% reflecting the increase in the WTI prices, but was partially offset by the higher heavy oil differential relative to Edmonton Par. Heavy oil differentials fluctuate based on a combination of factors including the level of heavy oil inventories, pipeline capacity to deliver heavy crude to the U.S. markets and the seasonal demand for heavy oil.

Realized Commodity Prices ⁽¹⁾

	Year Ended December 31
	2010	2009	Change
Light to medium oil ($/bbl)	71.09	58.18	22%
Heavy oil ($/bbl)	59.94	52.91	13%
Natural gas liquids ($/bbl)	58.83	45.03	31%
Natural gas ($/mcf)	4.21	4.29	(2%	)
Average realized price ($/boe)	55.85	47.02	19%

⁽¹⁾	Realized commodity prices exclude the impact of price risk management activities.

Our realized price for light to medium oil sales increased by 22% compared to the prior year, reflecting the 18% increase in Edmonton light pricing. Harvest’s heavy oil price increased by 13% compared to the prior year, reflecting the 14% increase in the Bow River prices. Our average realized price for natural gas changed marginally from the prior year.

Sales Volumes

The average daily sales volumes by product were as follows:

	Year Ended December 31
	2010		2009
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)⁽¹⁾	24,077	49%	23,651	46%	2%
Heavy oil (bbl/d)	9,253	19%	10,261	20%	(10%	)
Natural gas liquids (bbl/d)	2,587	5%	2,718	5%	(5%	)
Total liquids (bbl/d)	35,917	73%	36,630	71%	(2%	)
Natural gas (mcf/d)	80,881	27%	90,097	29%	(10%	)
Total oil equivalent (boe/d)	49,397	100%	51,646	100%	(4%	)

⁽¹⁾ Harvest classifies our oil production, except that produced from Hay River, as light to medium and heavy according to NI 51-101 guidance. The oil produced from Hay River has an average API of 24^o (medium grade) and is classified as a light to medium oil, notwithstanding that, it benefits from a heavy oil royalty regime and therefore would be classified as heavy oil according to NI 51-101.

Light/ medium oil sales volumes in 2010 were 24,077 bbl/d, an increase of 426 bbl/d or 2%. The marginal increase is primarily attributable to the first and third quarter property acquisitions in 2010, partially offset by natural declines.

Heavy oil sales volumes decreased by 10% compared to prior year to 9,253 bbl/d primarily due to natural declines.

Natural gas sales averaged 80,881 mcf/d in 2010, compared to 90,097 mcf/d in the prior year, representing a 10% decrease. This reduction is primarily due to natural declines and reduced spending on gas properties due to weak gas prices, partially offset by the increase in gas sales volumes from assets acquired in the third quarter of 2010.

Revenues

		Year Ended December 31
		2010			2009		Change
Light to medium oil sales	$	624,778		$	502,239		24%
Heavy oil sales		202,445			198,168		2%
Natural gas sales		124,226			141,225		(12%	)
Natural gas liquids sales and other		55,556			44,676		24%
Total sales revenue		1,007,005			886,308		14%
Royalties		(154,757	)		(128,860	)	20%
Net Revenues⁽¹⁾	$	852,248		$	757,448		13%

⁽¹⁾	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this annual report.

Harvest’s revenue is impacted by changes in sales volumes, commodity prices and currency exchange rates. Total 2010 sales revenue of $1,007.0 million is $120.7 million higher than the prior year.

Royalties

Harvest pays Crown, freehold and overriding royalties to the owners of mineral rights from which production is generated. These royalties vary for each property and product and the Crown royalties are based on a sliding scale dependent on production volumes and commodity prices.

Throughout 2010, royalties as a percentage of total revenue were 15.4% (2009 – 14.5%) and aggregated to $154.8 million (2009 - $128.9 million). The increase in the royalty rate throughout 2010 as compared to 2009 is primarily due to higher oil prices.

Operating Expenses

		Year Ended December 31
		2010				2009			Per boe
		Total		Per boe		Total		Per boe	Change
Operating expense
Power and fuel	$	59,106	$	3.28	$	55,892	$	2.97	10%
Well Servicing		50,427		2.80		48,152		2.55	10%
Repairs and maintenance		43,720		2.42		42,834		2.27	7%
Lease rentals and property taxes		30,637		1.70		30,857		1.64	4%
Processing and other fees		13,538		0.75		17,444		0.92	(18%	)
Labour – internal		22,641		1.26		22,616		1.20	5%
Labour – contract		15,966		0.89		15,740		0.83	7%
Chemicals		12,981		0.72		13,946		0.74	(3%	)
Trucking		9,645		0.53		10,488		0.56	(5%	)
Other		6,932		0.38		706		0.04	850%
Total operating expense	$	265,593	$	14.73	$	258,675	$	13.72	7%

Transportation and marketing expense	$	9,394	$	0.52	$	14,228	$	0.75	(31%	)

The 2010 operating costs totaled $265.6 million, an increase of $6.9 million from 2009. On a per boe basis, operating costs have increased by 7% to $14.73/boe as compared to $13.72/boe in the prior year. This increase is largely attributed to higher power and fuel costs, as well as higher activity levels on well servicing and repairs and maintenance, partially offset by decreased processing fees.

		Year Ended December 31
(per boe)		2010		2009	Change
Electric power and fuel costs	$	3.28	$	2.97	10%
Realized losses (gains) on electricity risk management contracts		0.10		0.07	43%
Net electric power and fuel costs	$	3.38	$	3.04	11%
Alberta Power Pool electricity price (per MWh)	$	50.78	$	47.85	6%

The 10% increase in power and fuel costs is mainly due to the increase in the average Alberta Power Pool electricity price. Harvest had electricity price risk management contracts in place throughout 2010 which resulted in a loss of $1.8 million compared to a loss of $1.3 million on the contracts held in place throughout the prior year.

Transportation and marketing expense for 2010 was $9.4 million or $0.52/boe, a decrease of 31% per boe from 2009. The transportation and marketing expense in 2009 was higher due to additional clean oil trucking costs at our Hay River property while the facilities were in turnaround and pipeline service was disrupted.

General and Administrative (“G&A”) Expense

		Year Ended December 31

		2010		2009	Change
G&A	$	44,974	$	35,795	26%
Unit based compensation expense (recovery)		-		658	(100%	)
Total G&A	$	44,974	$	36,453	23%

G&A per boe ($/boe)	$	2.49	$	1.90	31%

For the year ended December 31, 2010, G&A costs increased by $9.2 million compared to the prior year, reflecting higher professional and consulting fees in relation to the internal reorganization as well as an increase in payroll taxes related to KNOC employees seconded to Harvest. Generally, over 80% of the G&A expenses are related to salaries and other employee related costs.

There is no unit based compensation expense in 2010 as the Plan of Arrangement with KNOC resulted in the accelerated vesting and cash payout of all outstanding Trust Unit Incentive Rights and Unit Awards and the cancellation of the Trust Unit Rights Incentive Plan and the Unit Award Plan in December 2009.

Depletion, Depreciation, Amortization and Accretion Expense

		Year Ended December 31
		2010		2009	Change
Depletion, depreciation and amortization	$	387,462	$	407,239	(5%	)
Depletion of capitalized asset retirement costs		35,388		18,315	93%
Accretion on asset retirement obligation		25,241		24,737	2%
Total depletion, depreciation, amortization and accretion	$	448,091	$	450,291	0%
Per boe	$	24.85	$	23.89	4%

Our depletable asset base increased significantly over the prior year due to the aggressive capital program in 2010 as well as the revaluation of our assets resulting from the KNOC Acquisition. However, the impact from this increase in our asset base on our overall depletion, depreciation, amortization and accretion (“DDA&A”) expense was offset by a decrease in our depletion rate due to lower production volumes coupled with an increase in our reserve base. As a result, our DDA&A expense for the year ended December 31, 2010 was relatively unchanged from the prior year.

Capital Expenditures

		Year Ended December 31
		2010		2009
Drilling and completion	$	223,543	$	88,811
Well equipment, pipelines and facilities		107,933		81,626
Land and undeveloped lease rentals		23,803		3,459
Capitalized G&A expenses		13,027		10,756
Geological and geophysical		12,719		1,509
Furniture, leaseholds and office equipment		1,934		114
Total conventional oil and gas capital expenditures		382,959		186,276
BlackGold oil sands		21,056		-
Total development capital expenditures excluding acquisitions	$	404,015	$	186,276

In 2010, approximately 58% of our conventional development capital expenditures were incurred to drill 171 gross wells (141.4 net) with a success rate of 99%, compared to 48% incurred to drill 107 gross wells (76.6 net) with a success rate of 99% in 2009. Harvest had a more active drilling program in 2010 due to strengthening oil prices and increased access to capital following the KNOC Acquisition, and our 2010 drilling activities focused primarily on oil properties.

During 2010, Harvest signed an engineering, procurement and construction (“EPC”) lump sum contract with a third party to build a central processing facility for our BlackGold oil sands project for an aggregate of $311 million. A 10% deposit of $31.1 million was paid in 2010. Year-to-date capital expenditures were $21.1 million, relating to engineering and site preparation work for the main facility and production pad sites. The remaining $289.9 million of the EPC contracted cost is expected to be incurred in 2011 and 2012.

Refer to Item 4.A “Recent Developments” for information on significant acquisitions made in 2010.

DOWNSTREAM OPERATIONS

Summary of Financial and Operational Results

		Year Ended December 31
		2010			2009		Change

Revenues	$	2,949,930		$	2,381,637		24%
Purchased feedstock for processing and products purchased for resale⁽⁴⁾		2,733,019			2,015,671		36%
Gross margin⁽¹⁾		216,911			365,966		(41%	)

Costs and expenses
Operating expense		114,697			102,556		12%
Purchased energy expense		106,126			91,868		16%
Turnaround and catalyst expense		-			47,487		(100%	)
Marketing expense and other		6,366			12,009		(47%	)
General and administrative expense		1,764			1,593		11%
Depreciation and amortization expense		83,091			77,288		8%
Goodwill impairment		-			206,465		(100%	)
Loss from operations⁽¹⁾	$	(95,133	)	$	(173,300	)	(45%	)

Cash contribution⁽¹⁾	$	(12,636	)	$	108,909		(112%	)

Cash capital expenditures	$	71,234		$	43,875		62%

Feedstock volume (bbl/d)⁽²⁾		86,142			83,939		3%

Yield (% of throughput volume)⁽⁵⁾
Gasoline and related products		31%			34%		(3%	)
Ultra low sulphur diesel and jet fuel		36%			40%		(4%	)
HSFO		31%			25%		6%
Total		98%			99%		(1%	)

Average refining margin (US$/bbl)⁽³⁾	$	5.13		$	9.12		(44%	)

⁽¹⁾	These are non-GAAP measures; please refer to “Non-GAAP Measures” in this MD&A.
⁽²⁾	Barrels per day are calculated using total barrels of crude oil feedstock and vacuum gas oil (“VGO”).
⁽³⁾	Average refining margin is calculated based on per barrel of feedstock throughput.
⁽⁴⁾	Purchased feedstock for processing and products purchased for resale.
⁽⁵⁾	Based on production volumes after adjusting for changes in inventory held for resale.

Refining Benchmark Prices

	Year Ended December 31
	2010		2009		Change
WTI crude oil (US$/bbl)	79.53		61.80		29%
Brent crude oil (US$/bbl)	80.29		62.50		28%
RBOB gasoline crack spread (US$/bbl)	9.58		9.06		6%
Heating Oil crack spread (US$/bbl)	10.50		8.13		29%
HSFO crack spread (US$/bbl)	(8.96	)	(6.73	)	33%
Canadian / U.S. dollar exchange rate	0.971		0.880		10%

Summary of Gross Margin

		Year Ended December 31
		2010					2009
			Volumes						Volumes
			(000’s bbls)		(US$/bbl)				(000’s bbls)		(US$/bbl)
Refinery Sales
Gasoline products	$	985,737	10,838	$	88.31	$	851,850		11,014	$	68.06
Distillates		1,114,963	11,740		92.22		972,872		12,169		70.35
High sulphur fuel oil		723,454	9,902		70.94		467,249		7,563		54.37
		2,824,154	32,480		84.43		2,291,971		30,746		65.60
Refinery Feedstock⁽¹⁾
Middle Eastern		1,713,780	21,456		77.56		1,132,066		18,098		55.05
Russian		485,884	5,884		80.18		437,386		5,816		66.18
South American		211,318	2,978		68.90		260,456		4,690		48.87
		2,410,982	30,318		77.22		1,829,908		28,604		56.30
Vacuum Gas Oil		95,519	1,124		82.52		145,806		2,033		63.11
Other⁽²⁾		151,558					(1,491	)
Refinery gross margin⁽³⁾	$	166,095		$	5.13	$	317,748			$	9.12

Marketing
Sales⁽¹⁾	$	569,345				$	479,930
Cost of products sold		518,529					431,714
Marketing gross margin⁽³⁾	$	50,816				$	48,216

⁽¹⁾	Cost of feedstock includes all costs of transporting the crude oil to refinery in Newfoundland.
⁽²⁾	Includes inventory adjustments, additives and blend stocks
⁽³⁾	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.

Due to the unplanned downtime in the first and third quarters of 2010, the average daily throughput was 86,142 bbl/d for the year ended December 31, 2010 as compared to the 115,000 bpd nameplate capacity. The throughput in 2009 was also below capacity at 83,939 bbl/d due to a 42-day planned turnaround in the second quarter coupled with the planned reduction in throughput in the fourth quarter to optimize refinery economics in response to changing market conditions and to conduct planned maintenance.

The unplanned ten-week shutdown of the refinery units in the first quarter of 2010 was due to a fire in early January, while the downtime in the third quarter was due to unplanned maintenance and catalyst change-out in the hydrogen unit. An insurance claim has been submitted relating to the business interruption loss incurred from the fire. As a result of these shutdowns and the shift in product yield, the average refining margin decreased 44% from US$9.12/bbl in the prior year to US$5.13/bbl in 2010. The refinery yields for the year ended December 31, 2010 are impacted by the unplanned shutdowns that resulted in a decrease in the production of gasoline and distillates and an increase in the production of HSFO and VGO.

The cost of our feedstocks reflect numerous factors beyond changes in WTI price, including the quality of the crude oil processed, the mix of crude oil types, the costs of transporting the crude oil to our refinery, the operational hedging of the WTI component of our feedstock costs through the SOA, the ten-day delay in pricing pursuant to the SOA and for Middle Eastern crude oil purchased, the Official Selling Price (“OSP”) as set by the Oil Marketing Company of the Republic of Iraq and the carrying costs of inventories due to shutdowns.

The cost of our crude oil feedstock averaged US$77.22/bbl during 2010 representing a US$2.31/bbl discount from WTI as compared to a cost of US$56.30/bbl and a discount of US$5.50/bbl in the prior year.

The strengthening of the Canadian dollar in 2010 has slightly offset the contribution from our Downstream operations as substantially all of its gross margin, cost of purchased energy and marketing expense are denominated in U.S. dollars.

Operating Expenses

		Year Ended December 31
				2010						2009
		Refining		Marketing		Total		Refining		Marketing		Total

Operating cost	$	93,078	$	21,619	$	114,697	$	82,888	$	19,668	$	102,556
Turnaround and catalyst		-		-		-		47,487		-		47,487
Purchased energy		106,126		-		106,126		91,868		-		91,868
Total operating expense	$	199,204	$	21,619	$	220,823	$	222,243	$	19,668	$	241,911

(Per barrel of throughput)
Operating cost	$	2.96		-		-	$	2.71		-		-
Turnaround and catalyst		-						1.54
Purchased energy		3.38		-		-		3.00		-		-
Total operating expense	$	6.34		-		-	$	7.25		-		-

Refining operating expenses were $2.96/bbl during the year as compared to $2.71/bbl in 2009 reflecting higher maintenance costs as a result of the shutdowns in the first and third quarters of 2010. The $2.0 million increase in operating costs for the marketing division is mainly due to the continued growth of the Orangestores.

The Trust’s accounting policy was to expense all turnaround and catalyst replacement and regeneration expenditures; however, Harvest Operations accounting policy is to capitalize such expenditures, as such, there are no similar expenses in 2010.

Purchased energy, consisting of low sulphur fuel oil (“LSFO”) and electricity, is required to provide heat and power to refinery operations. The 16% increase in purchase energy costs over the prior year is due to a price variance of $18.3 million offset by a volume variance of $4.0 million. All variances include the foreign exchange impact of the strengthening Canadian dollar.

Depreciation and Amortization Expense

		Year Ended December 31
		2010						2009
		Refining		Marketing		Total		Refining		Marketing		Total

Tangible assets	$	79,615	$	3,476	$	83,091	$	67,619	$	3,262	$	70,881
Intangible assets		-		-		-		5,080		1,327		6,407
	$	79,615	$	3,476	$	83,091	$	72,699	$	4,589	$	77,288

Harvest’s accounting policy is to amortize the process units over an average useful life of 20 to 30 years. There are a number of accounting policy differences between the Trust and Harvest Operations, such as the capitalization of turnaround and catalyst costs, estimated useful life and componentization of the assets. As a result, the depreciation of the refining assets by Harvest in 2010 cannot be compared to that of Trust in 2009. In addition, the fair value of the intangible assets was deemed to be $nil in KNOC’s purchase price allocation; therefore, there is no intangible asset amortization in 2010.

Capital Expenditures

Capital spending for the year ended December 31, 2010 totaled $71.2 million (2009 - $43.9 million) relating to various capital improvement projects including $38.1 million (2009 - $11.2 million) associated with the debottleneck projects.

CORPORATE

Cash Flow Risk Management

Harvest periodically enters into derivatives contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changes in market prices due to changes in the underlying indices. Refer to the financial statements included under Item 17 of this annual report for a complete listing of the derivative contracts outstanding at December 31, 2010, 2009 and 2008.

Harvest uses electricity price swap contracts to manage some of its electricity price risk exposures relating to its electricity consumption. For the year ended December 31, 2010, the total realized loss and unrealized gain recognized in the consolidated statement of income relating to the electricity price swap contracts was $1.8 million and $3.1 million respectively ($1.3 million loss and $2.1 million loss respectively for the year ended December 31, 2009).

Harvest’s strategic crude oil hedging program is subject to periodic management reviews to determine appropriate hedge requirements in light of the Company’s tolerance for exposure to market volatility, as well as the need for stable cash flow to finance future growth. During the fourth quarter of 2010, Harvest entered into crude oil swap contracts to reduce the volatility of cash flows from a portion of its forecasted sales. The swaps were designated as cash flow hedges and are entered into for the periods consistent with forecasted petroleum sales. The effective portion of the unrealized loss of $5.0 million (net of deferred tax asset of $1.8 million) was included in other comprehensive income for the year ended December 31, 2010. The ineffective portion of the unrealized loss of $0.7 million was recorded to net income for the year ended December 31, 2010. Throughout 2009 the Trust did not enter into any comparable crude oil hedges.

For the year ended December 31, 2009, the Trust had additional net realized gains and net unrealized losses of $62.8 million and $37.9 million respectively, relating to derivative contracts on refined products, natural gas and currency exchange rates. Harvest did not enter into any comparable derivative contracts throughout 2010.

Interest Expense

		Year Ended December 31
		2010		2009
Interest on short term debt
Bank loan	$	1,370	$	8,747
Convertible debentures		703		149
Senior notes		30		-
Total interest on short term debt		2,103		8,896

Interest on long term debt
Bank loan		4,326		7,835
Convertible debentures		50,827		77,765
Senior notes		20,867		24,413
Total interest expense on long term debt	$	76,020	$	110,943
Total interest expense⁽¹⁾	$	78,123	$	119,839

(1)	Net of capitalized borrowing cost of $0.4 million relating to BlackGold oil sands project

The bank loan, convertible debentures and senior notes are recorded at amortized cost and as such interest is calculated using the effective interest method. Therefore, total interest includes non-cash interest income of $7.0 million for the year ended December 31, 2010 relating to the amortization of the premium on the convertible debentures and 7⁷/₈% Senior Notes net of the fees incurred on the Credit Facility and the 6⁷/₈% Senior Notes. For the year ended December 31, 2009 total interest included non-cash interest expense of $15.5 million relating to the amortization of the discount on the convertible debentures and 7⁷/₈% Senior Notes and the fees incurred on the Credit Facility. The senior notes and convertible debentures were previously recorded net of issue costs and therefore at a discount. However, in the KNOC Acquisition they were revalued to fair value and were carried at a premium; as a result, the non-cash interest component recorded by the Trust in 2009 was an expense whereas Harvest recorded non-cash interest income in 2010.

The decrease in cash interest expense from $104.3 million in 2009 to $85.1 million in 2010 is due to the reduction of our long-term debt in the first quarter of 2010 as a result of the KNOC Acquisition; refer to Recent Developments under Item 4.A of this annual report for more information on the redemption of our convertible debentures and senior notes pursuant to the change of control provision in the debt indentures as well as the reduction of our credit facility.

Currency Exchange

Currency exchange gains and losses are attributed to the changes in the value of the Canadian dollar relative to the U.S. dollar on our U.S. dollar denominated debt as well as any other U.S. dollar working capital balances. The Canadian dollar has continued to strengthen year over year ($US/$CAD: 2008 – 1.218, 2009 – 1.051, 2010 – 0.995) resulting in an unrealized foreign exchange gain of $2.3 million for the year ended December 31, 2010 as compared to a $5.3 million gain in 2009. Realized foreign exchange gains were $1.5 million for the year ended December 31, 2010 compared to realized losses of $3.1 million in 2009.

Our Downstream operations use U.S. dollar as their functional currency. The foreign exchange gains and losses incurred by our Downstream operations relate to Canadian dollar transactions converted to U.S. dollars as their functional currency is U.S. dollars. The cumulative translation adjustment recognized in other comprehensive income represents the translation of our Downstream operation’s U.S. dollar functional currency financial statements to Canadian dollars using the current rate method. During the year ended December 31, 2010, net cumulative translation losses were $46.4 million as compared to $172.1 million for 2009. Losses resulted due to the year over year strengthening of the Canadian dollar against the U.S. dollar, reflecting a decrease in the relative value of the net assets in our Downstream operations.

Future Income Tax

As a result of the reorganization in the second quarter of 2010, Harvest is now a taxable corporate structure with the effective corporate rate applicable to all entities. At December 31, 2010, Harvest recognized $42.5 million of investment tax credits relating to the Downstream operations. As a result of the restructuring of intercompany debt, the Downstream operations are expected to be taxable in the future and will be able to utilize these credits.

At December 31, 2010, Harvest had a net future income tax (“FIT”) liability of $177.2 million (2009 – $211.2 million), comprised of $80 million (2009 – $112.5 million) for the Downstream corporate entities and $97.2 million (2009 – $98.7 million) for the Upstream corporate entities.

As a result of KNOC Canada’s acquisition of the Trust, the opening FIT liability of $211.2 million was reflected as part of the purchase price allocation recorded at that date. The change in the FIT liability between December 31, 2010 and December 31, 2009 was $34 million and resulted from a FIT recovery of $39.9 million recognized in net loss for the year, a FIT recovery of $1.8 million recognized in other comprehensive income relating to the effective portion of hedge contracts, and offset by the FIT liability associated with the Red Earth Partnership acquisition of $7.7 million.

At December 31, 2010, we estimated our unclaimed capital expenditures to be:

Tax classification		Upstream		Downstream		Total
Canadian development & exploration expenditures	$	593,124	$	-	$	593,124
Canadian oil & gas property expenditures		852,862		-		852,862
Unclaimed capital cost		400,223		307,314		707,537
Non-capital losses and other		1,033,918		343,431		1,377,349
	$	2,880,127	$	650,745	$	3,530,872

YEAR ENDED DECEMBER 31, 2009 COMPARED WITH YEAR ENDED DECEMBER 31, 2008
UPSTREAM OPERATIONS
Summary of Operating Results

	Year Ended December 31
(in $000’s except where noted)	2009		2008		Change

Revenues	886,308		1,543,214		(43%	)
Royalties	(128,860	)	(248,445	)	(48%	)
Net revenues	757,448		1,294,769		(41%	)

Operating expenses	258,675		300,890		(14%	)
General and administrative	36,452		32,868		11%
Transportation and marketing	14,228		13,490		5%
Depreciation, depletion, amortization and accretion	450,291		448,735		0%
Goodwill Impairment	677,612		-		100%

Earnings (Loss) From Operations⁽¹⁾	(679,810	)	498,786		(236%	)

Operating Netback ($/boe)
Revenues	47.02		75.39		(38%	)
Royalties	(6.84	)	(12.14	)	(44%	)
Operating expense	(13.72	)	(14.70	)	(7%	)
Transportation and marketing expense	(0.75	)	(0.66	)	14%
Operating netback⁽¹⁾	25.71		47.89		(46%	)

Cash Contribution	443,328		945,930		(53%	)

Capital expenditures (excluding acquisitions)	186,276		271,312		(31%	)

Daily sales volumes
Light to medium oil (bbl/d)	23,651		25,093		(6%	)
Heavy oil (bbl/d)	10,261		12,162		(16%	)
Natural gas liquids (bbl/d)	2,718		2,624		4%
Natural gas (mcf/d)	90,097		96,315		(6%	)
Total (boe/d)	51,646		55,932		(8%	)

⁽¹⁾	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this annual report.

Commodity Price Environment

	Year Ended December 31
Benchmarks	2009	2008	Change

West Texas Intermediate crude oil (US$ per barrel)	61.80	99.65	(38%	)
Edmonton light crude oil ($ per barrel)	65.93	102.02	(35%	)
Bow River blend crude oil ($ per barrel)	59.97	84.10	(29%	)
AECO natural gas daily ($ per mcf)	3.95	8.14	(51%	)

Canadian / U.S. dollar exchange rate	0.880	0.943	(7%	)

During 2009, the average WTI benchmark price was 38% lower than the prior year. The average Edmonton light crude oil price (“Edmonton Par”) also decreased from the prior year to average $65.93 in 2009, a decrease of 35%. The decrease in Edmonton Par has been less than that of the WTI benchmark price due to the relative weakening, on an annual average basis, of the Canadian dollar relative to the US dollar.

Heavy oil differentials fluctuate based on a combination of factors including the level of heavy oil inventories, pipeline capacity to deliver heavy crude to U.S. markets and the seasonal demand for heavy oil. During 2009, the Bow River heavy oil differential relative to Edmonton Par tightened to an average of $5.96/bbl (or 9.0%) compared to $17.92/bbl (or 17.6%) in 2008. On a per barrel basis, heavy oil differentials tightened throughout the year as production shortfalls and increased refinery demand for heavier grades of oil put upward pressure on pricing.

2009

2008

Differential Benchmarks

Bow River Blend differential to Edmonton Par ($/bbl)

7.81

6.62

3.91

5.50

14.07

16.48

21.50

19.63

Bow River Blend differential as a % of Edmonton Par

10.2%

9.2%

5.9%

11.1%

22.2%

13.5%

17.1%

20.2%

Compared to the prior year, the average AECO daily natural gas price was 51% lower during the year ended December 31, 2009. Natural gas prices have weakened as a result of increased storage levels and decreased economic activity which has led to a decline in industrial consumption.

Realized Commodity Prices ⁽¹⁾

The following table summarizes our average realized price by product for 2009 and 2008.

	Year Ended December 31
	2009	2008	Change
Light to medium oil ($/bbl)	58.18	89.72	(35%	)
Heavy oil ($/bbl)	52.91	77.22	(31%	)
Natural gas liquids ($/bbl)	45.03	75.16	(40%	)
Natural gas ($/mcf)	4.29	8.60	(50%	)
Average realized price ($/boe)	47.02	75.39	(38%	)

⁽¹⁾	Realized commodity prices exclude the impact of price risk management activities.

Our realized price for light to medium oil sales decreased by $31.54/bbl (or 35%) compared to the prior year, reflecting the $36.09/bbl (or 35%) decrease in Edmonton Par pricing. Harvest’s heavy oil price decreased by $24.31/bbl (or 31%) compared to the prior year, reflecting the $24.13/bbl (or 29%) decrease in the Bow River price. Our average realized price for natural gas production decreased by $4.31/mcf (or 50%) compared to the prior year, reflecting the $4.19/mcf (or 51%) decrease in AECO daily pricing over the year.

Sales Volumes
The average daily sales volumes by product were as follows:

	Year Ended December 31
	2009		2008
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)⁽¹⁾	23,651	46%	25,093	45%	(6%	)
Heavy oil (bbl/d)	10,261	20%	12,162	22%	(16%	)
Natural gas liquids (bbl/d)	2,718	5%	2,624	5%	4%
Total liquids (bbl/d)	36,630	71%	39,879	72%	(8%	)
Natural gas (mcf/d)	90,097	29%	96,315	28%	(6%	)
Total oil equivalent (boe/d)	51,646	100%	55,932	100%	(8%	)

⁽¹⁾Harvest classifies our oil production, except that produced from Hay River, as light to medium and heavy according to NI 51-101 guidance. The oil produced from Hay River has an average API of 24^o(medium grade) and is classified as a light to medium oil, notwithstanding that, it benefits from a heavy oil royalty regime and therefore would be classified as heavy oil according to NI 51-101.

Our light/ medium oil production was 23,651 bbl/d, a decrease of 1,442 bbl/d or 6%. The decrease is attributed to a combination of some additional downtime in the first quarter associated with cold weather, pipeline service disruptions at our Hay River property in the third quarter due to maintenance and normal decline associated with decreased capital spending throughout 2009.

Our heavy oil production has decreased steadily over the past twelve months resulting in a 16% reduction with year-to-date production of 10,261 bbl/d compared to 12,162 bbl/d in 2008. This reduction is largely the result of normal decline, increased water cuts on our large producing wells in the west central Saskatchewan and Lloydminster areas, and reduced spending on our heavy oil properties due to weak commodity prices.

Our 2009 natural gas production decreased by 6% relative to 2008, averaging 90,097 mcf/d. This reduction is due to normal decline resulting from reduced capital spending, downtime at certain third-party processing facilities in the Second Quarter 2009 coupled with the divestment of our Channel Lake properties, partially offset by production added from the acquisition of Pegasus in August 2009.

Revenues

		Year Ended December 31
(000’s)		2009			2008		Change
Light to medium oil sales	$	502,239		$	824,014		(39%	)
Heavy oil sales		198,168			343,717		(42%	)
Natural gas sales		141,225			303,303		(53%	)
Natural gas liquids sales and other		44,676			72,180		(38%	)
Total sales revenue		886,308			1,543,214		(43%	)
Royalties		(128,860	)		(248,445	)	(48%	)
Net Revenues	$	757,448		$	1,294,769		(41%	)

Our revenue is impacted by changes in production volumes, commodity prices and currency exchange rates. Our 2009 total sales revenue of $886.3 million is $656.9 million lower than the prior year, of which $534.9 million is attributed to lower realized prices and $122.0 million is in respect of lower production volumes. The price decrease reflects the 35% decrease in Edmonton Par pricing and the 51% decrease in AECO daily natural gas pricing, while our decreased production volume is attributed to decline rates and a reduction in current year capital spending.

Light to medium oil sales revenue for 2009 was $321.8 million lower than the prior year due to a $272.3 million unfavourable price variance coupled with a $49.5 million unfavourable volume variance. Heavy oil sales revenue of $198.2 million in 2009 was $145.5 million lower than in the prior year due to a $91.0 million unfavourable price variance and a $54.5 million unfavourable volume variance. Natural gas sales revenue decreased by $162.1 million due to a $141.7 million unfavourable price variance and a $20.4 million unfavourable volume variance.

During 2009, natural gas liquids and other sales revenue decreased by $27.5 million compared to the prior year resulting from a $29.9 million unfavourable price variance offset by a $2.4 million favourable volume variance. Generally, the natural gas liquids volume variance will be aligned with our production of natural gas while the price variances will be aligned with the prices realized for our oil production.

Royalties

We pay Crown, freehold and overriding royalties to the owners of mineral rights from which production is generated. These royalties vary for each property and product and our Crown royalties are based on a sliding scale dependent on production volumes and commodity prices.

Throughout 2009, net royalties as a percentage of gross revenue were 14.5% (2008 – 16.1%) and aggregated to $128.9 million (2008 - $248.4 million). The decrease in our royalty rate throughout 2009 as compared to 2008 is due to reduced royalty rates in a lower commodity price environment as mandated by the Government of Alberta’s new Royalty Framework.

Operating Expenses

		Year Ended December 31
		2009				2008			Per boe
(000’s except per boe amounts)		Total		Per boe		Total		Per boe	Change
Operating expense
Power and fuel	$	55,892	$	2.97	$	80,162	$	3.92	(24%	)
Well Servicing		48,152		2.55		52,561		2.57	(1%	)
Repairs and maintenance		42,834		2.27		51,462		2.51	(10%	)
Lease rentals and property taxes		30,857		1.64		27,953		1.37	20%
Processing and other fees		17,444		0.92		15,073		0.74	24%
Labour – internal		22,616		1.20		23,785		1.16	3%
Labour – contract		15,740		0.83		17,128		0.84	(1%	)
Chemicals		13,946		0.74		15,968		0.78	(5%	)
Trucking		10,488		0.56		11,297		0.55	2%
Other		706		0.04		5,501		0.26	(85%	)
Total operating expense	$	258,675	$	13.72	$	300,890	$	14.70	(7%	)

Transportation and marketing expense	$	14,228	$	0.75	$	13,490	$	0.66	14%

Our 2009 operating costs totaled $258.7 million, a reduction of $42.2 million from 2008. On a per barrel basis, operating costs have decreased 7% to $13.72/boe as compared to $14.70/boe in the prior year, substantially attributed to reduced power and fuel costs due to the decrease in the average Alberta electric power price (2009 - $47.85/MWh, 2008 - $89.95/MWh), and to a lesser extent, reductions in repairs and maintenance expenses as a result of reduced activity in the industry in the current year.

We had electric power price risk management contracts in place from April 2009 through December 2009 which resulted in a loss of $1.3 million compared to a gain of $10.0 million on the contracts held in place throughout the prior year. The following table details the electric power costs per boe before and after the impact of our price risk management program.

		Year Ended December 31
(per boe)		2009		2008		Change
Electric power and fuel costs	$	2.97	$	3.92		(24%	)
Realized losses (gains) on electricity risk management contracts		0.07		(0.49	)	114%
Net electric power and fuel costs	$	3.04	$	3.43		(11%	)
Alberta Power Pool electricity price (per MWh)	$	47.85	$	89.95		(47%	)

Transportation and marketing expense for 2009 was $14.2 million or $0.75/boe, an increase of 14% per boe from $13.5 million or $0.66 per boe in 2008. The increased transportation and marketing expense in 2009 is primarily due to additional clean oil trucking costs at our Hay River property while the facilities were in turnaround and pipeline service was disrupted. These costs relate primarily to delivery of natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and our cost of trucking clean crude oil to pipeline receipt points. As a result, the total dollar amount of costs fluctuates in relation with our production volumes while the cost per boe typically remains relatively constant.

General and Administrative (“G&A”) Expense

		Year Ended December 31
(000’s except per boe)		2009		2008		Change
Cash G&A	$	35,795	$	33,643		7%
Unit based compensation expense (recovery)		658		(775	)	185%
Total G&A	$	36,453	$	32,868		11%

Cash G&A per boe ($/boe)	$	1.90	$	1.64		16%

For the year ended December 31, 2009, Cash G&A costs increased by $2.2 million (or 7%) compared to the prior year, reflecting higher employee costs in a continued tight market for technically qualified staff in the western Canadian petroleum and natural gas industry. Generally, over 80% of our Cash G&A expenses are related to salaries and other employee related costs.

Our unit based compensation plans provided employees with the option of settling outstanding awards with cash. As a result, unit based compensation expense is determined using the intrinsic method, being the difference between the Trust Unit trading price and the strike price of the unit awards adjusted for the proportion that is vested. The Plan of Arrangement with KNOC resulted in the accelerated vesting and cash payout of all outstanding Trust Unit Incentive Rights and Unit Awards on December 31, 2009 and accordingly, the unit based compensation expense recognized. The market price of our Trust Units was $10.50 at December 31, 2008 compared to $10.00 on December 22, 2009 when the Trust Unit Incentive Rights and Unit Awards were settled. Total unit based compensation expense increased $1.4 million in 2009 compared to 2008 as the result of the settlement of the unit based compensation plan with the closing of the acquisition of Harvest by the Korea National Oil Corporation (“KNOC”) in December.

Depletion, Depreciation, Amortization and Accretion Expense

		Year Ended December 31
(000’s except per boe)		2009		2008	Change
Depletion, depreciation and amortization	$	407,239	$	414,969	(2%	)
Depletion of capitalized asset retirement costs		18,315		15,135	21%
Accretion on asset retirement obligation		24,737		18,631	33%
Total depletion, depreciation, amortization and accretion	$	450,291	$	448,735	0%
Per boe	$	23.89	$	21.92	9%

Our overall depletion, depreciation, amortization and accretion (“DDA&A”) expense for the year ended December 31, 2009 was relatively unchanged from the prior year. The nominal increase is attributed to slightly higher finding, development and acquisition costs that have increased our depletion rate, partially offset by lower production volumes.

Cash Contribution

Upstream operations contributed $443.3 million of cash, down from $945.9 million in the prior year, reflecting the 38% year-over-year drop in realized commodity prices and an 8% reduction in production, partially offset by lower operating costs.

Capital Expenditures

		Year Ended December 31
(000’s)		2009		2008
Land and undeveloped lease rentals	$	3,459	$	7,762
Geological and geophysical		1,509		6,782
Drilling and completion		88,811		164,628
Well equipment, pipelines and facilities		81,626		81,680
Capitalized G&A expenses		10,756		10,235
Furniture, leaseholds and office equipment		114		225
Development capital expenditures excluding acquisitions and non-cash items		186,276		271,312
Non-cash capital additions (recoveries)		1,604		(251	)
Total conventional oil and gas capital expenditures		187,880		271,061
BlackGold oil sands		-		-
	$	187,880	$	271,061

In 2009, approximately 48% of our development capital expenditures were incurred to drill 107 gross wells with a success rate of 99%, compared to 247 gross wells with a success rate of 100% in 2008. Drilling activity was down in 2009 relative to 2008 due to the low oil price environment encountered at the start of the year, and although prices did strengthen during the year, Harvest maintained a reduced capital budget throughout 2009.

Our 2009 capital development program of $186.3 million was complemented by our acquisition of Pegasus Oil & Gas which was completed in August 2009 at a cost of approximately $19 million and was the only significant acquisition made during the year. Harvest used 2009 to capture value on some of the minor assets within our portfolio, and completed approximately $ 64.8 million of dispositions. With a reduced level of investment relative to 2008 and increased focus on dispositions, Harvest Gross Proved Reserves at December 31, 2009 dropped to 140.3 mmboe as compared to 154.3 mmboe at December 31, 2008, and Gross Proved plus Probable Reserves were 199.5 mmboe as compared to 219.9 mmboe.

DOWNSTREAM OPERATIONS
Summary of Financial and Operational Results

	Year Ended December 31
(in $000’s except where noted below)	2009		2008	Change

Revenues	2,381,637		4,194,595	(43%	)
Purchased feedstock for processing and products purchased for resale⁽⁴⁾	2,015,671		3,850,507	(47%	)
Gross margin⁽¹⁾	365,966		344,088	6%

Costs and expenses
Operating expense	102,556		98,736	4%
Purchased energy expense	91,868		131,878	(30%	)
Turnaround and catalyst expense	47,487		5,645	741%
Marketing expense and other	12,009		20,753	(42%	)
General and administrative expense	1,593		1,875	(15%	)
Depreciation and amortization expense	77,288		71,076	9%
Goodwill impairment	206,465		-	100%
Earnings (loss) From Operations⁽¹⁾	(173,300	)	14,125	(133%	)

Cash Contribution	108,909		83,592	30%

Cash capital expenditures	43,875		56,162	(21%	)

Feedstock volume (bbl/d)⁽²⁾	83,939		103,497	(19%	)

Yield (000’s barrels)
Gasoline and related products	10,499		12,068	(13%	)
Ultra low sulphur diesel and jet fuel	12,196		15,668	(22%	)
HSFO	7,538		9,952	(24%	)
Total	30,233		37,688	(20%	)

Average refining margin (US$/bbl)⁽³⁾	9.12		7.16	27%

⁽¹⁾ These are non-GAAP measures; please refer to “Non-GAAP Measures” in this MD&A.
⁽²⁾ Barrels per day are calculated using total barrels of crude oil feedstock and vacuum gas oil (“VGO”).
⁽³⁾Average refining margin is calculated based on per barrel of feedstock throughput.
⁽⁴⁾ Purchased feedstock for processing and products purchased for resale includes inventory write-downs of $2.4 million for the year ended December 31, 2009 ($35.3 million for the year ended December 31, 2008).

Refining Benchmark Prices

The following average benchmark prices and currency exchange rates are the reference points from which we discuss our refinery’s financial performance:

	Year Ended December 31
	2009	2008	Change
WTI crude oil (US$/bbl)	61.80	99.65	(38%)
Brent crude oil (US$/bbl)	62.50	98.38	(36%)
Basrah Official Sales Price (“OSP”) Discount (US$/bbl)	(3.23)	(7.40)	(56%)
RBOB gasoline (US$/bbl / US$/gallon)	70.86/1.69	104.40/2.49	(32%)
Heating Oil (US$/bbl / $US/gallon)	69.93/1.67	119.89/2.85	(42%)
HSFO (US$/bbl)	55.07	73.13	(25%)
Canadian / U.S. dollar exchange rate	0.880	0.943	(7%)

During 2009, the Heating Oil Crack Spread averaged US$8.13/bbl, a decrease of US$12.11/bbl over the US$20.24/bbl averaged in the prior year, as previously strong demand for distillate products in North America, Europe and Asia decreased, reducing margins. The RBOB Gasoline Crack Spread averaged US$9.06/bbl in 2009, an improvement of US$4.31/bbl from the US$4.75/bbl averaged in the prior year, as North American refinery output was curtailed to balance the continued weak demand resulting from the slowdown in economic activity. Similarly, the HSFO Crack Spread differential averaged US$6.73/bbl less than WTI in 2009, an increase of US$19.79/bbl from the average differential of US$26.52/bbl less than WTI in the prior year, as the prices of heavy sour crude oils improved substantially in the fourth quarter of 2008 and remained relatively stable throughout 2009.

During 2009, the Canadian/U.S. dollar exchange rate averaged $0.880, a decrease of $0.063 from the prior year. The relative weakening of the Canadian dollar resulted in a nominal increase in our cash flows from Downstream operations in 2009, as refined product and crude oil prices are denominated in U.S. dollars.

Summary of Gross Margin

The following table summarizes our Downstream gross margin for the years ended December 31, 2009 and 2008 segregated between refining activities and petroleum marketing and other related businesses.

Year Ended December 31

2009

2008

(000’s of Canadian dollars)

Refining

Marketing

Total

Refining

Marketing

Total

Sales revenue⁽¹⁾

2,291,971

479,930

2,381,637

4,092,555

670,686

4,194,595

Cost of feedstock for processing and

products for resale⁽¹⁾

1,974,223

431,714

2,015,671

3,804,952

614,201

3,850,507

Gross margin⁽²⁾

317,748

48,216

365,966

287,603

56,485

344,088

Average refining margin (US$/bbl)

9.12

7.16

⁽¹⁾	Downstream sales revenue and cost of products for processing and resale are net of intra-segment sales of $390.3 million for the year ended December 31, 2009 (2008 - $568.6 million) reflecting the refined products produced by the refinery and sold by the Marketing Division.
⁽²⁾	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.

Refining Gross Margin

Throughout 2008, refining margins averaged US$7.16/bbl, as crack spreads were particularly strong for distillate products with distillate margins averaging US$29.91/bbl for the year, while gasoline and HSFO crack spreads were relatively weak averaging US$6.68/bbl and US$(16.78)/bbl, respectively, reflecting increased feedstock costs and decreasing consumer demand for gasoline products particularly in the Fourth Quarter 2008.

In 2009, gasoline and HSFO margins improved over the prior year, while distillate margins softened considerably resulting in an average refining margin of US$9.12/bbl. This US$1.96/bbl improvement over the prior year reflects the US $14.40/bbl improvement in HSFO margins from US$(16.78)/bbl to US$(2.38)bbl, particularly in the First Quarter of 2009 when the HSFO margin was positive US$4.20/bbl, reflecting improved margins on these lower valued petroleum products. Similarly, gasoline margins improved by US$4.63/bbl to US$11.31/bbl in 2009. These margin improvements were offset by a US$16.31/bbl decrease in distillate margins from US$29.91/bbl in 2008 to US$13.60/bbl in 2009.

Refinery Throughput

During 2009, our feedstock was composed of 78,367 bpd of medium sour crude oil and 5,571 bpd of VGO as compared to 93,697 bpd of crude oil and 9,800 bpd of VGO in the prior year. Our aggregate total throughput in 2009 was 83,939 bpd, a 19,558 bpd decrease over the prior year reflecting a utilization rate of 73% relative to a 115,000 bpd nameplate capacity. Relative to 2008, refinery throughput was 19% lower, primarily attributed to a 42-day planned turnaround in the Second Quarter of 2009 coupled with the planned reduction in throughput in the Fourth Quarter of 2009 to optimize refinery economics in response to changing market conditions and to conduct some planned maintenance on the crude and platformer units. The planned turnaround was performed on the hydrocracking and hydrogen units and saw replacement of distillate hydrotreating and hydrocracking catalyst, as well as regeneration of the naphtha reforming unit catalyst, after which the refinery returned to near-capacity throughput for most of the Third Quarter. The refinery experienced limited planned or unplanned downtime in 2008, though our throughput was intentionally reduced from May through August in an effort to improve overall gross margin by reducing feedstock to eliminate the production of vacuum tower bottoms (“VTB’s”) in excess of our visbreaker unit capacity, thereby eliminating the need to downgrade middle distillate valued streams to blend the excess VTB’s into lower valued HSFO.

Refinery Sales Revenue

A comparison of our refinery yield, product pricing and revenue for the years ended December 31, 2009 and 2008 is presented below:

Year Ended December 31

2009

2008

Refinery

Volume

Sales

Refinery

Volume

Sales

Revenues

Price

Revenues

Price⁽¹⁾

(000’s of Cdn $)

(000’s of bbls)

(US$ per bbl/

(000’s of Cdn $)

(000’s of bbls)

(US$ per bbl/

US$ per US gal)

Gasoline products

851,850

11,014

68.06/1.62

1,327,599

12,830

97.58/2.32

Distillates

972,872

12,169

70.35/1.68

2,006,406

15,661

120.81/2.88

HSFO

467,249

7,563

54.37

758,550

9,651

74.12

2,291,971

30,746

65.60

4,092,555

38,142

101.18

Inventory adjustment

(513

)

(454

)

Total production

30,233

37,688

Yield (as a % of Feedstock)

98.7%

99.7%

For the year ended December 31, 2009, our refinery yield was composed of 35% gasoline products, 40% distillates and 25% HSFO compared to 32%, 42% and 26% for the same products during 2008. Although our yield can be altered slightly by adjusting refinery operations to react to market conditions and seasonal demand, product yields are primarily impacted by the type of crude oil feedstock processed and refinery performance. The shift in product yield in 2009 from distillates to gasoline is attributed to end-of-run activity of the hydrocracker catalyst as well as other end-of-run conditions in the First Quarter 2009 prior to the scheduled turnaround completed in the Second Quarter of 2009 as well as operational and feedstock changes to capitalize on the improved gasoline margins in 2009.

Relative to the average WTI benchmark price, in 2009 our refined products sold at an average premium of US$2.27/bbl higher than in the prior year. In 2009, our average sales price was US$65.60/bbl (a premium of US$3.80/bbl over WTI) as compared to an average selling price of US$101.18/bbl in the prior year (a premium of US$1.53/bbl over WTI). This increase in premium represents a $79.3 million price variance in 2009.

During 2009, the average sales premium to the average WTI benchmark price for our gasoline was US$6.26/bbl as compared to a US$2.07/bbl discount to WTI realized in 2008 representing a $104.3 million increase in gross margin as compared to the prior year. This US$8.33 improvement in gasoline refining margins relative to WTI reflects the reduction in North American refinery gasoline output to balance the continued weak demand resulting from the slowdown in economic activity.

During 2009, the average sales premium to the average WTI benchmark price for our distillate products was US$8.55/bbl as compared to a US$21.16/bbl premium over WTI realized in 2008 representing a $174.4 million decrease in gross margin as compared to the prior year. During 2009, global demand for distillate products weakened relative to the prior year resulting in poorer relative margins. As well, in 2009 the generally weaker margins for distillates were partially offset by US$0.7 million of incremental revenue from delivering approximately 2.7 million barrels of distillate products to Europe pursuant to our profit sharing arrangement with Vitol (in 2008 US$7.9 million of incremental revenue from delivery of approximately 7.5 million barrels).

During 2009, the average sales discount to the average WTI benchmark price for our HSFO was US$7.43/bbl as compared to a US$25.53/bbl discount in 2008 representing a $155.6 million improvement in gross margin as compared to the prior year. The US$18.10/bbl improvement in our HSFO pricing relative to WTI reflects the US$19.79/bbl improvement in the HSFO benchmark crack spread.

Refinery Feedstock

The volatility of WTI prices throughout 2009 makes it difficult to compare the economics of crude types when our consumption of crude type varies from month-to-month and costs are aggregated over the year. Further, our refinery processes international waterborne crude oils and VGO’s and the WTI benchmark price generally reflects a land-locked North American price with limited access to the international markets.

The cost of our feedstocks reflect numerous factors beyond changes in WTI price, including the quality of the crude oil processed, the mix of crude oil types, the costs of transporting the crude oil to our refinery, the ten-day delay in pricing pursuant to the SOA and, for our Iraqi crude oil purchases, the Official Selling Price (“OSP”) as set by the Oil Marketing Company of the Republic of Iraq. On a monthly basis, the OSP is announced as a discount to the WTI benchmark price for North American deliveries and is influenced by the quality of the crude oil as well as by the demand from contract purchasers in other regions.

A comparison of crude oil and VGO feedstock processed for the years ended December 31, 2009 and 2008 is presented below:

Year Ended December 31

2009

2008

Cost of

Volume

Cost per

Cost of

Volume

Cost per

Feedstock

Barrel ⁽¹⁾

Feedstock

Barrel ⁽¹⁾

(000’s of Cdn $)

(000’s of bbls)

(US$/bbl)

(000’s of Cdn $)

(000’s of bbls)

(US$/bbl)

Iraqi

1,132,066

18,098

55.05

1,963,882

21,218

87.28

Russian

437,386

5,816

66.18

614,187

5,973

96.97

Venezuelan

260,456

4,690

48.87

676,777

7,102

89.86

Crude Oil Feedstock

1,829,908

28,604

56.30

3,254,846

34,293

89.50

VGO

145,806

2,033

63.11

396,676

3,586

104.31

1,975,714

30,637

56.75

3,651,522

37,879

90.90

Net inventory adjustment ⁽²⁾

(28,183

)

(8,990

)

Additives and blendstocks

33,971

127,136

Inventory write-down (recovery) ⁽³⁾

(7,279

)

35,284

1,974,223

3,804,952

	⁽¹⁾	Cost of feedstock includes all costs of transporting the crude oil to refinery in Newfoundland.

	⁽²⁾	Inventories are determined using the weighted average cost method.

	⁽³⁾	Inventory write-downs are calculated on a product by product basis using the lower of cost or net realizable value.

Although the OSP discount may change between the date of loading in Iraq and its eventual processing later at our refinery, the OSP discount applicable at the time of loading does not change for our purchase. For example, the OSP discount of US$4.05 in February 2009 was a component of the cost of our feedstock processed in April and May recognizing the 30 to 45 days required to load in Iraq, transport to our refinery in Newfoundland, and storage residence time before processing. Although the SOA provides for operational hedging of the risk of WTI price variations between the time of pricing of our feedstocks and the time of processing, we are not able to hedge or otherwise manage the basis risk to WTI price associated with the medium sour crude oils we typically process.

When we commit to crude oil purchases, Vitol sells a forward WTI price contract for the appropriate futures contract month, which results in cash market price fluctuations subsequent to our purchase commitment being offset by the price fluctuations of the futures contract. If the crude oil is not processed before the expiration of the forward contract, the volume of the forward contract relating to unprocessed crude oil is rolled to the next futures contract month. This practice results in better matching of our refined product sales prices with our cost of feedstock. The persistent contango shape of the NYMEX WTI futures price curve since October 2008 has resulted in operational hedging gains from the rolling forward of these price contracts, which reduced our feedstock costs in the month the feedstock is processed. During 2009, this operational hedging resulted in reductions to the cost of our feedstock of US$73.2 million, as compared to the prior year when this operational hedging resulted in reductions to the cost of feedstock of US$0.4 million.

The cost of our crude oil feedstock averaged US$56.30/bbl during 2009 representing a US$5.50/bbl discount from WTI as compared to a cost of US$89.50/bbl and a discount of US$10.15/bbl in the prior year. The US$5.50 discount is composed of a US$3.07/bbl quality discount (2008 – US$6.30/bbl) and a US$2.35/bbl operational hedging gain (2008 – US$0.01/bbl) offset by a US$0.08/bbl reduction relating to timing under the SOA (2008 – US$3.83/bbl) .

The average cost of purchased VGO during 2009 was US$63.11/bbl representing a premium of US$1.31/bbl relative to the WTI benchmark price as compared to US$104.31/bbl and a US$4.66/bbl premium in the prior year. The reduced premium in 2009 is attributed to reduced demand for VGO as a consequence of reduced gasoline demand coupled with the benefit of our operational hedging.

Operating Expenses

The following summarizes the operating costs from the refinery and marketing division for the years ended December 31, 2009 and 2008:

	Year Ended December 31
		2009			2008
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total

Operating expense	82,888	19,668	102,556	78,907	19,829	98,736
Turnaround and catalyst	47,487	-	47,487	5,645	-	5,645
Purchased energy	91,868	-	91,868	131,878	-	131,878
	222,243	19,668	241,911	216,430	19,829	236,259

The largest component of refining operating expense is wages, salaries and benefits which totaled $49.3 million during 2009 (2008 - $49.6 million) while the other significant components were maintenance and repair costs of $15.0 million (2008 - $13.2 million), insurance of $6.2 million (2008 - $5.7 million) and professional services of $3.5 million (2008 - $5.1 million). Refining operating expenses were $2.71/bbl during the year as compared to $2.08/bbl in 2008 reflecting decreased throughput and an increase in total refining operating expenses, particularly repair and maintenance costs. The marketing division’s operating expenses have remained relatively unchanged from the prior year.

Turnaround and catalyst expenditures for the year ended December 31, 2009 of $47.5 million relate to costs incurred in preparation for, and completion of, the scheduled turnaround in the Second Quarter of 2009 of the hydrocracking and hydrogen units, replacement of distillate hydrotreating and hydrocracking catalyst and the regeneration of the naptha reforming unit catalyst. Of the total costs incurred related to the turnaround, $21.5 million relates to catalyst replacement and regeneration expenditures, while the balance relates to other turnaround activities. Harvest’s accounting policy is to expense all turnaround and catalyst replacement and regeneration expenditures, while capitalizing projects that provide future economic benefit. Turnaround and catalyst expenditures incurred in 2008 of $5.6 million relate to planned equipment certifications scheduled during the shutdown to implement the visbreaker unit expansion project.

Purchased energy, consisting of low sulphur fuel oil (“LSFO”) and electricity, is required to provide heat and power to refinery operations. Our purchased energy for the year ended December 31, 2009 was $3.00/bbl of throughput as compared to $3.48/bbl for 2008. In 2009, we purchased approximately 1.3 million barrels of LSFO at an average price of US$56.80/bbl as compared to approximately 1.6 million barrels purchased in 2008 at an average price of US$72.79/bbl. The $38.9 million decrease in the cost of purchased LSFO is due to a $21.3 million decreased price variance and a $17.6 million decrease in volume consumed. Our electricity costs decreased during the year at $9.0 million as compared to $10.1 million in the prior year, a result of reduced average throughput.

Marketing Expense and Other

During the year ended December 31, 2009, marketing expense was composed of $2.9 million (2008 - $3.4 million) of marketing fees (based on US$0.08/bbl) to acquire feedstock and $9.1 million (2008 - $26.0 million) of time value of money (TVM”) charges both pursuant to the terms of the SOA. The decreased TVM charge is mainly the result of a reduced crude oil inventory investment associated with lower commodity prices. At December 31, 2009, Harvest had commitments totaling approximately $582.1 million in respect of future crude oil feedstock purchases and related transportation from Vitol.

Depreciation and Amortization Expense

The following summarizes the depreciation and amortization expense for the years ended December 31, 2009 and 2008:

Year Ended December 31

2009

2008

(000’s of Canadian dollars)

Refining

Marketing

Total

Refining

Marketing

Total

Tangible assets

67,619

3,262

70,881

62,383

2,555

64,938

Intangible assets

5,080

1,327

6,407

4,749

1,389

6,138

72,699

4,589

77,288

67,132

3,944

71,076

The process units are amortized over an average useful life of 15 to 25 years. The intangible assets, consisting of engineering drawings, customer lists, and fuel supply contracts, are amortized over a period of 20 years, 10 years, and the term of the expected cash flows, respectively.

Cash Contribution

Downstream operations contributed $108.9 million of cash reflecting modestly improved refining margins partially offset by reduced annual throughput due to the turnaround of the hydrocracking and hydrogen units.

Capital Expenditures

Capital spending for the year ended December 31, 2009 totaled $43.9 million (2008 - $56.2 million) relating to various capital improvement projects including $11.2 million associated with the debottleneck projects.

Goodwill

At December 31, 2008, we had $216.2 million of goodwill on our balance sheet related to the October 2006 acquisition of our Downstream business segment. As our Downstream assets are held in a self-sustaining subsidiary with a U.S. dollar functional currency, our goodwill is adjusted at each balance sheet date to reflect the end of period foreign exchange rate. We assess our goodwill for impairment on an annual basis unless events or changes in circumstances warrant more frequent testing. To assess goodwill for potential impairment we compare the estimated fair value of the business segment at the balance sheet date to the recorded net book value. If the estimated fair value exceeds the net book value, no further evaluation is required. Management uses judgment in determining the estimated fair value using internal assumptions and external information to compute the present value of expected future cash flows using discount rates commensurate with the risks involved.

At June 30, 2009, it was determined that an impairment test was required due to expectations of lower refining gross margins and the probable deferral of certain future capital expenditures. The fair value of the Downstream reporting unit was determined using a discounted cash flow approach which incorporated management’s expectations of future throughput and expenses and the forward curve for refined product crack spreads. At June 30, the fair value of the Downstream reporting unit was below its carrying value, indicating a potential impairment. The fair value of the Downstream goodwill was determined by valuing the reporting unit’s net assets in the same manner as allocating a purchase price in a business combination. As the carrying value of the reporting unit’s goodwill exceeded its fair value, it was determined that the goodwill associated with the Downstream reporting unit was fully impaired. Accordingly, a charge of $206.5 million was recorded in the financial results for the year ended December 31, 2009.

CORPORATE

Cash Flow Risk Management

Harvest employs an integrated approach to cash flow risk management strategies whereby our cash flow from producing crude oil in western Canada is financially integrated with 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 32,000 bbls/d of refined product price exposure, 57,000 bbls/d of refined product crack spread exposure and 68,000 mcf/d of net western Canadian natural gas price exposure.

Our cash flow risk management program includes a detailed analysis of the impact of changes in crude oil prices, natural gas prices, the U.S./Canadian dollar exchange rate and certain refined product prices. The table below provides a summary of the gains and losses realized on our price risk management contracts for the years ended December 31, 2009 and 2008:

		Year Ended December 31

(000’s)		2009			2008		Change
Crude oil	$	-		$	(36,625	)	100%
Refined product		45,705			(174,129	)	126%
Natural gas		(129	)		(381	)	66%
Currency exchange rates		18,492			401		4,511%
Electric Power		(1,265	)		9,952		(113%	)
Total realized gain (loss)	$	62,803		$	(200,782	)	131%

During 2009, our net realized gain on price risk management contracts was $62.8 million (2008 – loss of $200.8 million), an increase of $263.6 million over the prior year, primarily due to gains on our refined product pricing contracts of $45.7 million (2008 – loss of $174.1 million), as well as increased gains on our currency exchange contracts. Additionally, Harvest did not have any crude oil contracts in place throughout 2009 as compared to having losses on crude oil contracts totaling $36.6 million in 2008.

In respect of refined products, we had pricing contracts in place for 12,000 bbl/d of NYMEX heating oil and 8,000 bbl/d of Platts heavy fuel oil for the first six months of 2009. The cash settlements of these contracts aggregated to $35.2 million and $10.5 million, respectively, during the year.

We had contracted to fix the US/Canadian dollar exchange rate for the period July 2009 through December 2009 on US$15.0 million per month at an average of Cdn$1.282 per US $1.00. Harvest received $18.5 million in settlements on this contract during the year.

During the First Quarter of 2009 we entered into a fixed price power contract for 10 MWh at $61.90 per MWh for the period of April 2009 through December 2009. This contract resulted in losses of $1.3 million as the Alberta electric power prices averaged $47.85 per MWh during the period. The fixed price contract ended in December 2009. Beginning January 2010, we have contracted to fix 25 MWh at an average of $59.22 through December 2010.

As of December 31, 2009, the mark-to-market deficiency on our fixed price power contracts was $2.1 million. We had no contracts for WTI, refined products, natural gas or currency exchange at the end of December 2009. Further details on our financial instruments and risk management contracts are included in Note 20 to the audited consolidated financial statements for the year ended December 31, 2009 included under Item 17 of this annual report.

*Interest Expense*
		Year Ended December 31

(000’s)		2009		2008	Change
Interest on short term debt
Bank loan	$	8,747	$	-	100%
Convertible Debentures		149		295	(49%	)
Amortization of deferred finance charges – short term debt		-		-	n/a
		8,896		295	2916%

Interest on long-term debt
Bank loan		7,835		51,855	(85%	)
Convertible Debentures		77,765		69,159	12%
7⁷/₈% Senior Notes		24,413		22,662	8%
Amortization of deferred finance charges – long term debt		930		2,699	(66%	)
		110,943		146,375	(24%	)
Total interest expense	$	119,839	$	146,670	(18%	)

Interest expense, including the amortization of related financing costs, decreased $26.8 million (18%) compared to the prior year as interest on our bank borrowings has decreased by $35.3 million due to lower borrowing costs, while total interest expense on Convertible Debentures has increased as a result of our 2008 Convertible Debenture offering.

The interest on our $1.6 billion Extendible Revolving Credit Facility is at a floating rate based between 70 to 75 basis points over bankers’ acceptances for Canadian dollar borrowings. During the year, interest charges on bank loans reflected an effective interest rate of 1.44% .

The interest on our Convertible Debentures totaled $77.9 million during 2009, representing a $8.5 million increase over the prior year. The increase is due to the impact of the four additional months of interest on the 7.5% Convertible Debenture issued on April 25, 2008. Interest on the Convertible Debentures is based on the effective yield of the debt component of the Convertible Debentures, and as a result, the interest expense recorded is greater than the cash interest paid.

The interest on our 7⁷/₈% Senior Notes totaled $24.4 million for the year ended December 31, 2009. Similar to our Convertible Debentures, interest expense is based on the effective yield, and as a result, the interest expense recorded is greater than the cash interest paid.

Included in short and long term interest expense is the amortization of the discount on the 7⁷/₈% Senior Notes, the accretion on the debt component balance of the Convertible Debentures to face value at maturity, as well as the amortization of commitment fees and legal costs incurred for our credit facility, all totaling $0.9 million for the year ended December 31, 2009.

Currency Exchange

Currency exchange gains and losses are attributed to the changes in the value of the Canadian dollar relative to the U.S. dollar on our U.S. dollar denominated 7⁷/₈% Senior Notes as well as any other U.S. dollar cash balances. Realized foreign exchange losses of $3.1 million for 2009, have resulted from the settlement of U.S. dollar denominated transactions. Since December 31, 2008, the Canadian dollar has strengthened compared to the U.S dollar from 1.218 to a rate of 1.051 at December 31, 2009, resulting in a year-to-date unrealized foreign exchange gain of $5.3 million. Of this unrealized gain, $41.0 million relates to the 7⁷/₈% Senior Notes, offset by $35.9 million of unrealized foreign exchange loss attributed to Downstream transactions.

Our Downstream operations are considered a self-sustaining operation with a U.S. dollar functional currency. The foreign exchange gains and losses incurred by our Downstream operations relate to Canadian dollar transactions converted to U.S. dollars as their functional currency is U.S. dollars. The cumulative translation adjustment recognized in other comprehensive income represents the translation of our Downstream operation’s U.S. dollar functional currency financial statements to Canadian dollars using the current rate method. During 2009, the strengthening of the Canadian dollar relative to the U.S. dollar resulted in a $172.1 million net cumulative translation gain (2008 – net gain of $284.7 million) as the stronger U.S. dollar results in an increase in the relative value of the net assets in our Downstream operations.

KNOC Acquisition Related Costs

Harvest incurred $18.4 million of costs relating to the acquisition of Harvest Trust Units by KNOC which includes $13.6 for advisory services, $2.6 million for management contract payouts and $2.2 million for the settlement of the Trust Unit Rights Incentive Plan and the Unit Award Plan.

Future Income Tax

During 2009, there was a significant change in the corporate structure of Harvest that impacted our accounting for future income taxes. As a result of the acquisition by KNOC on December 22, 2009, Harvest is no longer a public trust and is therefore no longer subject to the SIFT tax legislation that passed in Bill C-52 in June 2007 which made the distributions of publicly traded trusts subject to tax. Management does not intend on having income accumulate in the trust; however, in the event that this occurred, tax free distributions could be made to KNOC Canada to eliminate any taxable income. This results in an effective tax rate of zero for Harvest’s flow through entities which led to a reversal of the remaining future tax liability that was initially booked upon the enactment of the SIFT rates in the second quarter of 2007. A recovery of $224.7 million relating to this reversal was realized through equity during 2009 as it arose from a change in shareholder status, while a recovery of $28 million was reflected in the income statement. The additional movement was due to a future tax asset of $15 million being recorded on the Pegasus acquisition.

At the end of 2009, Harvest had a net future income tax asset on the balance sheet of $64.8 million, comprised of a $91 million future income tax liability for the Downstream corporate entities and an offsetting future income tax asset of $155.8 million for the Upstream corporate entities. This compares to a future income tax liability of $204 million at the end of the prior year, comprised of a $372.6 million provision for our various flow through entities and a $168.6 million net asset for our corporate entities.

At the end of 2009, we estimated our unclaimed capital expenditures to be:

Tax Classification (in millions)		Trust		Upstream		Downstream		Total
Canadian Oil & Gas Property Expenditures	$	487.0	$	313.2	$	-	$	800.2
Canadian Development & Exploration Expenditures		-		309.9		-		309.9
Unclaimed Capital Costs		-		361.3		314.3		675.6
Non-capital losses and other		25.1		823.6		317.3		1,166.0
Total	$	512.1	$	1,808.0	$	631.6	$	2,951.7

OUTLOOK

The improving economic climate bodes well for Harvest and our planned 2011 capital expenditures reflect this growing sense of optimism, as well as our sound financial backing from KNOC. Harvest’s commitment to growth resulted in an initial 2011 capital budget of $1.5 billion.

Our Upstream spending plan allots $525 million to acquire Hunt Oil Company of Canada’s producing and undeveloped assets in Western Canada. The transaction was closed on February 28, 2011. Further, $566 million of Upstream capital spending is intended to facilitate our active drilling program and continue our investment in longer term Enhanced Oil Recovery (EOR) projects. Our drilling plan includes ongoing development of assets that provide for volume growth opportunity and high returns on our investments, such as the Hay River area and the Red Earth’s promising Slave Point light oil resource play. In addition to this, we plan to be active in the Viking, Cardium, and Ellerslie light oil plays, bringing our total forecasted wells drilled to over 250. Harvest continues to focus on exploiting oil or liquids-rich natural gas opportunities, as we have little dry gas assets in our portfolio.

Rounding out our Upstream capital spending is the $240 million we plan to invest in BlackGold. Of this cost, $190 million is allocated to the construction and design of the BlackGold facility and $50 million is planned to be spent drilling 10 production well pairs, 12 observation wells, as well as developing other capital growth opportunities. 2011 is slated to be an important year for this project, as a substantial portion of the detailed engineering, procurement and construction will take place in the coming months.

With the delay in closing the Hunt transaction, production reduction associated with the non-operated Rainbow Pipeline disruption, the impact of northern Alberta forest fires and flooding in SE Saskatchewan, our expected 2011 Upstream production is approximately 60,000 boe/d (70% of this production will consist of crude oil and liquids). We will continue to focus on cost-effective methods of operating and expect our operating costs to average approximately $14.54/boe in 2011.

In our Downstream operations, we plan to spend approximately $199 million on capital projects in 2011. This includes $73 million intended for a planned refinery turnaround, $62 million allotted to refinery debottleneck projects, $55 million intended for ongoing capital expenditures, and $9 million assigned to our retail marketing assets. 2011 full-year refinery throughput is forecasted to average 85,000 bbl/d of feedstock, with operating and purchased energy costs aggregating to approximately $7.60/bbl.

From a financial standpoint, we will continue to leverage on our convertible debentures, 6⁷/₈% senior notes, and extendible revolving Credit Facility, balanced with KNOC-held equity. Our exposure to interest rate fluctuations will continue to be managed by maintaining a mix of short and long term financing that carries both floating and fixed interest rates. We are anticipating the average amount drawn on the Credit Facility to climb to approximately $250 million in 2011, which subjects approximately 16% of our interest rate exposure to floating rates.

While we do not speculate on commodity prices or refining margins, we do enter into price risk management contracts to mitigate price volatility and stabilize cash flow from operating activities. In the first quarter of 2011, we held WTI hedging contracts on 16,400 bbl/d of crude oil for the remainder of 2011 with an average contract price of US$93.54/bbl.

B. Liquidity and Capital Resources

Harvest manages its cash requirements by optimizing the capital structure of the Corporation and maintaining sufficient liquid financial resources to fund obligations as they come due in the most cost effective manner.

LIQUIDITY

The Corporation’s liquidity needs are met through the following sources: cash generated from operations, borrowings under our Credit Facility, long-term debt issuances and equity injections by KNOC. Harvest’s primary uses of funds are operating expenses, capital expenditures, and interest and principal payments on debt instruments.

The following table summarizes the Corporation’s sources and amounts of cash flows:

(000’s)		2010			2009			2008
Cash provided by (used in):
Operating activities	$	430,254		$	473,602		$	655,887
Financing activities		212,527			(263,446	)		(219,723	)
Investing activities		(629,320	)		(209,618	)		(431,973	)
Effect of exchange rate changes on cash		5,445			(538	)		(4,191	)
Net increase (decrease) in cash and cash equivalents	$	13,461		$	-		$	-

For the year ended December 31, 2010, cash flow from operating activities was $430.3 million including $22.6 million provided by a reduction in non-cash working capital and $20.3 million used in the settlement of asset retirement obligations as compared to $473.6 million including a $1.9 million increase in non-cash working capital and $14.3 million used in the settlement of asset retirement obligations in 2009 and $655.9 million including a $9.9 million increase in non-cash working capital and $11.4 million used in the settlement of asset retirement obligations in 2008. At December 31, 2010, Harvest’s financing activities provided $212.5 million of cash, including $558.5 million capital injections from KNOC and the issue of $495.9 million 6⁷/₈% senior notes, which was used to fund the repayment of $406.7 million of bank debt, the redemption of $256.9 million of 7⁷/₈% senior notes and the redemption of $180.2 million of convertible debentures. Harvest funded $651.5 million of capital expenditures and net asset acquisition activity during 2010 with cash generated from operating activities and financing activities.

Harvest had working capital of $2.0 million at December 31, 2010, as compared to a deficiency of $582.4 million at December 31, 2009 and $5.7 million at December 31, 2008. The negative working capital in 2009 was primarily related to the $428 million of bank loan and the classification of $172.1 million and $41.9 million of convertible debentures and senior notes, respectively as current liabilities. A portion of the bank loan and convertible debentures were repaid during 2010 with capital injections from KNOC. The Corporation’s working capital is expected to fluctuate from time to time, and will be funded from cash flows from operations and borrowings from Harvest’s credit facility, as required.

As well as future petroleum and natural gas prices, our Upstream operations rely on the successful exploitation of our existing reserves, future development activities and strategic acquisitions to replace existing production and add additional reserves. With a prudent maintenance program, our Downstream assets are expected to have a long life with additional growth in profitability available by upgrading the HSFO currently produced and/or expanding our refining throughput capacity. Future development activities and acquisitions in our Upstream business as well as the maintenance program in our Downstream business will likely be funded from cash flow from operating activities, while we will generally rely on funding more significant acquisitions and growth initiatives from some combination of cash flow from operating activities, issuances of incremental debt and capital injections from KNOC. Should incremental debt not be available to us through debt capital markets, our ability to make the necessary expenditures to enhance or expand our assets may be impaired.

Harvest’s liquidity is closely related to its ability to generate cash from operating activities, which is affected by changes in commodity prices, market demands for petroleum and natural gas products and the operating performances of both our Upstream and Downstream assets. Harvest periodically enters into derivatives contracts such as forwards, futures, swaps, options and costless collars to protect the Corporation from cash flow fluctuations due to commodity price changes. Harvest’s strategic crude oil hedging program is subject to periodic management reviews to determine appropriate hedge requirements in light of the Corporation’s tolerance for exposure to market volatility, as well as the need for stable cash flow to finance future growth. During the fourth quarter, Harvest entered into crude oil swap contracts to reduce the volatility of cash flows from a portion of its forecasted sales. The swaps were designated as cash flow hedges and are entered into for the periods consistent with forecasted petroleum sales. Harvest also uses electricity price swap contracts to manage some of its electricity price risk exposures relating to its electricity consumption.

Through a combination of cash available at December 31, 2010, cash from operating activities, available undrawn credit capacity and the working capital provided by the supply and offtake agreement with Vitol, it is anticipated that Harvest will have sufficient working capital to fund future operations, debt repayments and forecasted capital expenditures (excluding major acquisitions). Refer to the contractual obligations table in Item 5.F below for Harvest’s future commitments including the maturity of our existing debt and our capital commitments.

CAPITAL RESOURCES

The outstanding securities of Harvest consist of the common shares, senior notes and convertible debentures.

The authorized capital consists of an unlimited number of common shares and an unlimited number of preferred shares issuable in series. All of the outstanding common shares are held by KNOC. See "Recent Developments" under Item 4.A of this annual report for a complete description of the capital transactions that occurred during the year and as a result of the KNOC Acquisition.

At December 31, 2010 Harvest had $486 million available in undrawn credit capacity on its $500 million credit facility. See Item 10.C for a summary of the terms of the credit facility.

On October 4, 2010 Harvest issued the 6⁷/₈% Senior Notes, which are governed by the terms and conditions of the Note Indenture; see Item 10.C for a summary of the terms of this indenture. The notes are issued by Harvest Operations and guaranteed by the subsidiaries who guarantee the Credit Facility.

As a result of the internal reorganization during 2010, Harvest Operations became the parent entity of the Operating Subsidiaries, and in accordance with the provisions of the Debenture Indenture, as the parent entity it assumed the Trust's obligations under the Debentures. Under the completion of the KNOC Arrangement, an automatic adjustment to the conversion privilege occurred for each outstanding series of Debentures such that the Debentures are no longer convertible into Trust Units. See Item 10.C for a summary of the terms of the Debenture Indenture.

The following table summarizes the Corporation’s capital structure as at December 31, 2010:

*(000’s)*		December 31, 2010
Debts
Revolving credit facility⁽¹⁾	$	14,000
6⁷/₈% senior notes, at principal amount (US$500 million) ⁽²⁾		497,300
Convertible debentures, at principal amount		733,973
Total Debt		1,245,273

Shareholder’s Equity
330,953,567 common shares issued at December 31, 2010		3,250,942

Total Capitalization	$	4,496,215

(1)	Net of transaction costs – $11.4 million

(2)	Principal amount converted at the period end exchange rate.

Harvest Operations is rated by both Standard and Poor’s (“S&P”), a division of the McGraw-Hill Companies Inc., and Moody’s Investors Services Inc. (“Moody’s”). Harvest’s corporate ratings are “BB-” from S&P and Ba2 from Moody’s. The 6⁷/₈% Senior Notes are rated “BB-” by S&P and Ba1 by Moody’s. All ratings have a stable outlook.

C. Research and Development

Not applicable.

D. Trend Information

The Corporation is not aware of any trends that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. For information on risks associated with Harvest refer to Item 3.D Risk Factors

E. Off-Balance Sheet Arrangements

As of December 31, 2010, we have no off balance sheet arrangements in place.

F. Tabular Disclosure of Contractual Obligations.

						Maturity
		Total		Less than 1 year		1-3 years		3-5 years		After 5 years
Long-term debt⁽¹⁾	$	1,245,273	$	-	$	451,344	$	296,629	$	497,300
Interest on long-term debt⁽¹⁾		401,952		87,200		160,754		94,167		59,831
Operating and premise leases		28,751		7,514		13,355		7,602		280
Purchase commitments⁽²⁾		806,193		694,651		111,542		-		-
Asset retirement obligations⁽³⁾		1,242,033		16,148		30,756		34,185		1,160,944
Transportation ⁽⁴⁾		4,259		3,253		1,006		-		-
Pension contributions⁽⁵⁾		24,783		5,318		7,590		7,850		4,025
Feedstock commitments⁽⁶⁾		900,131		900,131		-		-		-
Total	$	4,653,375	$	1,714,215	$	776,347	$	440,433	$	1,722,380

(1)	Assumes constant foreign exchange rate.

(2)	Relates to drilling commitments, AFE commitments, BlackGold oil sands project commitment, Hunt’s assets purchase agreement and Downstream purchase commitments. The total purchase commitments as at March 31, 2011 were $310.6 million.

(3)	Represents the undiscounted obligation by period.

(4)	Relates to firm transportation commitment on the Nova pipeline.

(5)	Relates to the expected contributions for employee benefit plans.

(6)	Relates to feedstock commitments under the supply and offtake agreement and commitments to purchase refined product for resale.

G. Safe Harbor

See “SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS.”

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. Directors and Senior Management

The names, jurisdiction of residence, present positions and offices with Harvest and principal occupations during the past five years of the directors and executive officers of Harvest Operations at December 31, 2010 are set out in the table below.

	Position with
Name and Jurisdiction of	Harvest
Residence	Operations	Principal Occupation

Dr. Seong-Hoon Kim ⁽⁴⁾ Seoul, South Korea	Director, Chairman since January, 2010.	Dr. Kim is currently a director and the Senior Executive Vice President of KNOC. He has held the position of Executive Vice President for New Ventures & Business Exploration as well as other senior management positions within the New Ventures and Exploration division of KNOC.

William A. Friley Jr.⁽²⁾⁽⁴⁾ Alberta, Canada	Director from 2006 to 2009 and reappointed in January, 2010.	Mr. Friley is the President and Chief Executive Officer of Telluride Oil and Gas Ltd., President of Skyeland Oils Ltd., and Chairman of TimberRock Energy Corporation. He is also a Director of OSUM Oil Sands Corp. and a Director of SilverStar Energy Services and Advanced Flow Technologies Inc. Prior to this he acted as President and Chief Executive Officer of Triumph Energy Corporation (a publicly traded oil and natural gas company). Mr. Friley is a previous Director of Mustang Resources Inc. (a publicly traded oil and natural gas company) and a past Chair of Canadian Association of Petroleum Producers.

J. Richard Harris⁽¹⁾⁽²⁾ Alberta, Canada	Director since January, 2010.	Mr. Harris is an independent oil and gas consultant in Calgary, Alberta. He was previously the President of four Canadian publicly traded oil and gas companies and has served on the boards of nine other energy and energy service related companies. He was a member of the Alberta Securities Commission's Oil and Gas Securities Taskforce that led to the completion of National Instrument 51-101 and he served on the Commission's Reserve Advisory Committee until his retirement from the Committee in 2005. Mr. Harris is a member of several industry societies and holds the designations of Professional Geologist in Canada and Certified Petroleum Geologist and Certified Professional Geological Scientist in the United States.

	Position with
Name and Jurisdiction of	Harvest
Residence	Operations	Principal Occupation

Chang-Koo Kang⁽⁴⁾ Seoul, South Korea	Director since January, 2010.	Mr. Kang is currently the Vice President of KNOC’s Finance Management Department. Prior to this, he was the Senior Manager of KNOC’s Finance Team. He has helped finance KNOC’s merger and acquisition of PetroTech Peruana S.A., Peru, Harvest Energy, and Sumble JSC, Kazakhstan while in office.

William D. Robertson⁽¹⁾ Alberta, Canada	Director from 2008 to 2009 and reappointed in January, 2010.	Mr. Robertson is a Fellow Chartered Accountant and retired Partner of PricewaterhouseCoopers LLP where he acted as lead oil and gas specialist. He is currently a director of Inter Pipeline Fund and Cinch Energy Corp. Mr. Robertson has served on the CIM Petroleum Society Standing Committee on Reserve Definitions, the Alberta Securities Commission Financial Advisory Committee, the working sub-committee of the Alberta Securities Commission Taskforce of Oil and Gas Reporting, and the Council of the Institute of Chartered Accounts of Alberta.

Brant Sangster^{(1) (3)} Alberta, Calgary	Director since November, 2010.	Mr. Sangster is currently a director of Canadian Oil Sands Limited, Inter Pipeline Fund, and Titanium Corporation. Mr. Sangster enjoyed a 25-year career as a senior executive with Petro-Canada, where he was responsible for managing the company's oil sands businesses. Prior to this, Mr. Sangster held various strategic planning and operating positions with Imperial Oil Ltd.

Kang Hyun Shin⁽³⁾ Seoul, South Korea	Director since November, 2010.	Mr. Shin is currently KNOC's Vice President of Petroleum Marketing. Prior to this he acted as the Senior Manager for KNOC’s Legal Team as well as the Senior Manager for the KNOC’s Management Planning Team and the Senior Manager for the Strategic Planning Team. Mr. Shin holds an M.A. of Public Administration from the Graduate School of Public Administration, Seoul National University in South Korea.

Kyungluck Sohn⁽³⁾ Alberta, Canada	Chief Financial Officer since February, 2010; Director since November, 2010.	Mr. Sohn is currently the Chief Financial Officer of Harvest Operations. Prior to this he was a Vice President of KNOC, in the Finance Management Department in 2009 and in the Offshore Rig Operations department from May 2006 to December 2008. Mr. Sohn also held positions in KNOC as Administration Manager in the Ulsan Gas Terminal, Financing Manager and Information Manager in the Petroleum Information department and Marketing Manager in the Offshore Rig Operations department. Prior to these roles, he held a senior position in the Procurement department of Hyundai Heavy Industry Co., Ltd for four years. Mr. Sohn holds a Business Management degree from the Busan National University in South Korea.

Myunghuhn Yi⁽⁴⁾ Seoul, South Korea	Director since December, 2010.	Mr. Yi is currently the Executive Vice President for KNOC’s America Group. Prior to this, he acted as KNOC’s General Manager & Managing Director for the USA office and the Executive Vice President for Domestic Exploration and Production.

John E. Zahary^{(2) (3)} Alberta, Canada	President & Chief Executive Officer, Director since 2008⁽⁴⁾	Mr. Zahary has been the President & Chief Executive Officer of Harvest Operations since February 2006. From 2004 to 2006 he acted as President and Chief Executive Officer of Viking and prior thereto was President of Petrovera Resources. Mr. Zahary holds a BSc. in Mechanical Engineering from the University of Calgary and an M.Phil in Management from the University of Oxford.

Rob Morgan Alberta, Canada	Chief Operating Officer – Upstream	Mr. Morgan is Harvest Operations’ Chief Operating Officer – Upstream. Prior thereto, he was Vice President, Operations and Corporate Development of Viking from June 2004 to February 2006. Mr. Morgan is a professional engineer.

Brad Aldrich⁽⁵⁾ Missouri, USA	Chief Operating Officer – Downstream	Mr. Aldrich is Harvest Operations’ Chief Operating Officer – Downstream. From 2006 to 2007 he was President & Chief Operating Officer of Changing World Technologies and from 2005 to 2006 was Vice President of Thermodyne Holdings Corp. Prior to this, he was Vice President, Production Yukos Oil Company.

	Position with
Name and Jurisdiction of	Harvest
Residence	Operations	Principal Occupation

Brian Kwak Alberta, Canada	Deputy Chief Operating Officer – Upstream & Vice President, Oil sands	On January 19, 2010, Mr. Kwak was appointed Deputy Chief Operating Officer, Upstream and Vice President, Oil sands of Harvest Operations. From November, 2006 to January, 2010 he was Manager, Subsurface of KNOC Canada and from August, 2005 to November, 2006 was Manager, Offshore Drilling Rig of KNOC. Prior to this, he acted as the Deputy Manager, Exploration of Cuulong Joint Operating Company in Vietnam. Mr. Kwak holds a M. Sc and B. Sc Geology.

Gary Boukall Alberta, Canada	Vice President, Geosciences	Mr. Boukall is the Vice President, Geosciences of Harvest Operations. From December, 2002 to March, 2007 he held various positions with Harvest Operations including Chief Geologist, Manager of Geology and Manager of Geosciences. Mr. Boukall is a professional Geologist.

James Sheasby Alberta, Canada	Vice President, Engineering	On March 16, 2007 Mr. Sheasby was appointed to Vice President, Engineering of Harvest Operations. From February, 2006 to March, 2007 he was Manager, Engineering of Harvest Operations. Prior to this, he was the Manager, Engineering of Viking and the Vice President, Engineering of Hygait Resources. Mr. Sheasby is a Professional Engineer.

Neil Sinclair Alberta, Canada	Vice President, Operations	On March 16, 2007, Mr. Sinclair was appointed Vice President, Operations of Harvest Operations. From February, 2006 to March 2007 he was Manager, Operations of Harvest Operations and from June, 2004 to February, 2006 he was the Manager, Operations of Viking.

Phil Reist Alberta, Canada	Vice President, Controller	On March 16, 2007, Mr. Reist was appointed Vice President, Controller of Harvest Operations. From February, 2006 to March, 2007 he was Controller of Harvest Operations and from September, 2005 to February 2, 2006 he was Controller of Viking. Prior to this Mr. Reist was Vice President, Controller of Penn West Petroleum Ltd. Mr. Reist is a Chartered Accountant.

Les Hogan Alberta, Canada	Vice President, Land	On December 3, 2007, Mr. Hogan was appointed Vice President, Land of Harvest Operations. From June, 2002 to November, 2007 he held various positions including Vice President Land and Community Affairs at Pioneer Natural Resources Canada.

Dean Beacon Alberta, Canada	Vice President, Treasurer	On March 5, 2010 Mr. Beacon was appointed Vice President in addition to his existing role as Treasurer of Harvest Operations since 2007. Previously, Mr. Beacon held various senior management positions within the corporate finance, risk management and treasury departments within the Canadian banking industry as well as with oil and gas companies such as TransCanada Pipe Lines and Talisman Energy.

Jongwoo Kim Alberta, Canada	Chief Strategy Officer & Corporate Secretary	Mr. Kim has recently been appointed the Chief Strategy Officer and Corporate Secretary of Harvest Operations. Prior to this, since January 2010, Mr. Kim was the VP, Business Planning and Corporate Secretary at Harvest. Before joining Harvest, he held various positions at KNOC over a 17 year period. His previous role with KNOC was acting as the Merger and Acquisition Team Lead. Mr. Kim holds a Master of Science in Finance graduate degree from the Daniel's College of Business, University of Denver.

(2)	Member of the Audit Committee.

(3)	Member of the Upstream Reserves, Safety & Environment Committee.

(4)	Member of the Downstream Operations, Safety & Environment Committee.

(5)	Member of the Compensation and Corporate Governance Committee.

(6)	Brad Aldrich held the Chief Operating Officer – Downstream position from 2006 to March 24, 2011.

As at December 31, 2010, none of the directors and executive officers of Harvest Operations and their associates and affiliates, directly or indirectly, beneficially owned, controlled or directed any of the outstanding shares.

B. Compensation

COMPENSATION OF DIRECTORS

The independent directors of Harvest Operations Corp. were paid an annual retainer of $30,000, as well as $1,000 for each Board meeting attended, $1,000 for each committee meeting attended (if on a date different from a Board meeting date) and each such director was entitled to reimbursement for expenses incurred in carrying out his duties as director. Where applicable, retainer fees were pro-rated for a partial year’s service.

The following table sets forth all compensation provided to the independent directors of Harvest Operations for the most recently completed financial year, December 31, 2010. The non-independent directors received no compensation for carrying out their duties as directors.

		Fees		Annual			Total
		earned		Retainer⁽²	⁾		compensation
Name		($)		($)			($)
Dennis Balderston⁽¹⁾	$	13,000	$	29,178		$	42,178
William A. Friley	$	9,000	$	29,178		$	38,178
J. Richard Harris	$	16,000	$	29,178		$	45,178
William Robertson	$	11,000	$	29,178		$	40,178
Brant Sangster	$	1,000	$	2,384		$	3,384

(1)	As at December 31, 2010 Mr. Balderston resigned from the Harvest Board of Directors.

(2)	Mr. Balderston, Friley, Harris, and Robertson were paid an annual retainer fee that was prorated from January 11, 2010 until December 31, 2010. Mr. Sangster was paid a retainer fee that was prorated from December 3, 2010 until December 31, 2010.

COMPENSATION OF OFFICERS AND MANAGEMENT

The following table sets forth for the year ended December 31, 2010 information concerning the compensation paid to Harvest’s executive officers and senior management. The Chief Executive Officer (“CEO"), Chief Financial Officer ("CFO") and the next three most highly compensated individuals at December 31, 2010 are individually identified while the remainders of individuals disclosed in Item 6.A are shown in aggregate.

		Short-term	Long-term
		incentive	incentive	All other	Total
Name	Salary	plans⁽²⁾	plans⁽⁵⁾	compensation⁽³⁾	compensation
John Zahary⁽¹⁾⁽⁴⁾	418,000	271,700	485,591	75,753	1,251,044
Kyungluck Sohn⁽⁴⁾⁽⁶⁾	147,230	33,558	nil	109,451	290,239
Robert Morgan⁽¹⁾	224,862	121,306	189,475	30,832	566,475
Phil Reist	231,000	60,060	116,906	30,157	438,123
Neil Sinclair	231,000	60,060	126,649	33,300	451,009
Other⁽⁷⁾	1,381,391	202,921	400,309	393,796	2,378,417

(1)	Harvest Operations has entered into employment agreements with Mr. Zahary and Mr. Morgan. Please see the section below entitled "Termination Benefits" for further details.

(2)	The above amounts were paid to each individual shortly after the end of the fiscal year.

(3)	Includes the employer’s contributions to a savings plan (equal to 10% of salary) and other taxable benefits.

(4)	Mr. Zahary and Mr. Sohn are directors of Harvest Operations, but did not receive compensation for their services as directors.

(5)	Half of the compensation for the 2010 long-term incentive plan was paid in 2011, with the remainder to be paid in 2012.

(6)	Mr. Sohn participates in the KNOC employee compensation program, but does not participate in Harvest’s incentive programs, as he is a secondee to Harvest Operations from KNOC.

(7)	Includes remaining executive officers and senior management included in Item 6.A.

SHORT-TERM INCENTIVE PROGRAM

In the Upstream business, Harvest uses the following metrics to assess performance: production volume, finding, development and acquisition costs on a per BOE basis, earnings before interest, taxes, depreciation and amortization (EBITDA), operating and transportation costs on a per BOE basis, and safety (lost time injury frequency). In the Downstream business, Harvest uses the following metrics to assess performance: sales volume, EBITDA, non-fuel operating costs on a per BOE basis and safety (lost time injury frequency). Bonuses were based on these measures being met and the degree to which they were met along with individual performance assessment.

Cash bonuses were awarded to the individuals included in the “Summary Compensation Table” below based on their leadership of the business resulting in:

Delivery of a cash contribution from Upstream operations of $532 million versus $443 million on a pro-forma basis in 2009;
Investment of $404 million in Upstream capital asset additions plus $176 million in net property and business acquisitions (before consideration of the BlackGold purchase from KNOC or the announced acquisition for $525 million at the end of the year which closed in 2011) resulting in net overall additions of more than 350% over 2009 on a pro-forma basis;
Management through an active year of credit facility refinancing, senior note offering refinancing including the issuance in October 2010 of US$500 million of 6⁷/₈% Senior Notes and equity issues totaling approximately $930 million;
Maintenance and enhancement of Harvest’s presence in capital markets; and
Enhancement of Harvest’s corporate presence under the equity ownership of KNOC in the active and competitive market in the Canadian oil and gas industry.

LONG-TERM INCENTIVE PROGRAM

All employees (including the Named Executive Officers) are eligible to participate in Harvest's long-term incentive program, which is designed to reward individual and corporate performance in the form of deferred cash payments. These payments are subject to the achievement of the Corporation’s key performance indicators as discussed above. The value of the award may also consider individual performance and the competitive industry environment.

C. Board Practices

TERM OF OFFICE

Directors are elected or appointed yearly at the annual meeting and the terms of office of all directors expire at the following annual meeting; see Item 6.A above for the period that each Director has served in their current term of office.

TERMINATION BENEFITS

Harvest has entered into an executive employment agreement with each of Mr. Zahary (President and Chief Executive Officer) and Mr. Morgan (Chief Operating Officer - Upstream). Each such agreement provides that, in the event of termination of employment without cause, the executive shall be entitled to receive a cash payment equal to a multiple of the executive's total monthly compensation based on (i) his then annual base salary, (ii) an amount equal to 20% of base salary for loss of benefits and (iii) an amount equal to the average annual bonus payments made in the two prior years (or the last annual bonus or a reasonable estimate thereof if only one bonus year or no bonus year has been completed, as the case may be), plus any amount that the executive may be entitled to receive under any long-term incentive plan of Harvest Operations. The agreed multiple is 15 months of total monthly compensation plus one additional month for each full or partial year of service under the agreement (commencing December 22, 2009) to a maximum of 18 months.

If the employment of any of Messrs. Zahary or Morgan is terminated for cause or in the event of permanent disability (within the meaning of the employment agreement), or if any such executive shall voluntarily resign his employment, the executive shall be entitled to receive payment of any earned but unpaid base salary, but shall not be entitled to receive any bonus, severance or termination pay or other payment for loss of employment.

There are no agreements providing for benefits upon termination of employment/service for any other employees or directors.

AUDIT COMMITTEE

The members of the Audit Committee are J. Richard Harris, Brant Sangster and William D. Robertson. The mandate and terms of reference under which the audit committee operates are as follows:

ROLE AND OBJECTIVE

The Audit Committee (the "Committee") is a committee of the board of directors (the "Board") of Harvest Operations Corp. (“HOC”) to which the Board has delegated its responsibility for oversight of the nature and scope of the annual audit, management’s reporting on internal accounting standards and practices, financial information and accounting systems and procedures, financial reporting and statements and recommending, for approval of the Board, the audited financial statements, interim financial statements and other mandatory disclosure releases containing financial information. The primary objectives of the Committee with respect to HOC and its subsidiaries, (hereinafter collectively referred to as “Harvest”) are as follows:

1.	to assist directors meet their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of Harvest and related matters;

2.	to ensure that Harvest complies with all applicable laws, regulations, rules, policies and other requirements of governments, regulatory agencies and stock exchanges relating to financial reporting and disclosure;

3.	to enhance that Harvest’s accounting functions are performed in accordance with a system of internal controls designed to capture and record properly and accurately all of the financial transactions;

4.	to provide better communication between directors and external auditor(s);

5.	to enhance the external auditor’s independence;

6.	to increase the credibility and objectivity of financial reports; including that such reports are accurate within a reasonable level of materiality and present fairly Harvest’s financial position and performance in accordance with generally accepted accounting principles consistently applied; and

7.	to strengthen the role of the outside directors by facilitating in depth discussions between directors on the Committee, management and external auditor(s).

MEMBERSHIP OF COMMITTEE

1.	The Committee shall be comprised of at least three (3) directors of Harvest Operations, none of whom are members of management of Harvest Operations and all of whom are "unrelated directors" (as such term is used in the Report of the Toronto Stock Exchange on Corporate Governance in Canada) and "independent" (as such term is used in Multilateral Instrument 52-110 – Audit Committees ("MI 52-110") unless the Board shall have determined that the exemption contained in Section 3.6 of MI 52-110 is available and has determined to rely thereon.

2.	All of the members of the Committee shall be "financially literate" (as defined in MI 52-110) unless the Board shall determine that an exemption under MI 52-110 from such requirement in respect of any particular member is available and has determined to rely thereon in accordance with the provisions of MI 52-110.

3.	Unless otherwise designated by the Board, the members of the Committee shall elect a Chairman from among the members and the Chair shall preside at all meetings of the Committee.

MANDATE AND RESPONSIBILITIES OF COMMITTEE

1.	It is the responsibility of the Committee to oversee the work of the external auditor(s), including resolution of disagreements between management and the external auditor(s) regarding financial reporting.

2.	It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to Harvest's Internal Control Systems:

identifying, monitoring and mitigating business risks; and
ensuring compliance with legal, ethical and regulatory requirements.

3.	It is a primary responsibility of the Committee to review the annual and interim financial statements of Harvest and related management's discussion and analysis ("MD&A") prior to their submission to the Board for approval. The process should include but not be limited to:

reviewing changes in accounting principles and policies, or in their application, which may have a material impact on the current or future years’ financial statements;
reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;
reviewing accounting treatment of unusual or non-recurring transactions;
ascertaining compliance with covenants under loan agreements;
reviewing disclosure requirements for commitments and contingencies;
reviewing adjustments raised by the external auditor(s), whether or not included in the financial statements;
reviewing unresolved differences between management and the external auditor(s); and
obtain explanations of significant variances with comparative reporting periods.

4.	The Committee is to review the financial statements, prospectuses, MD&A, annual information forms and all public disclosure containing audited or unaudited financial information (including, without limitation, annual and interim press releases and any other press releases disclosing earnings or financial results) before release and prior to Board approval. The Committee must be satisfied that adequate procedures are in place for the review of Harvest's disclosure of all other financial information and shall periodically access the accuracy of those procedures.

5.	With respect to the appointment of external auditor(s) by the Board, the Committee shall:

recommend to the Board the external auditor(s) to be nominated;
recommend to the Board the terms of engagement of the external auditor(s), including the compensation of the auditor(s) and a confirmation that the external auditor(s) shall report directly to the Committee;
on an annual basis, review and discuss with the external auditor(s) all significant relationships such auditor(s) have with the Harvest to determine the auditor(s)' independence;
when there is to be a change in auditor(s), review the issues related to the change and the information to be included in the required notice to securities regulators of such change; and
review and pre-approve any non-audit services to be provided to Harvest by the external auditor(s) and consider the impact on the independence of such auditor(s). The Committee may delegate to one or more independent members the authority to pre–approve non–audit services, provided that the member report to the Committee at the next scheduled meeting such pre–approval and the member comply with such other procedures as may be established by the Committee from time to time.

6.	Review with external auditor(s) (and internal auditor if one is appointed by Harvest) their assessment of the internal controls of Harvest, their written reports containing recommendations for improvement, and management’s response and follow-up to any identified weaknesses. The Committee shall also review annually with the external auditor(s) their plan for their audit and, upon completion of the audit, their reports upon the financial statements of Harvest and its subsidiaries.

7.	The Committee shall review risk management policies and procedures of Harvest (i.e. hedging, litigation and insurance).

8.	The Committee shall establish a procedure for:

the receipt, retention and treatment of complaints received by Harvest regarding accounting, internal accounting controls or auditing matters; and
the confidential, anonymous submission by employees of Harvest of concerns regarding questionable accounting or auditing matters.

9.	The Committee shall review and approve Harvest's hiring policies regarding partners and employees and former partners and employees of the present and former external auditor(s) of Harvest.

10.	The Committee shall have the authority to investigate any financial activity of Harvest. All employees of Harvest are to cooperate as requested by the Committee.

11.	The Committee may retain persons having special expertise and/or obtain independent professional advice to assist in filling their responsibilities at the expense of Harvest without any further approval of the Board.

12.	The Committee shall review the Committee mandate and subsequent revisions periodically, and recommend to the Board for approval.

MEETINGS AND ADMINISTRATIVE MATTERS

1.	At all meetings of the Committee every question shall be decided by a majority of the votes cast. In case of an equality of votes, the Chairman of the meeting shall not be entitled to a second or casting vote.

2.	The Chair shall preside at all meetings of the Committee, unless the Chair is not present, in which case the members of the Committee present shall designate from among the members present the Chair for purposes of the meeting.

3.	A quorum for meetings of the Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee shall be the same as those governing the Board unless otherwise determined by the Committee or the Board.

4.	Meetings of the Committee should be scheduled to take place at least four times per year and at such other times as the Chair of the Committee may determine necessary. Minutes of all meetings of the Committee shall be taken. The Chief Financial Officer shall attend meetings of the Committee, unless otherwise excused from all or part of any such meeting by the Chairman.

5.	The Committee shall meet with the external auditor(s) at least once per year (in connection with the preparation of the year end financial statements) and at such other times as the external auditor(s) and the Committee consider appropriate.

6.	Agendas, approved by the Chair, shall be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.

7.	The Committee may invite such officers, directors and employees of the Corporation as it may see fit from time to time to attend at meetings of the Committee and assist thereat in the discussion and consideration of the matters being considered by the Committee.

8.	At the discretion of the Committee, the members of the Committee shall meet in private session (in camera) with the external auditor(s), management and with Committee members as required.

9.	Following each meeting, the Committee will report to the Board. Upon request, copies of the materials of such Committee meeting should be provided at the next Board meeting after a meeting is held (these may still be in draft form).

10.	Minutes of the Committee will be recorded and maintained and circulated to directors who are not members of the Committee or otherwise made available at a subsequent meeting of the Board upon request.

11.	The Committee may retain persons having special expertise and/or obtain independent professional advice to assist in fulfilling its responsibilities at the expense of Harvest.

12.	Any members of the Committee may be removed or replaced at any time by the Board and shall cease to be a member of the Committee as soon as such member ceases to be a director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy shall exist on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, each member of the Committee shall hold such office until the Committee is reconstituted by the Board.

13.	Any issues arising from these meetings that bear on the relationship between the Board and management should be communicated to the Chairman of the Board by the Committee Chair.

COMPENSATION COMMITTEE

The Compensation and Corporate Governance Committee is comprised of Dr. Seong-Hoon Kim, Myunghuhn Yi, Chang-Koo Kang and William A. Friley Jr., who is an independent director. The Compensation and Corporate Governance Committee (“Compensation Committee”) is responsible to the Harvest Board for reviewing matters relating to the human resource policies, employee retention and short and long-term compensation of the directors, officers and employees of Harvest and its subsidiaries in the context of the budget and business plan of the Corporation. The Compensation Committee, when making such salary, bonus and other incentive determinations, takes into consideration individual salaries, bonuses and benefits paid to executives of other similarly sized Canadian conventional oil and natural gas companies with a view to ensuring that such overall compensation packages are competitive. Such information is obtained from the annual Canadian oil and gas industry salaries and benefits survey prepared by Mercer Human Resource Consulting ("Mercer"), a firm of independent consultants that regularly reviews compensation practices in Canada. In addition, the Compensation Committee reviews the completion of operational metrics, strategic objectives and the financial performance of Harvest compared to a peer group, currently comprised of similarly sized oil and gas companies, to determine what performance level has been achieved.

D. Employees

The number of full-time and part-time employees as at December 31 for each of the past three financial years was as follows:

	Upstream		Downstream	Total
	*Corporate*	*Field*
2010	286	128	481	895
2009	251	136	531	918
2008	281	140	546	967

In the Downstream operations approximately 66% of the full-time employees and 95% of the part-time employees are unionized and represented by the United Steel Workers of America in four collective bargaining agreements. North Atlantic has had a history of good relations with its union, which is evidenced by the lack of any work stoppage at the Refinery. Three of the collective agreements have expired: one expired on December 31, 2010, and the other two collective agreements expired on March 31, 2011. The fourth collective agreement expires March 31, 2013. The agreement that expired on December 31, 2010 is currently under negotiation and is the largest of the three expired ones; it covers 277 full time and 85 part time operation and maintenance workers. The average number of temporary employees in 2010 was 46.

E. Share Ownership

None of the individuals listed in Item 6.B own shares of Harvest as 100% of the issued and outstanding shares of the Corporation are owned by KNOC.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. Major Shareholders

KNOC owns 100% of the 335,535,047 issued and outstanding common shares of Harvest at December 31, 2010 (see Item 4.A of this annual report for more information on KNOC); this information remains unchanged as at the date of this annual report. The Trust Units of the predecessor company, Harvest Energy Trust, were widely held up until the date of the KNOC Acquisition on December 22, 2009. See Item 4.A for further discussion on the KNOC Acquisition.

B. Related Party Transactions

There were no material or unusual related party transactions since January 1, 2010 to the date of this annual report except as disclosed in “Recent Developments” under Item 4.A of this annual report in connection with the KNOC Acquisition, the internal reorganization and the acquisition of the BlackGold assets. There are no loans between Harvest and any of its related parties.

C. Interests of Experts

Not applicable.

ITEM 8. FINANCIAL INFORMATION

A. Consolidated Statements and Other Financial Information

See Item 17 of this annual report.

The Corporation does not currently distribute dividends.

The following table provides the total amount of export sales in each of the last three years:

		Year Ended December 31
		2010		2009		2008
Total export sales ($000’s) ⁽¹⁾	$	2,328,653	$	1,869,686	$	3,414,663
Export sales as a percentage of total sales		61%		60%		62%

⁽¹⁾Export sales are primarily to the U.S. market with only an immaterial amount exported to Europe.

B. Significant Changes

On December 14, 2010 Harvest signed a purchase and sale agreement to purchase the assets of Hunt Oil Company of Canada, Inc. and Hunt Oil Alberta, Inc. (collectively “Hunt”). The transaction closed on February 28, 2011. Refer to “Recent Developments” under Item 4.A of this annual report for more information on this acquisition.

On April 14, 2011, Vitol provided a six-month notice to terminate the SOA effective November 1, 2011. Harvest is evaluating various options to procure crude feedstock subsequent to the termination date.

On April 29, 2011, Harvest extended the term of its credit facility by 2 years to April 30, 2015. The minimum rate charged on the credit facility was also amended from 200 bps to 175 bps over bankers’ acceptance rates as long as Harvest’s secured debt to EBITDA ratio remains below or equal to one. The borrowing capacity of the credit facility remains at $500 million and the financial covenants remain unchanged.

ITEM 9. THE OFFER AND LISTING

Not applicable.

ITEM 10. ADDITIONAL INFORMATION

A. Share Capital

Not applicable.

B. Memorandum and Articles of Association

Given that the information required under this Item 10.B is primarily the listed matters as they are dealt with by or contained in a corporation’s articles and bylaws, the following discussion is not, except to the extent applicable and specifically required under this Item (or as necessary for clarity) intended to compare the provisions of Harvest’s bylaws and articles to the provisions of the ABCA. In some areas the Harvest bylaws and articles reflect or repeat the ABCA provisions, and in others, where and to the extent permitted by the ABCA, statutory provisions are added to or varied. Some description of the provisions of the ABCA may be made in the following explanations for context or for completeness to describe the relevant matters where the Articles or Bylaws do not have corresponding provisions. However, in any case where provisions of the ABCA are described, reference should be made to the actual statute for a complete understanding of the applicable law. In addition, in certain cases, the establishment of rights or restrictions under the Harvest articles and bylaws is subject to or restricted by the provisions of the ABCA, and the following does describe those aspects of the ABCA to the extent required for clear disclosure to meet the requirements of this Item 10.B. The Harvest articles and bylaws have been developed to be in compliance with the ABCA requirements.

REGISTRATION AND POWERS

The Corporation is registered under Corporate Access Number 2015335496 and is the result of an amalgamation filed May 1, 2010 under the ABCA. The amalgamating corporations were KNOC Canada Ltd., Harvest Operations Corp. and 12065892 Alberta ULC. Companies incorporated or amalgamated under the ABCA have the capacity and, subject to the ABCA, the rights, powers and privileges of a natural person. Under the ABCA no bylaws are required to confer any particular power on a corporation or its directors, but if there are restrictions in its articles on the business carried on or exercised, the corporation shall not carry on or exercise such business. Harvest has no such restrictions in its articles of amalgamation (“Articles.”).There are no stated objects or purposes as would be applicable in a memorandum of association jurisdiction. References to “Bylaws” in the following shall mean the bylaws of Harvest, Bylaw No.1 and Bylaw No. 2.

DIRECTORS

Material contracts: A director who is party to a material contract or proposed material contract (or material transaction) has to disclose the nature and extent of the director’s interest therein in accordance with the ABCA. Such director is unable to vote on any resolution to approve such contract except as permitted by the ABCA, but is not excluded in determining the quorum. Certain exceptions to the inability to vote are provided for under the ABCA, and in particular an exception is made for contracts relating primarily to the director’s remuneration as a director, officer, employee or agent of the Company or an affiliate. Accordingly, the directors do have power in the absence of an independent forum to vote directors’ compensation. . The compensation of the directors is decided by the directors unless the board of directors requests approval of compensation from the shareholders, which would be required to be by ordinary resolution (passed by a majority of the votes cast by the shareholders who voted on the resolution, or signed by all the shareholders entitled to vote on that resolution.)

Borrowing powers: There are no limitations created either by the Bylaws or Articles on borrowing powers of Harvest exercisable by the directors.

Retirement or non- retirement: There are no provisions for retirement or non-retirement of directors under an age limit.

Qualifying number of shares: There are no requirements for director share ownership provided under the Articles and Bylaws.

CLASSES OF SHARES AND SHARE RIGHTS

The Articles provide for two classes of shares (common shares and preferred shares), and for the issuance of an unlimited number of common share and the issuance in series of preferred shares, in unlimited number

Common shares

Under the Articles the common shares have the right to vote at all meetings of shareholders, except meetings which have voting restricted to holders of a specified class of shares, and under the ABCA (a provision not varied by the Articles) each share entitles the holder to one vote at a meeting of shareholders. There is no provision under the Bylaws or Articles for directors to stand for reelection at staggered intervals or for cumulative voting. The common shares have the right to receive the remaining property and assets of the Corporation on dissolution, subject to the prior rights and privileges applicable to any other class of shares. With respect to the common shares under the Articles or Bylaws, there are no redemption provisions, sinking fund provisions, provisions imposing liability for further capital calls, or any provision discriminating against any existing or prospective holder of the common shares as a result of such shareholder owning a substantial number of shares.

Preferred shares

The preferred shares may be issued from time to time in one or more series with the number o shares in any such series determined by resolution of the directors prior to such issue. Under the Articles, each issued series of preferred shares shall have the rights, privileges, restrictions and conditions attaching to such series as are approved by resolution of the directors before the issue of such series.

Dividends

The common shares have the right to receive any dividend declared by Harvest subject to prior rights and privileges applicable to any other class of shares. The preferred shares’ rights to dividends may be established, as with any other rights, by resolution of directors as described above. Under the ABCA (and expressly included in the Bylaws) there is a solvency test and a liquidity test restricting the declaration and payment of dividends. There is no provision in the Articles or Bylaws for a lapse in dividend entitlement, based on time limits or otherwise.

Rights to change share rights

The necessary action to change the rights of holders of an Alberta corporation’s stock is set out under the ABCA. Under the ABCA in order to add, change or remove any rights, privileges, restrictions and conditions applicable to all or any of Harvest’s shares, the articles may be amended by special resolution. A special resolution is a resolution passed by a majority of not less than 2/3 of the votes cast by the shareholders who voted in respect of that resolution, or signed by all the shareholders entitled to vote on that resolution. The ability to amend or remove any of the foregoing includes rights to accrued dividends and can apply to shares whether issued or unissued. The Bylaws or Articles do not vary this provision of the ABCA and accordingly conditions for change of rights of Harvest shareholders are not more significant than required by law. Classes or series of shares are entitled to be dealt with in this regard by a vote separately by class or series, subject to the provisions of the ABCA. Articles of amendment must be filed after amendments are adopted by resolution

MEETINGS

Annual meetings are provided under the Articles to be held in accordance with the requirements of the ABCA, and held at the registered office of the Corporation or elsewhere as determined by the directors. Special meetings may be called at any time and held on the dates and at the locations determined by the directors. Written notice to the shareholders is required (at least 21 days and not more than 50 days in advance of the meeting), including, if applicable details of special business to be transacted and the text of any special resolution to be tabled at the meeting. The notice is to be sent to each shareholder entitled to vote at the meeting, and the shareholders entitled to vote are those who on the record date are registered on the records of the Corporation (or if applicable, the transfer agent) . Under the ABCA a written resolution signed by all shareholders entitled to vote on it is as valid as though passed at a meeting and such a resolution satisfies statutory meeting requirements. Accordingly in the case of a sole shareholder corporation, such as Harvest it can be practical to address annual meeting requirements and to deal with the business to be transacted at the annual meeting by written resolutions.

SHARE (SECURITIES) OWNERSHIP

The number of direct or indirect beneficial owners of securities of the Corporation under the Articles is limited to not more than fifty (securities in this context does not include non-convertible debt securities) and any invitation to the public to subscribe for securities is prohibited. With respect to the rights to acquire securities, the Articles provide that directors’ approval is required to transfer securities to a person who is not already a security holder. There are no limitations under the Articles and Bylaws on the rights of non-resident shareholders to hold securities or to exercise voting rights on securities which are held nor are there any such limitations pursuant to provisions of the ABCA.

OTHER PROVISIONS

There are no provisions of the Articles or Bylaws that would have the effect of delaying, deferring or preventing a change in control of Harvest and that would operate only with respect to a merger, acquisition or corporate restructuring involving Harvest or any subsidiaries. There are no provisions in the Bylaws governing the ownership threshold above which shareholder ownership must be disclosed. There are no provisions in the Articles or Bylaws governing changes in capital, and accordingly no conditions on changes in capital of Harvest under the Articles or Bylaws.

C. Material Contracts

6⁷/₈% SENIOR NOTES AND THE NOTE INDENTURE

The following is a summary of the material attributes and characteristics of the Note Indenture (and references below to “Notes” refer to the 6⁷/₈% Senior Notes).

PAYMENT UPON REDEMPTION

Prior to maturity, the Notes are redeemable at a redemption price equal to 100% of the principal amount of the Notes being redeemed, plus a make-whole redemption premium and accrued and unpaid interest to the redemption date. Harvest may also redeem the Notes at any time in the event that certain changes affecting Canadian withholding taxes occur.

COVENANTS

There are also covenants restricting, among other things, certain transactions for the sale of assets, and the incurrence of additional indebtedness if such issuance would result in an interest coverage ratio, as defined in the Note Indenture, of less than 2.0 to 1. Notwithstanding the interest coverage ratio limitation, the incurrence of additional secured indebtedness may not exceed the greater of $1.0 billion and 15% of total assets as outlined in the limitation on liens covenant. In addition, the covenants under the Note Indenture limit the amount of restricted payments, including dividends to Harvest’s shareholders, should the defined leverage ratio be greater than 2.50 to 1.

REGISTRATION RIGHTS

The Notes have not been registered under the U.S. Securities Act of 1933 or the securities laws of any other jurisdiction. Harvest has entered into a Registration Rights Agreement. The Registration Rights Agreement will provide that unless the Exchange Offer would not be permitted by applicable law or SEC policy, Harvest Operations and the subsidiary guarantors will:

(1)	file an Exchange Offer Registration Statement with the SEC on or prior to 45 days after the filing deadline (the “Filing Date”), as specified in the SEC’s rules and regulations, for Harvest’s Form 20-F for the fiscal year ended December 31, 2011;

(2)	use their commercially reasonable efforts to have the Exchange Offer Registration Statement declared effective by the SEC on or prior to 105 days after the Filing Date; and

(3)	following effectiveness of the Exchange Offer Registration Statement,

	(a)	commence the Exchange Offer; and

	(b)	issue Exchange Notes in exchange for all Notes tendered prior thereto in the Exchange Offer.

CREDIT FACILITY

The Credit Facility is a secured covenant-based $500 million credit facility with a syndicate of financial institutions and includes an accordion feature that permits the Corporation to increase the size of the facility from $500 million to $1.0 billion without lender consent if the Corporation is able to secure additional capacity from an existing or new lender(s). On April 29, 2011, the term of the Credit Facility has been extended by two years to April 30, 2015.

Harvest continues to pay a floating interest rate plus a risk premium that changes based on the ratio of the Corporation’s drawn amount of debt to earnings before interest, taxes, depletion, amortization and other non-cash items (“EBITDA”) as more fully defined below. The minimum rate charged on the Credit Facility is 175 bps over bankers’ acceptance rates as long as Harvest’s drawn amount of debt to EBITDA ratio remains below or equal to one. In addition, the Credit Facility requires standby fees on undrawn amounts. As at December 31, 2010, $14 million was drawn on this facility.

In addition to the standard representations, warrants and covenants commonly contained in a credit facility, the Credit Facility agreement contains the following covenants:

(a)

An aggregate limitation of $25 million on financial assistance and/or capital contributions to parties other than those included in the first floating security interest;

	(b)	A limitation to carrying on business in countries that are not members of the Organization for Economic Cooperation and Development;

	(c)	A limitation on the payment of distributions to shareholders, including dividends should the Total Debt to EBITDA ratio exceed 2.5 to 1.0; and

	(d)	Subject to the following quarterly financial covenants:

	(1)	Senior Debt to EBITDA of 3.0 to 1.0 or less;

	(2)	Total Debt to EBITDA of 3.5 to 1.0 or less;

	(3)	Senior Debt to Capitalization of 50% or less; and

	(4)	Total Debt to Capitalization of 55% or less.

(and in the above, “Senior Debt” includes letters of credit, bank debt and guarantees and “Total Debt” consists of Senior Debt, the Notes and the Debentures)

For purposes of determining the financial covenants, the following terms are defined in the Credit Facility agreement:

(d)

EBITDA is the aggregate of the past four quarters Net Earnings plus:


		(1)	interest and financing charges;

		(2)	future income tax expense;

		(3)	depletion, depreciation, amortization and other;

		(4)	unrealized gains/losses on risk management contracts;

		(5)	unrealized currency exchange gains/losses; and

		(6)	non-cash unit based compensation expense.

(e)

Capitalization is the aggregate of the amounts drawn under the Credit Facility, the 6⁷/₈% Senior Notes, the Debentures and shareholders’ equity (less equity relating to BlackGold), all as reported in Harvest’s consolidated balance sheet in accordance with Canadian GAAP.

With respect to these financial covenants, Harvest’s December 31, 2010 financial ratios were as follows:

Senior Debt to EBITDA of 0.06 to 1.0;
Total Debt to EBITDA of 2.39 to 1.0;
Senior Debt to Capitalization of 1%; and
Total Debt to Capitalization of 31%.

DEBENTURES AND DEBENTURE INDENTURE

The following is a summary of the material attributes and characteristics of the Debentures. This summary does not include a description of all of the terms of each series of Debentures, and reference should be made to the relevant trust indenture for the series of Debenture filed at www.sedar.com for a complete description of such terms.

GENERAL

Each series of Debentures specify a maturity date, an interest rate, the terms of the conversion privilege and the redemption terms, if any. The principal amount and interest of the Debentures is payable in lawful money of Canada.

The Debentures are direct obligations of the Corporation and are not secured by any mortgage, pledge, hypothec or other charge and will be subordinated to other liabilities of the Corporation as described under "Subordination". The Debenture Indenture will not restrict the Corporation from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its properties to secure any indebtedness.

CONVERSION PRIVILEGE

In accordance with the provisions of the Debenture Indenture, the completion of the KNOC Arrangement resulted in an automatic adjustment to the conversion privilege under each outstanding series of Debentures. The Debentures are no longer convertible into Trust Units. They are convertible into the same cash consideration (based on the acquisition price under the KNOC Arrangement of $10.00 per unit) that a holder of Debentures would have received under the KNOC Arrangement had the holder converted their Debentures into former Trust Units immediately prior to the effective time of the KNOC Arrangement. Accordingly, in the event of a valid exercise of the conversion right by a holder of Debentures, the holder will now receive, in lieu of the number of Trust Units that would have been issuable prior to the effective time of the KNOC Arrangement, a cash payment in an amount equal to $10.00 for each such Trust Unit that would otherwise have been issued at such time. Based on the conversion price of each outstanding series of Debentures, a holder who converts any Debentures now will receive, in exchange for their converted Debentures, a cash payment that is less than the principal amount converted and it is assumed that no investor would exercise their conversion option.

REDEMPTION AND PURCHASE

The Debentures may be redeemed at the Corporation’s option in whole or in part prior to their respective maturity dates. The redemption price for each series of Debentures for the first redemption period is equal to $1,050 per $1,000 principal amount of Debentures and for the second redemption period is equal to $1,025 per $1,000 principal amount of Debentures period. After the second redemption period, all of the Debentures may be redeemed at par. In the case of redemption of less than all of a series of Debentures, the Debentures to be redeemed will be selected by the Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee deems equitable, subject to the consent of the TSX. The Corporation has the right to purchase the Debentures in the market, by tender or by private contract.

PAYMENT UPON REDEMPTION OR MATURITY

On redemption or at maturity, Harvest will repay the indebtedness represented by the Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, together with accrued and unpaid interest thereon. Any accrued and unpaid interest thereon will be paid in cash.

SUBORDINATION

The payment of principal and interest on the Debentures is subordinated in right of payment to the prior payment in full of all of Harvest’s senior indebtedness, including the 6⁷/₈% Senior Notes discussed above, and effectively subordinated to claims of creditors of the Corporation’s subsidiaries.

DEBENTURES MAY BE ISSUED IN SERIES AND RANK PARI PASSU

The Debentures may be issued in one or more series with each series established by a supplement to the Debenture Indenture specifying, among other things, any limit to the aggregate principal amount of the Debentures of the series to be issued, the date or dates on which the principal of the Debentures of the series is payable, the rate or rates at which the Debentures of the series shall bear interest, the right, if any, of Harvest to redeem Debentures of the series and the period or periods and price therefore.

All issued and outstanding Debentures of the Corporation are direct unsecured obligations of the Corporation with each series of Debentures ranking pari passu with all other series of Debentures of the Corporation and each Debenture of a series ranking pari passu with each Debenture of the same series of Debentures.

COVENANTS

The Debenture Indenture contains customary covenants and provisions, including covenants with respect to limitations on certain transactions, payment of principal, premium and interest, covenants and provisions governing mergers, consolidation and asset sales, change of control and a covenant limiting distributions to the equity holder if Harvest’s board of directors has actual knowledge that the paying of the distribution on the payment date will result in an event of default. In addition, the Debenture Indenture provides that the Corporation may not issue additional Debentures of equal ranking if the principal amount of all issued and outstanding Debentures exceeds 25% of Harvest’s total market capitalization (as defined in the Debenture Indenture) after the issuance of such additional Debentures.

OFFERS FOR DEBENTURES

The Debenture Indenture contains provisions to the effect that if an offer is made for the Debentures which is a take-over bid for Debentures within the meaning of the Securities Act (Alberta) and not less than 90% of the Debentures (other than Debentures held at the date of the take-over bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Debentures held by the holders of Debentures who did not accept the offer on the terms offered by the offeror.

SUPPLY AND OFFTAKE AGREEMENT

Concurrent with the acquisition of North Atlantic by Harvest in 2006, North Atlantic entered into a Supply and Offtake Agreement (the “SOA”) with Vitol Refining S.A. ("Vitol"), and this agreement was amended and extended October 12, 2009; effective November 1, 2009. The SOA provides that the ownership of substantially all crude oil and other feedstocks and refined product inventories at the Refinery be retained by Vitol and that Vitol be granted the exclusive right and obligation to provide crude oil feedstock and other feedstocks for delivery to the Refinery as well as the exclusive right and obligation to purchase virtually all refined products produced by the Refinery for export. The SOA also provides that Vitol will receive a time value of money amount (the "TVM") reflecting the cost of financing the working capital associated with the purchase of crude oil and other feedstocks and sale of refined products, as the SOA requires that Vitol retain ownership of the crude oil and other feedstocks until delivered through the inlet flange to the Refinery as well as immediately take title to the refined products as they are delivered by the Refinery through the inlet flange to designated storage tanks. Further, the SOA provides North Atlantic with the opportunity to share the incremental profits and losses resulting from the sale of products beyond the U.S. east coast markets.

Pursuant to the SOA, Harvest, in consultation with Vitol, request a certain slate of crude oil and other feedstocks and Vitol is obligated to provide the feedstocks in accordance with the request. The SOA includes a feedstock transfer pricing formula that aggregates the pricing for the feedstocks purchased as correlated to published future contract settlement prices, the cost of transportation from the source of supply to the Refinery and the settlement cost or proceeds for related operational price risk management contracts plus a marketing fee. The purpose of these operational price risk management contracts is to convert the fixed price of crude oil and other feedstock purchases to floating prices for the period from the purchase date through to the date the refined products are sold to North Atlantic to allow "matching" of feedstock purchases to refined product sales, thereby mitigating the gross margin risk between the time feedstocks are purchased and the time refined products are sold.

The SOA requires that Vitol purchase and lift all refined products produced by the Refinery, except for certain excluded refined products to be marketed by North Atlantic in the local Newfoundland market, and provides a product purchase pricing formula that aggregates a price based on the current Boston and New York City markets less the costs of transportation, insurance, port fees, inspection charges and similar costs incurred by Vitol, plus the TVM component.

The SOA is effective until November 1, 2011 and may be terminated by either party at any time thereafter by providing notice of termination no later than six months prior to the desired termination date or if the refinery is sold in an arm’s length transaction, upon 30 days notice prior to the desired termination date. Further, the SOA may be terminated upon the continuation for more than 180 days of a delay in performance due to force majeure but prior to the recommencing of performance. Upon termination of the entire agreement or the right and obligation to provide feedstocks, North Atlantic will be required to purchase the related feedstocks and refined product inventories, respectively, at the prevailing market prices.

Vitol is an indirect wholly-owned subsidiary of the Vitol Group, a privately owned worldwide marketer of crude oil providing oil trading and marketing services to producers through to Downstream retailers of petroleum products. The Vitol Group is one of the largest independent gasoline traders in the world. With headquarters in Rotterdam, the Netherlands and Geneva Switzerland, with trading entities in Houston, London, Bahrain and Singapore the Vitol Group has 24 hour coverage of all the world's oil markets. In the crude oil sector, the Vitol Group has developed a worldwide reputation as a reliable business partner.

D. Exchange Controls

There are no regulations or legislation that affects the import or export of capital or the remittance of dividends, interest or other payments to nonresident security holders.

E. Taxation

Not applicable.

F. Dividends and Paying Agents

Not applicable.

G. Statements by Experts

Not applicable.

H. Documents on Display

Documents concerning the Corporation which are referred to in this annual report may be inspected at Harvest’s head office, Suite 2100, 330 - 5th Avenue S.W., Calgary, Alberta T2P 0L4. Copies of our financial statements and other continuous disclosure documents are also available for viewing on SEDAR at www.sedar.com.

I. Subsidiary Information

Refer to Item 4.C of this annual report.

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Quantitative information about market risk as at December 31, 2010 can be found in Note 16(c)(iii) of the Corporation’s December 31, 2010 consolidated financial statements included under Item 17; similar information as of December 31, 2009 can be found in Note 20(c)(iii) of Harvest Energy Trust’s December 31, 2009 consolidated financial statements included under Item 17 of this annual report. All market risk sensitive instruments are entered into for purposes other than trading.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

Not applicable.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

Not applicable.

ITEM 15. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

As part of the corporate reorganization and dissolution of the Trust on May 1, 2010, the newly reorganized company, Harvest, will continue to assume the disclosure controls and procedures. Under the supervision of the Chief Executive Officer and Chief Financial Officer, the Corporation has evaluated the effectiveness of its disclosure controls and procedures as of December 31, 2010 as defined under the rules adopted by the U.S. Securities and Exchange Commission. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2010, the disclosure controls and procedures were effective to ensure that information required to be disclosed by Harvest in reports it files or submits to U.S. securities authorities was recorded, processed, summarized and reported within the time period specified in U.S. securities laws and was accumulated and communicated to management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining internal control over our financial reporting. Our internal control is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes. Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2010. The evaluation was based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on that evaluation, management has concluded that as of December 31, 2010, the design and operation of internal control over financial reporting was effective.

Based on their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control systems are met.

CHANGES IN CONTROL OVER FINANCIAL REPORTING

During the year ended December 31, 2010, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

Harvest’s board of directors has determined that there is at least one independent audit committee financial expert serving on the audit committee, Mr. William D. Robertson. Refer to Item 6.A for additional information on Mr. Robertson’s relevant education and experience.

ITEM 16B. CODE OF ETHICS

Harvest has adopted a Code of Ethics that applies to its principal executive, financial and accounting officers, and other members of senior management. Specifically, this code applies to the Registrant’s President and Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Upstream, and Chief Operating Officer, Downstream. It, and any amendments to the code, is available in print without charge to any person who requests it. Such requests may be made by contacting the Harvest’s Investor Relations and Communications Advisor via email at: information@harvestenergy.ca or by phone at (403) 265-1178. There were no waivers or amendments to the Code of Ethics in 2010.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The aggregate fees billed by Harvest’s external auditor in the last two fiscal years for audit services are as follows:

	2010	2009
Audit Fees⁽¹⁾	690,000	945,000
Audit-Related Fees⁽²⁾	270,000	33,000
Tax Fees	-	-
All Other Fees⁽³⁾	-	-
Total	960,000	978,000

(1)	Represents the aggregate fees of the Corporation’s auditors for audit services in respect of the financial year and interim periods.

(2)	Represents the aggregate fees billed for assurance and related service by the Corporation’s auditors that are reasonable related to the performance of audit or review of the Corporation’s financial statements and are not included under “Audit Fees” and are primarily composed of services related to the Corporation’s debt offerings and adoption of IFRS

(3)	Represents the aggregate fees billed for products and services provided by the Corporation’s auditors other than those services reported under “Audit Fees”, “Audit Related Fees” and “Tax Fees”

The Audit Committee must first approve all non-audit or special services performed by any independent accountants. All remuneration provided to the Corporation's auditor and any independent accountants are also approved by the Audit Committee. The Corporation’s auditor meets with the Audit Committee, without management present, at least annually and more often at the request of either the Audit Committee or the auditor. The audit committee approved all services included in the table above.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

ITEM 16E. PURCHASE OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

Not applicable.

ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

Not applicable.

ITEM 17. FINANCIAL STATEMENTS

See F-pages following Item 19.

ITEM 18. FINANCIAL STATEMENTS

We have elected to provide financial statements pursuant to Item 17.

ITEM 19. EXHIBITS

1	Harvest's Articles of Amalgamation and Bylaws
2	6⁷/₈% Senior Notes Indenture, dated October 4, 2010 incorporated by reference to Form 6-K filed on June 20, 2011.
4.1	Supply and Offtake Agreement between North Atlantic and Vitol Refining S.A. dated October 1, 2006 and First Amendment to Supply and Offtake Agreement between North Atlantic and Vitol Refining S.A. dated October 12, 2009, incorporated by reference to Form 6-K filed on April 1, 2010.
4.2	Amended and Restated Credit Facility dated April 30, 2010 incorporated by reference to Form 6-K filed on May 17, 2010.
4.3	First Amending Agreement (Credit Facility) dated December 17, 2010 incorporated by reference to Form 6-K filed on June 20, 2011.
4.4	Second Amending Agreement (Credit Facility) dated April 29, 2011 incorporated by reference to Form 6-K filed on June 20, 2011.
4.5	6⁷/₈% Senior Notes Indenture, dated October 4, 2010 incorporated by reference to Item 19.2 of this annual report.
4.6	Harvest's Articles of Amalgamation and Bylaws incorporated by reference to Item 19.1 of this annual report.
8	Refer to Item 4.C of this annual report.
12.1	Chief Executive Officer Certification required by Rule 13a-14(a) and 15d-14(a)
12.2	Chief Financial Officer Certification required by Rule 13a-14(a) and 15d-14(a)
13.1	Chief Executive Officer Certification required by Rule 13a-14(b) and 15d-14(b)
13.2	Chief Financial Officer Certification required by Rule 13a-14(b) and 15d-14(b)
15.1	McDaniels’ covering letter and Reserve Evaluation Methodology Report
15.2	GLJ’s covering letter Reserve Evaluation Procedure Report

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

Harvest Operations Corp.

/s/ Kyungluck Sohn
Kyungluck Sohn
Chief Financial Officer

Dated: June 29, 2011

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
HARVEST OPERATIONS CORP. - AUDITED CONSOLIDATED FINANCIAL STATEMENTS
Fiscal Years 2010 and 2009
Management’s Report	F - 2
Report of Independent Registered Public Accounting Firm	F - 3
Consolidated Balance Sheets as at December 31, 2010 and 2009	F - 5
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2010 and 2009	F - 6
Consolidated Statements of Unitholders’ Equity as at December 31, 2010 and 2009	F - 7
Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009	F - 8
Notes to Consolidated Financial Statements	F - 9
Supplemental U.S. GAAP Reconciliation Note for Fiscal Year 2010 and 2009	F - 31

HARVEST ENERGY TRUST - AUDITED CONSOLIDATED FINANCIAL STATEMENTS
Fiscal Years 2009 and 2008
Management’s Report	F - 33
Report of Independent Registered Public Accounting Firm	F - 34
Consolidated Balance Sheets as at December 31, 2009 and 2008	F - 35
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2009 and 2008	F - 36
Consolidated Statements of Unitholders’ Equity as at December 31, 2009 and 2008	F - 37
Consolidated Statements of Cash Flows for the years ended December 31, 2009 and 2008	F - 38
Notes to Consolidated Financial Statements	F - 39
Auditors Report on US GAAP Reconciliation Note	F - 63
Supplemental U.S. GAAP Reconciliation Note for Fiscal Year 2009 and 2008	F - 64

F - 1

MANAGEMENT’S REPORT

In management’s opinion, the accompanying consolidated financial statements of Harvest Operations Corp. (the “Company”) have been prepared within reasonable limits of materiality and in accordance with Canadian generally accepted accounting principles. Since a precise determination of many assets and liabilities is dependent on future events, the preparation of financial statements necessarily involves the use of estimates and approximations. These have been made using careful judgment and with all information available up to June 28, 2011. Management is responsible for the consistency, therewith, of all other financial and operating data presented in Management’s Discussion and Analysis for the year ended December 31, 2010.

To meet its responsibility for reliable and accurate financial statements, management has established and monitors systems of internal control which are designed to provide reasonable assurance that financial information is relevant, reliable and accurate, and that assets are safeguarded and transactions are executed in accordance with management’s authorization.

Under the supervision of our Chief Executive Officer and our Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We have concluded that as of December 31, 2010 our internal controls over financial reporting were effective.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

The consolidated financial statements have been examined by our auditors, KPMG LLP. Their responsibility is to express a professional opinion on the fair presentation of the consolidated financial statements prepared in accordance with Canadian generally accepted accounting principles. The Auditors’ Report outlines the scope of their examination and sets forth their opinion on our financial statements.

The Board of Directors is responsible for approving the consolidated financial statements. The Board fulfills its responsibilities related to financial reporting mainly through the Audit Committee. The Audit Committee consists exclusively of independent directors and includes at least one director with financial expertise. The Audit Committee meets regularly with management and the external auditors to discuss reporting and governance issues and ensures each party is discharging its responsibilities. The Audit Committee has reviewed these financial statements with management and the Independent Registered Public Accountants and has recommended their approval to the Board of Directors. The Board of Directors has approved the consolidated financial statements of the Company.


John E. Zahary	Kyungluck Sohn
President and Chief Executive Officer	Chief Financial Officer


Calgary, Alberta
June 28, 2011

F - 2


	KPMG LLP
	Chartered Accountants	Telephone (403) 691-8000
	2700 205 - 5^thAvenue SW	Telefax (403) 691-8008
	Calgary AB T2P 4B9	Internet www.kpmg.ca

INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors of Harvest Operations Corp.

We have audited the accompanying consolidated financial statements of Harvest Operations Corp., which comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of income (loss) and comprehensive income (loss), shareholder’s equity and cash flows for the year ended December 31, 2010 and for the period from incorporation on October 9, 2009 to December 31, 2009, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Harvest Operations Corp. as at December 31, 2010 and 2009 and its consolidated results of operations and its consolidated cash flows for the year ended December 31, 2010 and for the period from incorporation on October 9, 2009 to December 31, 2009 in accordance with Canadian generally accepted accounting principles.

F - 3

Other Matter

Our audits were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The supplementary information included in Form 20-F entitled "Reconciliation of the Consolidated Financial Statements to U.S. GAAP" is presented for purposes of additional analysis and requirements under securities legislation. Such supplementary information has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic consolidated financial statements taken as a whole.

Chartered Accountants
Calgary, Canada
June 28, 2011

F - 4

CONSOLIDATED BALANCE SHEETS

*(thousands of Canadian dollars)*		December 31, 2010			December 31, 2009
Assets
Current assets
Cash and cash equivalents	$	18,906		$	-
Accounts receivable and other		215,795			180,839
Prepaid expenses and deposits		73,280			15,551
Inventories [Note 5]		75,517			86,819
Fair value of risk management contracts [Note 16]		1,007			-
Future income tax [Note 14]		1,633			-
		386,138			283,209

Long term deposit		12,394			-
Investment tax credits receivable		42,475			-
Property, plant and equipment [Note 6]		4,521,277			4,090,653
Goodwill [Note 1]		404,943			404,943
	$	5,367,227		$	4,778,805

Liabilities and Shareholder’s Equity
Current liabilities
Bank loan [Note 9]	$	-		$	428,017
Accounts payable and accrued liabilities [Note 7]		376,635			216,563
Current portion of convertible debentures [Note 11]		-			182,806
Current portion of 7^7/8% senior notes [Note 10]		-			42,921
Fair value deficiency of risk management contracts [Note 16]		7,553			2,052
		384,188			872,359

Bank loan [Note 9]	$	11,379		$	-
Senior notes [Note 10]		482,389			222,456
Convertible debentures [Note 11]		745,257			748,261
Asset retirement obligations [Notes 7 & 8]		297,105			284,042
Employee future benefits [Note 15]		16,872			17,453
Deferred credit		294			358
Future income tax [Note 14]		178,801			211,188
		2,116,285			2,356,117

Shareholder’s equity
Shareholder’s capital [Note 12]		3,355,350			2,422,688
Deficit		(53,028	)		-
Accumulated other comprehensive loss		(51,380	)		-
		3,250,942			2,422,688
	$	5,367,227		$	4,778,805
Commitments and contingencies [Note 18]
See accompanying notes to these consolidated financial statements.

F - 5

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

					For the Period from
					Incorporation on
					October 9, 2009 to
		For the Year Ended			December 31, 2009
(thousands of Canadian dollars)		December 31, 2010			[Note 1(b)]
Revenue
Petroleum, natural gas, and refined product sales	$	3,956,935		$	-
Royalty expense		(154,757	)		-
		3,802,178			-

Expenses
Purchased products for processing and resale		2,733,019			-
Operating		486,416			-
Transportation and marketing		15,760			-
General and administrative		46,738			-
Realized losses on risk management contracts [Note 16]		1,808			-
Unrealized gains on risk management contracts [Note 16]		(2,358	)		-
Interest and other financing charges on short term debt, net		2,103			-
Interest and other financing charges on long term debt		76,020			-
Depletion, depreciation, amortization and accretion		531,182			-
Currency exchange gain		(3,840	)		-
Large corporations tax recovery and other taxes		(212	)		-
Future income tax recovery		(39,897	)		-
		3,846,739			-
Net loss		(44,561	)		-

Other comprehensive loss
Losses on designated hedges, net of tax [Note 16]		(5,020	)		-
Change to cumulative translation adjustment		(46,360	)		-
Comprehensive loss	$	(95,941	)	$	-
See accompanying notes to these consolidated financial statements.

F - 6

CONSOLIDATED STATEMENT OF SHAREHOLDER’S EQUITY

							Accumulated Other
							Comprehensive
(thousands of Canadian dollars)		Shareholder’s Capital		Deficit			Income
At October 9, 2009	$	-	$	-		$	-
Issued for cash
December 22, 2009		2,422,688		-			-
At December 31, 2009		2,422,688		-			-
Issued for cash
January 29, 2010		465,679		-			-
August 20, 2010		47,000		-			-
October 4, 2010		7,128		-			-
October 25, 2010		38,686		-			-
BlackGold acquisition [Note 4]		374,169		(8,467	)		-
Losses on designated hedges, net of tax [Note 16]		-		-			(5,020	)
Change to cumulative translation adjustment		-		-			(46,360	)
Net loss		-		(44,561	)		-
At December 31, 2010	$	3,355,350	$	(53,028	)	$	(51,380	)
See accompanying notes to these consolidated financial statements.

F - 7

CONSOLIDATED STATEMENTS OF CASH FLOWS

					For the Period from
					Incorporation on
					October 9, 2009 to
		For the Year Ended			December 31, 2009
(thousands of Canadian dollars)		December 31, 2010			[Note 1(b)]
Cash provided by (used in)
Operating Activities
Net loss	$	(44,561	)	$	-
Items not requiring cash
Depletion, depreciation, amortization and accretion		531,182			-
Unrealized currency exchange gain		(2,315	)		-
Non-cash interest expense and amortization of finance charges		(7,029	)		-
Unrealized gains on risk management contracts [Note 16]		(2,358	)		-
Future income tax reduction		(39,897	)		-
Employee benefit obligation [Note 15]		(581	)		-
Other non-cash items		(89	)		-
Realized foreign exchange gain on senior note redemptions		(6,438	)		-
Settlement of asset retirement obligations [Note 8]		(20,257	)		-
Change in non-cash working capital		22,597			-
		430,254			-

Financing Activities
Issue of common shares, net of issue costs		558,493			2,422,688
Bank repayments, net		(406,729	)		-
Issue of 6^7/8% senior notes, net of issue costs		495,935			-
Redemptions of 7^7/8% senior notes		(256,931	)		-
Redemptions of convertible debentures		(180,193	)		-
Change in non-cash working capital		1,952			-
		212,527			2,422,688

Investing Activities
Additions to property, plant and equipment		(475,249	)		-
Business acquisition		(23,400	)		(2,422,688	)
Property acquisitions, net of dispositions		(152,861	)		-
Construction advance [Note 18e]		(31,141	)		-
Acquisition deposit [Note 19]		(40,000	)		-
Change in non-cash working capital		93,331			-
		(629,320	)		(2,422,688	)

Change in cash and cash equivalents		13,461			-

Effect of exchange rate changes on cash		5,445			-

Cash and cash equivalents, beginning of period		-			-

Cash and cash equivalents, end of period	$	18,906		$	-

Interest paid	$	66,917		$	-
Large corporation tax and other tax received, net	$	(212	)	$	-
See accompanying notes to these consolidated financial statements.

F - 8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2010 and for the period from incorporation on October 9, 2009 to December 31, 2009

(tabular amounts in thousands of Canadian dollars)

1.	Nature of Operations and Structure of the Company

	*(a)* *Nature of Operations*

	Harvest Operations Corp. is an integrated energy company with petroleum and natural gas operations focused on the operation and further development of assets in western Canada including the BlackGold oil sands asset (“Upstream operations”) and a medium gravity sour crude hydrocracking refinery and a retail and wholesale petroleum marketing business both located in the Province of Newfoundland and Labrador (“Downstream operations”).

	*(b)* *Structure of the Company*

	On December 22, 2009, KNOC Canada Ltd. (“KNOC Canada”), a wholly owned subsidiary of Korea National Oil Corporation (“KNOC”), acquired all of the issued and outstanding trust units of Harvest Energy Trust (the “Trust”) for $10.00 per unit. The acquisition of all the issued and outstanding trust units of the Trust resulted in a change of control in which KNOC Canada became the sole equity owner of the Trust.

The aggregate consideration for the acquisition of the Trust consists of the following:
		Amount
Cash paid to Trust unitholders	$	1,822,688
Repayment of debt		600,000
	$	2,422,688

This acquisition was accounted for using the purchase method whereby the assets acquired and the liabilities assumed are recorded at fair value with the excess of the consideration over the fair value of the identifiable net assets allocated to goodwill. The following summarizes the allocation of the consideration to the fair value of the Trust’s assets and liabilities:

		Amount
Property, plant and equipment	$	4,090,653
Inventories		86,819
Goodwill		404,943
Net working capital (deficiency)		(20,531	)
Total debt		(1,624,461	)
Asset retirement obligations		(284,042	)
Future income tax liability		(211,188	)
Funding deficiency of pension and other benefit plans		(17,453	)
Fair value of risk management contract		(2,052	)
	$	2,422,688

On May 1, 2010, an internal reorganization was completed pursuant to which the Trust was dissolved and the Trust’s wholly owned subsidiary and manager of the Trust, Harvest Operations Corp., was amalgamated with KNOC Canada to continue as one corporation under the name Harvest Operations Corp (“Harvest” or the “Company”). The recorded amounts of Harvest’s assets and liabilities were determined from the existing carrying values of KNOC Canada’s assets and liabilities.

KNOC Canada was incorporated on October 9, 2009 and did not have any results from operations or cash flows in the period from October 9, 2009 to the acquisition date of December 22, 2009 aside from capital injections from Korea National Oil Corporation to finance the purchase of the Trust.

F - 9

The following unaudited pro forma consolidated results of operations have been prepared as if the acquisition of the Trust and the subsequent reorganization occurred on January 1, 2009:

		*Year Ended 31, 2009*
									Pro Forma
		Harvest			Pro Forma				Harvest
(thousands of Canadian dollars)		Energy Trust			Adjustments		Notes		Operations Corp.
Revenue
Petroleum, natural gas, and refined product sales	$	3,267,945			-			$	3,267,945
Royalty expense		(128,860	)		-				(128,860	)
		3,139,085			-				3,139,085
Expenses
Purchased products for processing and resale		2,015,671			-				2,015,671
Operating		500,586			(47,488	)	(e)		453,098
Transportation and marketing		26,237			-				26,237
General and administrative		38,045			-				38,045
KNOC acquisition costs		18,393			-				18,393
Realized gains on risk management contract		(62,803	)		-				(62,803	)
Unrealized net losses on risk management contract		37,904			-				37,904
Interest and other financing charges on short term debt, net		8,896			(9,214	)	(b)(c)		(318	)
Interest and other financing charges on long term debt		110,943			(33,066	)	(b)(c)		77,877
Depletion, depreciation, amortization and accretion		527,579			24,992		(a)		552,571
Goodwill impairment		884,077			(884,077	)	(d)		-
Currency exchange gains		(2,265	)		-				(2,265	)
Large corporations tax (recovery) and other tax		(509	)		-				(509	)
Future income tax (reduction )		(28,035	)		31,917		(f)		3,882
		4,074,719			(916,936	)			3,157,783
Net income (loss)		(935,634	)		916,936				(18,698	)
Other comprehensive income
Change to cumulative translation adjustment		(172,058	)		18,942		(g)		(153,116	)
Comprehensive income (loss)	$	(1,107,692	)	$	935,878			$	(171,814	)

The following are summaries of the significant pro forma adjustments:

	a)	Additional depletion, depreciation, amortization and accretion based on the fair value adjustments to property, plant, and equipment.
	b)	Adjustment of the interest and other financing charges to reflect the estimated carrying cost of the debt assumed on acquisition.
	c)	The terms of the credit facility were amended on December 22, 2009 and again on April 30, 2010. Pro forma adjustments were made to adjust interest expense to apply the revised terms from the beginning of January 1, 2009.
	d)	Reversal of goodwill impairment expense recorded by the Trust.
	e)	Operating expense was adjusted to reflect Harvest’s capitalization policy on turnaround and catalyst costs.
	f)	Taxes have also been adjusted for the effect of the items discussed.
	g)	Change to cumulative translation adjustment has been adjusted for the effect of the above items.

F - 10

2.	Significant Accounting Policies

	These financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles.

	*(a)*	*Consolidation*

		These consolidated financial statements include the accounts of Harvest and its subsidiaries. All inter-entity transactions and balances have been eliminated upon consolidation.

	*(b)*	*Use of Estimates*

		The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenues and expenses during the period. Specifically, amounts recorded in the purchase price equations and for depletion, depreciation, amortization and accretion expense, asset retirement obligations, fair value of risk management contracts, employee future benefits, income taxes and amounts used in the impairment tests for goodwill, inventory and property, plant and equipment are based on estimates. These estimates include petroleum and natural gas reserves, future petroleum and natural gas prices, future refined product prices, future interest and currency exchange rates and future costs required to develop those reserves as well as other fair value assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be material.

	*(c)*	*Revenue Recognition*

		Revenues associated with the sale of crude petroleum, natural gas, natural gas liquids and refined products are recognized when title passes to customers and payment has either been received or collection is reasonably certain. Concurrent with the recognition of revenue from the sale of refined products and included in purchased products for resale and processing are associated transportation charges. Revenues for retail services are recorded when the services are provided.

		The sales price of residential home heating fuels and automotive gasoline and diesel within the Province of Newfoundland and Labrador is subject to regulation under the Petroleum Products Act. The Petroleum Products Pricing Commissioner sets the maximum wholesale and retail prices that a wholesaler and a retailer may charge and sets the maximum mark-up between the wholesale price to the retailer and the retail price to the consumer. Prices are set biweekly using a price adjustment formula based on an allowable premium with an interruption formula. The full effect of rate regulation is reflected in the product sales revenue as recorded by Harvest.

	*(d)*	*Cash and Cash Equivalents*

		Cash and cash equivalents are comprised of cash and investments with a maturity date of three months or less and are recorded at fair value.

	*(e)*	*Inventories*

		Inventories are carried at the lower of cost or net realizable value. The costs of inventory are determined using the weighted average cost method. The valuation of inventory is reviewed at the end of each month. When the circumstances that previously caused inventories to be written down below cost no longer exist or when there is clear evidence of an increase in net realizable value because of changed economic circumstances, the amount of the write-down is reversed. The reversal is limited to the amount of the original write-down. The costs of parts and supplies inventories are determined under the average cost method.

	*(f)*	*Joint Interest and Partnership Accounting*

		The subsidiaries of Harvest conduct substantially all of their petroleum and natural gas production activities through joint interests and through partnerships. The consolidated financial statements reflect only Harvest’s proportionate interests in such activities.

	*(g)*	*Property, Plant, and Equipment*

		Upstream Operations

		Harvest follows the full cost method of accounting for its petroleum and natural gas activities. All costs of acquiring petroleum and natural gas properties, whether productive or unproductive, related development costs, and overhead charges directly related to these activities, are capitalized and accumulated in one cost centre. Major capital maintenance projects are capitalized but general maintenance and repair costs that do not extend or enhance the recoverable reserves are charged against income.

F - 11

Proceeds from the sale of petroleum and natural gas properties are applied against capital costs. Gains and losses are not recognized on the disposition of petroleum and natural gas properties unless that disposition would alter the rate of depletion and depreciation by 20% or more.

Provision for depletion and depreciation of petroleum and natural gas assets is calculated using the unit-of-production method, based on proved reserves net of royalties as evaluated by independent petroleum engineers. The cost basis used for the depletion and depreciation provision is the capitalized costs of petroleum and natural gas assets including undeveloped property plus the estimated future development costs of proved undeveloped reserves. Reserves are converted to equivalent units on the basis of six thousand cubic feet of natural gas to one barrel of petroleum, reflecting the approximate relative energy content.

Harvest places a limit on the aggregate carrying amount of property, plant and equipment associated with petroleum and natural gas activities which may be amortized to depletion and depreciation in future periods. Impairment is recognized when the carrying amount of the petroleum and natural gas assets exceeds the sum of the undiscounted future cash flows expected from the proved reserves.

To recognize impairment, Harvest would then measure the amount of impairment by comparing the carrying amounts of the petroleum and natural gas assets to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves using the risk-free discount rate. Any excess carrying amount above the net present value of Harvest’s future cash flows would be a permanent impairment and reflected as a charge to net income for the period. Present value of cash flows are calculated based on future price estimates, adjusted for Harvest’s contractual arrangements related to pricing and quality differentials.

The cost of unproved properties is excluded from the impairment test calculation described above and subject to a separate impairment test. An impairment of unproved properties is recognized when the cost base exceeds the fair value determined by a reference to market prices, historical experience or a third party independent evaluation.

The BlackGold oil sands central processing facility is expected to be completed in the fourth quarter of 2012. BlackGold assets have been excluded from the provision for depletion and depreciation and are tested separately for impairment.

Downstream Operations

Property, plant and equipment related to the refining assets are recorded at cost. Depreciation of recorded cost less salvage value is provided on a straight-line basis over the estimated useful life of the assets as set out below. Any gains or losses on disposal of individual assets are recognized in the year of disposal.

	Asset	Period
	Refining and production plant:
	Processing equipment	5 – 35 years
	Structures	15 – 20 years
	Catalysts	2 – 8 years
	Tugs	25 years
	Vehicles	2 – 7 years
	Office and computer equipment	3 – 5 years

General maintenance and repair costs, including major maintenance activities, are expensed as incurred. Major replacements and capital maintenance projects such as turnaround costs are capitalized. Improvements that increase or prolong the service life or capacity of an asset are capitalized.

Property, plant and equipment related to refining assets are tested for recovery whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Property, plant and equipment related to refining assets are not recoverable if their carrying amounts exceed the sum of the undiscounted cash flows expected to result from their use and eventual disposition. If property, plant and equipment related to refining assets are not recoverable, an impairment loss is recognized in an amount by which their carrying amount exceeds their fair value, with fair value determined based on discounted estimated net cash flows.

F - 12

	*(h)*	*Capitalized Interest*

		Interest on major development projects are capitalized until the project is complete using the weighted-average interest rate on all of Harvest’s borrowings.

	*(i)*	*Goodwill*

		Goodwill is recognized when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of the acquired business. Goodwill is carried at cost less impairment and is not amortized. The carrying amount of goodwill is assessed for impairment annually at year-end or more frequently if events occur that could result in an impairment. The goodwill impairment test is a two-step test. In the first step, the carrying amount of the assets and liabilities, including goodwill, is compared to the fair value of the reporting unit. The fair value of a reporting unit is determined by calculating the present value of the expected future cash flows from the reporting unit. If the fair value is less than the carrying amount of the reporting unit, a potential impairment of goodwill may exist requiring the second test to be performed. Impairment is measured by allocating the fair value of the reporting unit, as determined in the first test, over the fair value of the identifiable assets and liabilities. The excess of the fair value of the reporting unit over the fair value of the identifiable assets and liabilities represents the fair value of goodwill. The excess of the book value of goodwill over this implied fair value is then recognized as an impairment and charged to income in the period in which it occurs.

	*(j)*	*Asset Retirement Obligations*

		Harvest recognizes the fair value of any asset retirement obligations as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and normal use of the assets. Harvest uses a credit-adjusted risk free discount rate to estimate this fair value. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted and depreciated using the method described under “Property, Plant and Equipment”. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each subsequent period to reflect the passage of time and changes in the timing and amount of estimated future cash flows underlying the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded.

	*(k)*	*Income Taxes*

		Harvest follows the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using enacted or substantively enacted income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

	*(l)*	*Employee Future Benefits*

		Harvest’s Downstream operations maintains a defined pension benefit plan and provides certain post-retirement health care benefits, which cover the majority of its employees and their surviving spouses. The cost of providing the defined pension benefits and other post-retirement benefits is actuarially determined based upon an independent actuarial valuation using management’s best estimates of discount rates, rate of return on plan assets, rate of compensation increase, retirement ages of employees, and expected health care costs. The cost of pensions earned by employees is actuarially determined using the projected benefit method prorated on credited service. Funding of the defined benefit pension plans complies with Canadian federal and provincial regulations, and requires contributions to the plans be made based on independent actuarial valuation. Pension plan assets are measured at fair values with the difference between the fair value of the plan assets and the total employee benefit obligation recorded on the balance sheet. For the purpose of calculating the expected return on assets, the fair value of the plan assets is used.

		The defined benefit plans provide benefits based on length of service and the best five years of the last ten years’ average earnings. There is no recognition or amortization of actuarial gains or losses less than 10% of the greater of the accrued benefit obligations and the fair value of plan assets for the defined benefit pension plans. Actuarial gains and losses over 10% are amortized over the average remaining service period of the plan participants. Actuarial gains or losses related to the other post-retirements benefits are recognized in income immediately. Past service costs are amortized on a straight-line basis over the expected average remaining service life of plan participants.

F - 13

	*(m)*	*Currency Translation*

		Monetary assets and liabilities denominated in a currency other than Canadian dollars are translated at the exchange rate in effect at the balance sheet date. Revenues and expenses denominated in a foreign currency are translated at the monthly average rate of exchange. Translation gains and losses are included in income in the period in which they arise.

		Harvest’s investment in its Downstream operations, which is considered a self-sustaining operation with a U.S. dollar denominated functional currency, is translated using the current rate method. Gains and losses resulting from this translation are recorded in other comprehensive income with the cumulative translation adjustments reported in accumulated other comprehensive income.

	*(n)*	*Financial Instruments*

		Harvest recognizes financial assets and financial liabilities, including derivatives, on the consolidated balance sheet when the Company becomes a party to the contract. Financial liabilities are removed from the consolidated financial statements when the liability is extinguished either through settlement of or release from the obligation of the underlying liability.

		The Company initially measures all financial instruments at fair value. Subsequent measurement of the financial instruments is based on their classification. Financial assets are classified into the following categories: held for trading, available for sale, held-to-maturity investments and loans and receivables. Financial liabilities are classified as held for trading or other financial liabilities.

		Financial assets and financial liabilities classified as held for trading are measured at fair value with changes in those fair values recognized in net income. Financial assets classified as either held-to-maturity or loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Financial assets classified as available-for-sale are measured at fair values with changes in those fair values recognized in other comprehensive income. The Company has not designated any financial assets or financial liabilities upon initial recognition as held for trading.

		Financial assets and financial liabilities are offset and the net amount reported in the consolidated balance sheets if, and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the assets and settle the liabilities simultaneously.

		Transaction costs relating to financial instruments classified as held for trading are expensed in net income in the period that they are incurred. For transaction costs that are directly attributable to the acquisition or issuance of financial instruments not classified as held for trading, they are included in the costs of the financial instruments upon initial recognition.

		Harvest assesses at each reporting date whether there is any objective evidence that a financial asset or a group of financial assets is impaired, as a result of one or more events that has occurred after the initial recognition of the asset (an incurred ‘loss event’) and that loss event has an impact on the estimated future cash flows of the financial asset or the group of financial assets that can be reliably estimated.

	*(o)*	*Hedges*

		Harvest uses derivative financial instruments such as foreign currency contracts and financial commodity contracts to hedge its foreign currency risks and commodity price risks. Such derivative financial instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Any gains or losses arising from changes in the fair value of derivatives are recorded in net income, except for the effective portion of cash flow hedges, which is recognized in other comprehensive income.

		At the inception of a hedge relationship, Harvest formally designates and documents the hedge relationship to which the Company intends to apply hedge accounting. The designation document includes the risk management objective and strategy for undertaking the hedge, the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged and how the Company will assess the hedge effectiveness. Upon designation and at each reporting date, Harvest assesses hedge effectiveness by comparing the changes in the hedging instrument’s fair value and the changes in the hedged item’s fair value or cash flows attributable to the hedged risk. Only if such hedges are highly effective in achieving offsetting changes in fair value or cash flows will Harvest continue to apply hedge accounting.

F - 14

		The effective portion of the gain or loss on the hedging instrument is recognized directly in other comprehensive income, while any ineffective portion is recognized immediately in net income. Amounts recognized in other comprehensive income are transferred to the income statement when the hedged transaction affects net income, such as when the hedged forecasted transaction occurs. Where the hedged item is the cost of a non-financial asset or non- financial liability, the amounts recognized as other comprehensive income are transferred to the initial carrying amount of the nonfinancial asset or liability.

		If the forecast transaction is no longer expected to occur, the cumulative gain or loss previously recognized in other comprehensive income is transferred to net income. If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked, any cumulative gain or loss previously recognized in other comprehensive income remains in other comprehensive income until the forecast transaction affects net income.

	*(p)*	*Investment Tax Credits*

		Harvest is entitled to certain investment tax credits on qualifying manufacturing expenditures relating to its Downstream operations. These credits are recorded as a reduction of the related expense or as a reduction of the cost of the related asset. The benefits are recognized when the Company has complied with the terms and conditions of applicable tax legislation provided there is reasonable assurance of realization.

3.	New Accounting Policies

	*Future Accounting Changes*

	Business Combinations, Consolidated Financial Statements and Non-Controlling Interests

	The CICA Handbook Section 1582 ‘‘Business Combinations’’ is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting the standard is expected to have a material effect on the way the Company accounts for future business combinations. Entities adopting Section 1582 will also be required to adopt CICA Handbook Sections 1601 ‘‘Consolidated Financial Statements’’ and 1602 ‘‘Non-Controlling Interests’’. These standards require non-controlling interests to be presented as part of Shareholder’s Equity on the balance sheet. In addition, the income statement of the controlling parent will include 100 per cent of the subsidiary’s results and present the allocation between the controlling and non-controlling interests. These standards will be effective January 1, 2011, with early adoption permitted. Harvest has not elected to early adopt these standards. The changes resulting from adopting Section 1582 will be applied prospectively and the changes from adopting Sections 1601 and 1602 will be applied retrospectively.

	International Financial Reporting Standards (“IFRS”)

	In February 2008, the CICA Accounting Standards Board (“ASB”) announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (“IFRS”) commencing January 1, 2011 which will require comparative IFRS information for the 2010 year end. Harvest will begin reporting under IFRS for the periods starting from January 1, 2011.

4.	Acquisitions

	(a) Petroleum and natural gas assets

	On September 30, 2010, Harvest acquired a package of petroleum and natural gas assets which included the remaining 40% interest in Red Earth Partnership for total cash consideration of $146.2 million. As a result of the acquisition, $161.3 million was added to property, plant and equipment, $7.4 million to asset retirement obligations and $7.7 million to future income tax liability. The operating results of the acquired assets were included in the consolidated financial statements commencing on the acquisition date.

	(b) BlackGold Oil Sands Project

	On August 6, 2010, Harvest closed the acquisition of the BlackGold oil sands project (“BlackGold”) from KNOC for $374 million, representing the fair value of the oil and gas assets acquired as determined by an independent valuation. The acquisition was financed with the issuance of shares to KNOC. As KNOC is the sole shareholder of Harvest, they will be retaining control over BlackGold. Given there is no substantive change in the ownership interest of the BlackGold assets, these assets have been recorded by Harvest at the carrying values as previously recorded by KNOC.

F - 15

The following amounts were added to Harvest’s balance sheet at August 6, 2010:

	Amount ($000's	)

Current assets	500
Property, plant and equipment	365,212
Long-term liabilities	(10	)
Common shares	(374,169	)
Deficit	8,467

	KNOC has injected $85.7 million of capital for further development of the BlackGold assets since August 6, 2010.

5.	Inventories

		December 31, 2010		December 31, 2009
Petroleum products
Upstream – pipeline fill	$	1,010	$	1,183
Downstream		70,586		81,240
		71,596		82,423
Parts and supplies		3,921		4,396
Total inventories	$	75,517	$	86,819

	For the year ended December 31, 2010, Harvest recognized inventory impairments of $2.4 million in its Downstream operations. Such write-down and recoveries amounts are included as costs in “Purchased products for processing and resale” in the consolidated statements of income (loss).

6.	Property, Plant and Equipment

		December 31, 2010									December 31, 2009
		Upstream			Downstream			Total			Upstream		Downstream		Total
Cost	$	3,955,539		$	1,079,478		$	5,035,017		$	2,976,911	$	1,113,742	$	4,090,653
Accumulated depletion and depreciation		(435,239	)		(78,501	)		(513,740	)		-		-		-
Net book value	$	3,520,300		$	1,000,977		$	4,521,277		$	2,976,911	$	1,113,742	$	4,090,653

General and administrative costs of $14.6 million and borrowing costs of $0.4 million have been capitalized in Upstream property, plant and equipment during year ended December 31, 2010. Capitalized borrowing costs relate to the BlackGold oil sands project.

All costs, except those associated with major spare parts inventory, assets under construction and major development projects, are subject to depletion, depreciation and amortization at December 31, 2010 including future development costs of $533.2 million. At December 31, 2010 the following costs were excluded from the asset base subject to depreciation, depletion and amortization: Downstream major parts inventory of $6.8 million, Downstream assets under construction of $68.8 million and Upstream BlackGold oil sands project assets of $385.3 million. For the year ended December 31, 2010, an investment tax credit of $42.7 million was applied against Downstream assets.

The petroleum and natural gas future prices used in the impairment test for petroleum and natural gas assets were obtained from third party engineers and accepted by management. Based on these assumptions, the undiscounted future net revenue from Harvest’s proved reserves exceeded the carrying amount of its petroleum and natural gas assets as at December 31, 2010 and 2009, and therefore no impairment was recorded in either of the periods ended on these dates.

Benchmark prices and U.S.$/Cdn.$ exchange rate assumptions reflected in the impairment test as at December 31, 2010 were as follows:

F - 16

	WTI Oil⁽¹⁾	Currency	Edmonton Light Crude	AECO Gas⁽¹⁾
Year	(US$/barrel)	Exchange Rate	Oil⁽¹⁾(CDN$ barrel)	(CDN$/MMBtu)
2011	85.00	0.975	84.20	4.25
2012	87.70	0.975	88.40	4.90
2013	90.50	0.975	91.80	5.40
2014	93.40	0.975	94.80	5.90
2015	96.30	0.975	97.70	6.35
Thereafter (escalation)	2%	0%	2%	2%
⁽¹⁾Actual prices used in the impairment test were adjusted for commodity price differentials specific to Harvest.

7.	Accounts Payable and Accrued Liabilities

		December 31, 2010		December 31, 2009
Trade accounts payable	$	146,223	$	71,309
Accrued interest		18,481		16,530
Other accrued liabilities		195,783		117,538
Current portion of asset retirement obligations		16,148		11,186
Total	$	376,635	$	216,563

8.	Asset Retirement Obligations

	Harvest’s asset retirement obligations result from its net ownership interest in petroleum and natural gas assets including well sites, gathering systems and processing facilities and the estimated costs and timing to reclaim and abandon them. Harvest estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations to be approximately $1,242 million which will be incurred between 2011 and 2070. A credit-adjusted risk-free discount rate of 8% - 10% and inflation rate of approximately 2% were used to calculate the fair value of the asset retirement obligations. A reconciliation of the asset retirement obligations is provided below:

		December 31, 2010			December 31, 2009
Balance, beginning of year	$	295,228		$	277,318
Incurred on business acquisition of a private corporation		-			1,411
Liabilities incurred		1,623			1,351
Revision of estimates		1,724			7,219
Net liabilities acquired (settled) through acquisition (disposition)		9,694			(2,538	)
Liabilities settled		(20,257	)		(14,270	)
Accretion expense		25,241			24,737
Balance, end of year⁽¹⁾	$	313,253		$	295,228
⁽¹⁾Current portion of the asset retirement obligation is included in accounts payable and accrued liabilities [Note 7]

	Harvest has undiscounted asset retirement obligations of approximately $14.9 million (2009 – $14.9 million) relating to the refining and marketing assets. The fair value of this obligation cannot be reasonably determined because the timing of retiring the assets is uncertain.

9.	Bank Loan

	At the time of the purchase of the Trust by KNOC Canada on December 22, 2009, the Trust had renegotiated a temporary credit facility of $600 million with the maturity date of April 30, 2010. On April 30, 2010, Harvest entered into an amended and extended credit facility maturing April 30, 2013 and the facility was reduced from $600 million to $500 million. Harvest continues to pay a floating interest rate plus a risk premium that changes based on the Company’s secured debt (excluding 6^7/8% senior notes and convertible debentures) to earnings before interest, taxes, depletion, amortization and other non-cash items (“EBITDA”) ratio. The minimum rate charged on the credit facility is 200 bps over bankers’ acceptance rates as long as Harvest’s secured debt to EBITDA ratio remains below or equal to one. In addition, the credit facility requires standby fees on undrawn amounts.

	The credit facility is secured by a first floating charge over all of the assets of Harvest's operating subsidiaries plus a first mortgage security interest on the Downstream operation’s refinery assets. The most restrictive covenants of Harvest’s credit facility include an aggregate limitation of $25 million on financial assistance and/or capital contributions to parties other than those included in the first floating charge, a limitation to carrying on business in countries that are not members of the Organization of Economic Co-operation and Development and a limitation on the payment of distributions to shareholders of an amount greater than EBITDA minus capital expenditures by Harvest and its subsidiaries. In addition, the capacity under this facility is limited to an amount as outlined in the limitations on liens covenant of the 6^7/8% senior notes described in Note 10 and availability is subject to the following quarterly financial covenants:

F - 17

	Covenant	As at December 31, 2010
Senior debt⁽¹⁾to EBITDA	3.0 to 1.0 or less	0.06
Total debt⁽²⁾to EBITDA	3.5 to 1.0 or less	2.39
Senior debt⁽¹⁾to Capitalization⁽³⁾	50% or less	1%
Total debt⁽²⁾to Capitalization⁽³⁾	55% or less	31%
⁽¹⁾Senior debt consists of letters of credit, bank debt and guarantees.
⁽²⁾Total debt consists of secured debt and convertible debentures and notes.
⁽³⁾Capitalization consists of total debt and shareholders’ equity.

	Harvest’s bank debt is recorded net of transaction costs. At December 31, 2010, $14 million (2009 - $428 million) was drawn from the $500 million (2009 - $600 million) available under the credit facility

10.	Senior Notes

	On October 14, 2004, Harvest issued US$250 million of 7^7/8% senior notes for cash proceeds of $312 million. On September 17, 2010, Harvest issued an Offer To Purchase And Consent Solicitation Statement (the “Offer”) to purchase all of the outstanding 7^7/8% senior notes and solicit consent for amendments of the related indenture. Harvest offered US$983.50 for each US$1,000 principal amount of notes tendered; in addition, for consent to the amendments of the indenture a payment of US$20.00 was offered for each US$1,000 principal amount of notes tendered by September 30, 2010. On October 4, 2010, all conditions of the tender offer were met and Harvest accepted the offer and redeemed US$178.3 million of the US$209.6 million principal amount outstanding for total consideration of $179.0 million. On October 19, 2010, Harvest redeemed the remaining US$31.3 million senior notes at par under the terms of the amended indenture.

	On October 4, 2010, Harvest completed an offering of US$500 million principal amount of 6^7/8% senior notes for net cash proceeds of US$484.6 million. The 6^7/8% senior notes are unsecured, incur interest payments semi-annually on April 1 and October 1 each year, mature on October 1, 2017 and are unconditionally guaranteed by Harvest and all of its wholly-owned subsidiaries that guarantee the revolving credit facility and every future restricted subsidiary that guarantees certain debt. Prior to maturity, the notes are redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed, plus a make-whole redemption premium and accrued and unpaid interest to the redemption date. Harvest may also redeem the notes at any time in the event that certain changes affecting Canadian withholding taxes occur.

	There are also covenants restricting, among other things, the sale of assets and the incurrence of additional indebtedness if such issuance would result in an interest coverage ratio, as defined, of less than 2.0 to 1. Notwithstanding the interest coverage ratio limitation, the incurrence of additional secured indebtedness may not exceed the greater of $1.0 billion and 15% of total assets as outlined in the limitation on liens covenant. In addition, the covenants of the senior notes limit the amount of restricted payments, including dividends to our shareholders, should our defined leverage ratio, be greater than 2.50 to 1. No dividend was paid during the year ended December 31, 2010.

11.	Convertible Debentures

	Harvest has a series of convertible unsecured subordinated debentures outstanding (the “convertible debentures”). Interest on the debentures is payable semi-annually in arrears in equal installments on dates prescribed by each series.

	As a result of the Trust’s acquisition, the debentures are no longer convertible into units but investors would receive $10.00 for each unit notionally received based on each series conversion rate. Because every series of debentures carry a conversion price that exceeds $10.00 per unit, it is assumed that no investor would exercise their conversion option. The debentures may be redeemed by Harvest at its option in whole or in part prior to their respective redemption dates. The redemption price for the first redemption period is at a price equal to $1,050 per debenture and at $1,025 per debenture during the second redemption period. With the exception of the 7.50% debentures due 2015, Harvest may redeem the debentures at par after the second redemption period. Any redemption will include accrued and unpaid interest at such time.

	The following table lists a summary of the outstanding convertible debentures at December 31, 2010:

F - 18

	Conversion price /
Series	share	Maturity	First redemption period	Second redemption period
6.40% Debentures Due 2012	$ 46.00	Oct. 31, 2012	Nov. 1/08-Oct. 31/09	Nov. 1/09-Oct. 31/10
7.25% Debentures Due 2013	$ 32.20	Sept. 30, 2013	Oct. 1/09-Sept. 30/10	Oct. 1/10-Sept. 30/11
7.25% Debentures Due 2014	$ 27.25	Feb. 28, 2014	Mar. 1/10-Feb. 28/11	Mar. 1/11-Feb. 29/12
7.50% Debentures Due 2015	$ 27.40	May 31, 2015	Jun. 1/11-May 31/12	Jun. 1/12-May 31/13

The following table summarizes the face value, carrying amount and fair value of the convertible debentures:

		December 31, 2010						December 31, 2009
				Carrying						Carrying
		Face Value		Amount		Fair Value		Face Value		Amount		Fair Value
6.50% Debentures Due 2010	$	-	$	-	$	-	$	37,062	$	37,562	$	37,562
6.40% Debentures Due 2012		106,796		107,544		108,291		174,626		176,460		176,460
7.25% Debentures Due 2013		330,548		334,804		339,142		379,256		385,703		385,703
7.25% Debentures Due 2014		60,050		60,851		61,912		73,222		74,467		74,467
7.50% Debentures Due 2015		236,579		242,058		248,763		250,000		256,875		256,875
	$	733,973	$	745,257	$	758,108	$	914,166	$	931,067	$	931,067

The “change of control” provision included within the convertible debentures’ indentures required Harvest to make an offer to purchase 100% of the outstanding convertible debentures for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest. Harvest made these offers on January 20, 2010 and by March 4th all of the offers had expired. The following redemptions were made:

6.50% Debentures due 2010 – $13.3 million principal amount tendered, with the remaining principal balance of $23.8 million maturing on December 31, 2010
6.40% Debenture due 2012 – $67.8 million principal amount tendered leaving a principal balance of $106.8 million outstanding
7.25% Debentures due 2013 – $48.7 million principal amount tendered leaving a principal balance of $330.5 million outstanding
7.25% Debentures due 2014 – $13.2 million principal amount tendered leaving a principal balance of $60.1 million outstanding
7.50% Debentures due 2015 – $13.4 million principal amount tendered leaving a principal balance of $236.6 million outstanding

12.	Shareholder’s Capital

	*(a) Authorized*

	The authorized capital consists of an unlimited number of common shares and an unlimited number of preferred shares issuable in series.

	*(b) Number of Common Shares Issued*
	Outstanding at October 8, 2009		-
	Common share issue to KNOC on incorporation at $1 per share		1
	Common shares issued to KNOC at $10.00 per share to fund the Trust acquisition		242,268,801
	Outstanding at December 31, 2009		242,268,802
	Common shares issued to KNOC at $10.00 per share to fund debt repayment		46,567,852
	Common shares issued to KNOC at $10.00 per share for BlackGold consideration [Note 4]		37,416,913
	Common shares issued to KNOC at $10.00 per share to fund BlackGold project development [Note 4]		8,568,600
	Common shares issued to KNOC at $10.00 per share to fund Global Technology & Research Centre development		712,880
	Outstanding at December 31, 2010		335,535,047

13.	Capital Structure

	Harvest considers its capital structure to include its credit facilities, senior notes, convertible debentures and shareholder’s equity.

F - 19

		December 31, 2010		December 31, 2009
Bank debt ⁽¹⁾	$	14,000	$	428,017
6^7/8% Senior Notes ⁽²⁾		497,300		-
7^7/8% Senior Notes ⁽²⁾		-		262,750
Principal amount of convertible debentures		733,973		914,166
Total Debt		1,245,273		1,604,933
Shareholder’s equity		3,250,942		2,422,688
Total capitalization	$	4,496,215	$	4,027,621
(1) Excludes capitalized financing fees
(2) Face value converted at the period end exchange rate

Harvest’s primary objective in its management of capital resources is to have access to capital to fund its financial obligations as well as future growth. Harvest monitors its capital structure and makes adjustments according to market conditions to remain flexible while meeting these objectives. Accordingly, Harvest may adjust its capital spending programs, issue equity, issue new debt or repay existing debt.

Harvest evaluates its capital structure using the following non-GAAP financial ratios: bank debt to twelve month trailing EBITDA; secured debt to net present value of the Company’s proved petroleum and natural gas reverses discounted at 10%; and total debt to total debt plus shareholder’s equity. These ratios are also included in the externally imposed capital requirements per the Company’s credit facility, senior notes and convertible debentures. Harvest was in compliance with all debt covenants at December 31, 2010.

14.

Income Taxes

The future income tax (“FIT”) provision reflects the net tax effects of temporary differences between the carrying amounts of assets and liabilities of the legal entities of Harvest and their corresponding income tax bases. Changes in the temporary differences are reflected in FIT expense (recovery).

As KNOC Canada acquired the Trust, the opening FIT liability is calculated as part of the purchase price allocation recorded at that date. The opening FIT liability of $211.2 million represents a tax liability based on the excess book over tax value of net assets and the related tax impact is calculated at corporate tax rates applicable to the relevant provinces.

At the end of the year ended December 31 2010, Harvest had a net FIT liability of $177.2 million comprised of a $80 million (2009 – $112.5 million) FIT liability for the Downstream corporate entities and $97.2 million (2009 – $98.7 million) FIT liability for the Upstream entities.

FIT liability (asset)
Opening FIT Liability, January 1, 2010 (from PPA)	$	211,188
Ending FIT Liability, net December 31, 2010		177,168
		(34,020	)
Consists of:
FIT recovery for period ended December 31, 2010		(39,897	)
FIT liability associated with partnership acquisition		7,709
FIT recovery associated with the effective portion of hedge accounting		(1,832	)
Total		(34,020	)

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

F - 20

Year Ended December 31, 2010
Loss before taxes	$	(84,670	)
Combined Canadian Federal and Provincial statutory income tax rate		28.25%
Computed income tax recovery at statutory rates		(23,919	)
Increased recovery resulting from the following:
Difference between current and expected tax rates		(11,639	)
Non-taxable portion of capital gain		(2,997	)
Non-deductible expenses and other		(1,342	)
FIT recovery	$	(39,897	)

The components of the FIT liability (asset) are as follows:

		December 31, 2010			December 31, 2009
Net book value of petroleum and natural gas assets in excess of tax pools	$	563,247		$	559,063
Asset retirement obligation		(79,664	)		(75,784	)
Net unrealized gains related to risk management contracts and currency exchange positions – current		(1,633	)		(3,248	)
Net unrealized losses related to risk management contracts and currency exchange positions – long-term		1,643			6,681
Non-capital loss carry forwards for tax purposes		(303,116	)		(274,067	)
Deferral of taxable income in partnership					681
Future employee retirement costs		(3,542	)		(2,094	)
Working capital and other items		233			(44	)
FIT liability, net	$	177,168		$	211,188

The expiry dates on the consolidated non-capital losses and Downstream operations’ ITC are as follows:

		Non-capital		Investment tax
Year of Expiry		losses		credits
2013	$	9,768	$	-
2014		40,411		-
2018		-		1,932
2019		-		3,753
2020		-		3,042
2021		-		2,976
2022		-		3,850
2023		366		5,792
2024		902		3,346
2025		97,444		5,533
2026		40,698		1,701
2027		449,517		3,356
2028		344,376		3,561
2029		110,572		1,616
2030		249,061		2,017
	$	1,343,115	$	42,475

F - 21

15.	Employee Future Benefit Plans

	The measurement of the accrued benefit obligation and annual expense for the defined benefit plans requires actuarial calculations and several assumptions. These assumptions are as follows:

	December 31, 2010		December 31, 2009
		Other		Other
	Pension	Benefit	Pension	Benefit
	Plans	Plans	Plans	Plans

Discount rate	5.25%	5.25%	5.5%	5.5%
Expected long-term rate of return on plan assets	7.0%	-	7.0%	-
Rate of compensation increase	3.5%	-	3.5%	-
Employee contribution of pensionable income	6.0%	-	6.0%	-
Annual rate of increase in covered health care benefits	-	8%	-	9.0%
Expected average remaining service lifetime (years)	12.0	10.3	12.2	10.5

The assets of the defined benefit plan are invested and maintained in the following asset mix:

	December 31, 2010	December 31, 2009

Bonds/fixed income securities	32%	31%
Equity securities	68%	69%

Total cash payments for employee future benefits, consisting of cash contributed by Harvest to the pension plans and other benefit plans was $3.9 million for the year ended December 31, 2010; expected contributions in 2011 are $3.4 million for the pension plans and $0.3 million for the other benefit plan.

The expected long-term rates of return are estimated based on many factors, including the expected forecast for inflation, risk premiums for each class of asset, and current and future financial market conditions.

The defined benefit pension plans were subject to an actuarial valuation on December 31, 2010, and the next valuation report will be as at December 31, 2011. The post-retirement health care benefits plan was last subject to an actuarial valuation on December 31, 2010.

		December 31, 2010
		Pension Plans			Other Benefit Plans

Employee benefit obligation, beginning of year	$	56,476		$	7,047
Current service costs		2,189			291
Interest		3,258			397
Actuarial losses		3,776			593
Benefits paid		(1,908	)		(427	)
Employee benefit obligation, end of year		63,791			7,901

Fair value of plan assets, beginning of year		46,070			-
Actual return on plan assets		2,034			-
Employer contributions		3,605			257
Employee contributions		1,526			170
Benefits paid		(1,908	)		(427	)
Fair value of plan assets, end of year		51,327			-
Funded status - deficit	$	(12,464	)	$	(7,901	)
Unamortized net actuarial losses		3,493			-
Carrying amount	$	(8,971	)	$	(7,901	)

		December 31, 2010		December 31, 2009
Summary:
Pension plans	$	8,971	$	10,406
Other benefit plans		7,901		7,047
	$	16,872	$	17,453

F - 22

Estimated pension and other benefit payments to plan participants which reflect expected future service, expected to be paid from 2011 to 2020, are as follows:

		Pension Plans		Other Benefit Plans

2011	$	1,930	$	520
2012		2,147		732
2013		2,421		875
2014		2,891		1,060
2015		3,277		1,248
2016 to 2020		23,963		10,519
Total	$	36,629	$	14,954

The table below shows the components of the net benefit plan expense:

		Year ended December 31, 2010
		Pension Plans			Other Benefit Plans

Current service cost	$	2,189		$	291
Interest costs		3,258			397
Expected return on assets		(3,277	)		-
Amortization of net actuarial losses		-			423
Net benefit plan expense	$	2,170		$	1,111

A 1% change in the expected health care cost trend rate would have the following impacts as at December 31, 2010:

		1% Increase		1% Decrease
Impact on post-retirement benefit expense	$	1	$	(2	)
Impact on projected benefit obligation		5		(5	)

16.	Financial Instruments

	*(a) Fair Values*

	Financial instruments of Harvest consist of accounts receivable, accounts payable and accrued liabilities, bank loan, risk management contracts, convertible debentures and the senior notes.

	The carrying value and fair value of these financial instruments at December 31, 2010 are disclosed below by financial instrument category, as well as any related gains or losses and interest income or expense for the year ended December 31, 2010:

2010
									Interest			Other
		Carrying				Gain /			Income /			Comprehensive
		Value		Fair Value		(Losses)			(Expense)			Income (Loss)
Financial Assets
Loans and Receivables
Accounts receivable	$	215,795	$	215,795	$	-		$	108	⁽³⁾	$	-
Held for Trading
Fair value of risk management contracts		1,007		1,007		1,252	⁽⁴⁾		-			-
Total Financial Assets		216,802		216,802		1,252			108			-
Financial Liabilities

Held for Trading
Fair value of risk management contracts		7,553		7,553		(702	)⁽⁴⁾		-			(5,020	)⁽⁶⁾
Measured at Amortized Cost
Accounts payable and accrued liabilities		360,487		360,487		-			-			-

F - 23

2010
									Interest			Other
		Carrying				Gain /			Income /			Comprehensive
		Value		Fair Value		(Losses)			(Expense)			Income (Loss)
Bank loan		11,379		14,000		-			(5,696	)		-
7^7/8% senior notes⁽¹⁾		-		-		-			(11,992	)		-
6^7/8% senior notes⁽²⁾		482,389		507,246		-			(8,905	)		-
Convertible debentures		745,257		758,108		-			(51,530	)		-
Total Measured at Amortized Costs		1,599,512		1,639,841		-			(78,123	)⁽⁵⁾		(5,020	)
Total Financial Liabilities	$	1,607,065	$	1,647,394	$	(702	)	$	(78,123	)	$	(5,020	)

	⁽¹⁾	The face value of the 7^7/8% Senior Notes at December 31, 2010 is $nil (December 31, 2009 - $262.8 million or US$250 million).
	⁽²⁾	The face value of the 6^7/8% Senior Notes at December 31, 2010 is $497.3 million or US$500 million (December 31, 2009 - $nil).
	⁽³⁾	Included in petroleum, natural gas, and refined product sales in the statement of income and comprehensive income.
	⁽⁴⁾	Included in risk management contracts - realized and unrealized gains (losses) in the statement of income and comprehensive income.
	⁽⁵⁾	Included in interest and other financing charges on short term/long term debt in the statement of income and comprehensive income; net of capitalized interests.
	⁽⁶⁾	Net of deferred tax of $1.8 million

Due to the KNOC acquisition, the carrying value of all financial assets and financial liabilities was equal to the fair value at December 31, 2009.

Harvest enters into risk management contracts with various counterparties, principally financial institutions with investment grade credit ratings. Derivatives valued using valuation techniques with market observable inputs include foreign exchange contracts and financial commodity contracts. The most frequently applied valuation techniques include forward pricing and swap models, using present value calculations. The models incorporate various inputs including the credit quality of counterparties, foreign exchange spot and forward rates, interest rate curves and forward rate curves of the underlying commodity.

The fair values of the risk management contracts are net of a credit valuation adjustment attributable to derivative counterparty default risk. The changes in counterparty credit risk had no material effect on the hedge effectiveness assessment for derivatives designated in hedge relationships and other financial instruments recognized at fair value.

The fair values of the convertible debentures and the senior notes are based on quoted market prices as at December 31, 2010. The fair value of the bank loan approximates to the carrying value (excluding deferred financing charges) as the bank loan bears floating market rates. The carrying value of the bank loan includes $2.6 million of deferred financing charges at December 31, 2010. Due to the short term maturities of accounts receivable, deposits and accounts payable and accrued liabilities, their carrying values approximate their fair values.

Harvest’s financial assets and liabilities recorded at fair value have been classified according to the following hierarchy based on the amount of observable inputs used to value the instrument: Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: other techniques for which all inputs which have a significant effect on the recorded fair value are observable, either directly or indirectly Level 3: techniques which use inputs that have a significant effect on the recorded fair value that are not based on observable market data

Harvest’s cash and cash equivalents and risk management contracts have been assessed on the fair value hierarchy described above. Cash and cash equivalents are classified as Level 1 and risk management contracts as Level 2. During the year ended December 31, 2010, there were no transfers among Levels 1, 2 and 3.

(b) Risk Management Contracts

Harvest purchases electricity for consumption in its facilities. As a result, the Company is exposed to electricity price volatility. Harvest uses electricity price swap contracts to manage some of its price risk exposures. These swap contracts are not designated as hedges and are entered into for periods consistent with forecast electricity purchases. The total realized loss and unrealized gain recognized in the consolidated statement of income relating to the electricity price swap contracts was $1.8 million and $3.1 million respectively.

Harvest is exposed to fluctuations in crude prices relating to its petroleum sales. The Company enters into crude oil swap contracts to reduce the volatility of cash flows from some of its forecast sales The swaps were designated as cash flow hedges and are entered into for periods consistent with the forecast petroleum sales. The effective portion of the unrealized loss of $5.0 million (net of deferred tax asset of $1.8 million) was included in other comprehensive income for the year ended December 31, 2010. The amount removed from accumulated other comprehensive income during the period and included in petroleum, natural gas, and refined product sales was $nil for the year ended December 31, 2010. The Company expects that the $5.0 million of losses reported in accumulated other comprehensive income will be released to net income within the next 12 months. The ineffective portion of the cash flow hedges recognized in the consolidated income statement for the year ended December 31, 2010 was $0.7 million.

F - 24

The following is a summary of Harvest’s risk management contracts outstanding at December 31, 2010:

Contracts not Designated as Hedges
Contract Quantity	Type of Contract	Term	Contract Price	Fair value
30 MWh	Electricity price swap contracts	Jan - Dec 2011	Cdn $46.87	$ 1,007

Contracts Designated as Hedges
Contract quantity	Type of Contract	Term	Contract Price	Fair value
8200 bbls/day	Crude oil price swap contract	Jan - Dec 2011	US $91.23/bbl	$ (7,553)

	*(c)*	*Risk Exposures*
		Harvest is exposed to market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates in the normal course of operations. Harvest is also exposed, to a lesser extent, to credit risk on accounts receivable and price risk management contracts and to liquidity risk relating to the Company’s debt.

	(i.)	Credit Risk
		Upstream Accounts Receivable
		Accounts receivable in Harvest’s Upstream operations are due from crude oil and natural gas purchasers as well as joint venture partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Concentration of credit risk is mitigated by having a broad customer base, which includes a significant number of companies engaged in joint operations with Harvest. Harvest periodically assesses the financial strength of its crude oil and natural gas purchasers and will adjust its marketing plan to mitigate credit risks. This assessment involves a review of external credit ratings; however, if external ratings are not available, Harvest requests a guarantee from the parent company that does have a credit rating. If this is not possible, Harvest performs an internal credit review based on the purchaser’s past financial performance. The credit risk associated with joint venture partners is mitigated by reviewing the credit history of partners and requiring some partners to provide cash prior to incurring significant capital costs on their behalf. Additionally, most agreements have a provision enabling Harvest to use the proceeds from the sale of production that would otherwise be taken in kind by the partner to offset amounts owing from the partner that is in default. Generally, the only instances of impairment are when a purchaser or partner is facing bankruptcy or extreme financial distress.

		Risk Management Contract Counterparties
		Harvest is exposed to credit risk from the counterparties to its risk management contracts. This risk is managed by diversifying Harvest’s risk management portfolio among a number of counterparties limited to lenders in its syndicated credit facilities; Harvest has no history of losses with these counterparties.

		Downstream Accounts Receivable
		The supply and offtake agreement exposes Harvest to the credit risk of Vitol Refining S.A. (“Vitol”) as all feedstock purchases and the majority of product sales are made with Vitol. Pursuant to the agreement, Vitol is required to maintain a minimum B+ credit rating as assessed by Standard and Poor’s Rating Services. If the credit rating falls below this line, additional security is required to be supplied to Harvest. This credit risk is also mitigated by the amounts owing to Vitol for feedstock purchases that are offset against amounts receivable from Vitol for product sales with the balance being net settled. Harvest is in a net payable position with Vitol at December 31, 2010 accordingly the outstanding balance is included in current trade accounts payable in the liability liquidity table.

		Harvest’s maximum exposure to credit risk relating to the above classes of financial assets at December 31, 2010 is the carrying value of accounts receivable. The table below provides an analysis of Harvest’s current financial assets and the age of its past due but not impaired financial assets by type of credit risk.

F - 25

				Overdue AR
						> 30 days,		> 60 days,
		Current AR		< 30 days		< 60 days		< 90 days		> 90 days
Upstream accounts receivable	$	119,853	$	662	$	283	$	824	$	8,891
Downstream accounts receivable		79,340		4,503		845		312		283
Total	$	199,193	$	5,165	$	1,128	$	1,136	$	9,174	⁽¹⁾
⁽¹⁾Includes a $4.1 million allowance for doubtful accounts.

	(ii.)	Liquidity Risk
		Harvest is exposed to liquidity risk due to the Company’s borrowings under its credit facilities, convertible debentures and 6^7/8% senior notes. This risk is mitigated by managing the maturity dates on the Company’s obligations, complying with covenants and managing the Company’s cash flow by entering into price risk management contracts. Additionally, when Harvest enters into price risk management contracts it selects counterparties that are also lenders in its syndicated credit facility thereby using the security provided in the credit agreement eliminating the requirement for margin calls and the pledging of collateral.

		The following table provides an analysis of Harvest’s financial liability maturities based on the remaining terms of its liabilities as at December 31, 2010 and includes the related interest charges:

				>1 year		>4 years
		<1 year		<3 years		<5 years		>5 years		Total
Trade accounts payable and accrued liabilities	$	342,006		-		-		-	$	342,006
Settlement of risk management contracts		7,553		-		-		-		7,553
Bank loan and interest		114		14,600		-		-		14,714
Convertible debentures and interest		52,897		529,120		322,417		-		904,434
7^7/8% senior notes and interest		34,189		68,379		68,379		557,131		728,078
Total	$	436,759	$	612,099	$	390,796	$	557,131	$	1,996,785

	(iii.)	Market Risks and Sensitivity Analysis
		Harvest is exposed to three types of market risks: interest rate risk, currency exchange rate risk and commodity price risk. Harvest has performed sensitivity analysis on the three types of market risks identified, assuming that the volatility of the risks over the next year will be similar to that experienced in the past year. Harvest has determined that a reasonably possible price or rate variance over the next reporting period for a given risk variable can be estimated by calculating two standard deviations for each three month period in the last year for the relevant daily price/rate settings and using an average of the standard deviation as a reasonable estimate of the expected variance. This variance is then applied to the relevant period end rate or price to determine a reasonable percentage increase and decrease in the risk variable which can then be applied to the outstanding risk exposure at period end. Using twelve months of data, Harvest factors in the seasonality of the business and the price volatility therein.

		Interest Rate Risk
		Harvest is exposed to interest rate risk on its bank borrowings as interest rates are determined in relation to floating market rates plus an incremental charge based on the Company’s secured debt to EBITDA ratio. Harvest’s convertible debentures and 6^7/8% senior notes have fixed interest rates and therefore do not have any additional interest rate risk. Harvest manages its interest rate risk by targeting appropriate levels of debt relative to its expected cash flow from operations.

		For the year ended December 31, 2010, interest charges on bank loans aggregated to $5.7 million reflecting an effective interest rate of 3.7%.

		If the interest rate applicable to Harvest’s bank borrowings at December 31, 2010 increased or decreased by 40 basis points (0.4%) with all other variables held constant, after-tax net income for the year would decrease by $0.9 million or increase by $0.3 million respectively as a result of change in interest expense on variable rate borrowing.

		Currency Exchange Rate Risk
		Harvest is exposed to the risk of changes in the U.S. dollar exchange rate on its U.S. dollar denominated revenues as well as Canadian dollar revenues that are based on a U.S. dollar commodity price. In addition, Harvest’s 6^7/8% senior notes are denominated in U.S. dollars (U.S.$500 million) and interest on these notes is payable semi-annually in U.S. dollars and accordingly the principal and any interest payable at the balance sheet date are also subject to currency exchange rate risk. Harvest is also exposed to currency exchange rate risk on its net investment in its Downstream operations which is a self sustaining subsidiary that has a U.S. dollar functional currency. Harvest manages these exchange rate risks by occasionally entering into fixed rate currency exchange contracts on future U.S. dollar payments and U.S. dollar sales receipts.

F - 26

At December 31, 2010, if the U.S. dollar strengthened or weakened by 8% relative to the Canadian dollar, the impact on net income and other comprehensive income due to the translation of monetary financial instruments would be as follows:

					Impact on Other
		Impact on Net Income			Comprehensive income
U.S. Dollar Exchange Rate - 8% increase	$	39,418		$	(3,384	)
U.S. Dollar Exchange Rate - 8% decrease	$	(39,418	)	$	3,384

Harvest’s Downstream operations operates with a U.S. dollar functional currency which gives rise to currency exchange rate risk on the Company’s Canadian dollar denominated monetary assets and liabilities, such as Canadian dollar bank accounts and accounts receivable and payable, as follows:

		Impact on Net Income
Canadian Dollar Exchange Rate - 8% increase	$	(4,864	)
Canadian Dollar Exchange Rate - 8% decrease	$	4,864

Commodity Price Risk

Harvest is exposed to electricity and crude oil price movements as part of its normal business operations. The Company uses price risk management contracts to hedge a portion of the Company’s future cash flows and net income against unfavorable movements in commodity prices. These contracts are recorded on the balance sheet at their fair value as of the reporting date. Changes from the prior period’s fair value for electricity contracts are reported in net income. The effective portion of the changes from the prior period’s fair value for crude oil contracts are reported in other comprehensive income. These fair values are generally determined as the difference between the stated fixed price of the contract and an expected future price of power and oil. Variances in expected future prices expose Harvest to commodity price risk as changes will result in a gain or loss that Harvest will realize on settlement of these contracts. This risk is mitigated by continuously monitoring the effectiveness of these contracts.

If the following changes in expected forward prices were applied to the fair value of risk management contracts in place at December 31, 2010, net income would be impacted as follows:

					Impact on Other
		Impact on Net Income			Comprehensive Income
Forward price of electricity – 75% increase	$	9,993		$	-
Forward price of electricity – 75% decrease	$	(6,755	)	$	-
Forward price of crude oil – 10% increase	$	(2,844	)	$	(25,058	)
Forward price of crude oil – 10% decrease	$	1,336		$	11,490

17.	Segment Information

	Harvest operates in Canada with two reportable operating segments, Upstream and Downstream. Harvest’s Upstream operations consist of development, production and subsequent sale of petroleum, natural gas and natural gas liquids, while its Downstream operations include the purchase of crude oil, the refining of crude oil, the sale of the refined products including a network of retail operations and the supply of refined products to commercial and wholesale customers.

		Year Ended December 31, 2010
		Downstream⁽¹⁾		Upstream⁽¹⁾			Total
Revenue⁽²⁾	$	2,949,930	$	1,007,005		$	3,956,935
		-		(154,757	)
Royalties							(154,757	)
Less:
Purchased products for resale and processing		2,733,019		-			2,733,019
Operating		220,823		265,593			486,416
Transportation and marketing		6,366		9,394			15,760

F - 27

		Year Ended December 31, 2010
		Downstream⁽¹⁾			Upstream⁽¹⁾		Total
General and administrative		1,764			44,974		46,738
Depletion, depreciation, amortization and accretion		83,091			448,091		531,182
	$	(95,133	)	$	84,196	$	(10,937	)


Realized losses on risk management contracts							(1,808	)
Unrealized gain on risk management contracts							2,358

Interest and other financing charges on short term debt, net							(2,103	)

Interest and other financing charges on long term debt							(76,020	)
Currency exchange gain							3,840
Large corporations tax recovery and other taxes							212
Future income tax reduction							39,897
Net loss						$	(44,561	)

Capital Expenditures
Development and other activities	$	71,234		$	404,015	$	475,249
Business acquisitions		-			23,400		23,400
Property acquisitions, net of dispositions		-			152,861		152,861
Total expenditures	$	71,234		$	580,276	$	651,510

	⁽¹⁾	Accounting policies for segments are the same as those described in Note 2 above.
	⁽²⁾	Of the total Downstream revenue, two customers represent sales of $2 billion and $145 million for the year ended December 31, 2010. No other single customer within either segment represents greater than 10% of Harvest’s total revenue.
	⁽³⁾	There is no intersegment activity.

		2010									2009
		Downstream⁽¹⁾			Upstream⁽¹⁾			Total			Downstream⁽¹⁾		Upstream⁽¹⁾		Total
Total Assets⁽²⁾	$	1,215,352		$	4,151,875		$	5,367,227		$	1,273,881	$	3,504,924	$	4,778,805

Property, plant and equipment
Cost	$	1,079,478		$	3,955,539		$	5,035,017		$	1,113,742	$	2,976,911	$	4,090,653
Less: Accumulated depletion, depreciation, and amortization		(78,501	)		(435,239	)		(513,740	)		-		-		-
Net book value	$	1,000,977		$	3,520,300		$	4,521,277		$	1,113,742	$	2,976,911	$	4,090,653

Goodwill
Beginning of period	$	-		$	404,943		$	404,943		$	-	$	404,943	$	404,943
Addition (reduction) to goodwill		-			-			-			-		-		-
Impairment of goodwill		-			-			-			-		-		-
End of period	$	-		$	404,943		$	404,943		$	-	$	404,943	$	404,943

	⁽¹⁾	Accounting policies for segments are the same as those described in Note 2 above.
	⁽²⁾	Total assets on a consolidated basis include $1 million relating to the fair value of risk management contracts and $1.6 million relating to future income tax.

18.	Commitments and Contingencies

	From time to time, Harvest is involved in litigation or has claims brought against it in the normal course of business operations. Management of Harvest is not currently aware of any claims or actions that would materially affect Harvest’s reported financial position or results from operations. In the normal course of operations, management may also enter into certain types of contracts that require Harvest to indemnify parties against possible third party claims, particularly when these contracts relate to purchase and sale agreements. The terms of such contracts vary and generally a maximum is not explicitly stated; as such the overall maximum amount of the obligations cannot be reasonably estimated. Management does not believe payments, if any, related to such contracts would have a material effect on Harvest’s reported financial position or results from operations.

F - 28

The following are the significant commitments and contingencies at December 31, 2010:

	(a)	The Downstream operations have a supply and offtake agreement with Vitol for a primary term to October 31, 2011 after which the agreement will revert to an evergreen arrangement. This agreement continues to provide that the ownership of substantially all crude oil feedstock and refined product inventory at the refinery be retained by Vitol and that Vitol will be granted the right and obligation to provide crude oil feedstock for delivery to the refinery, as well as the right and obligation to purchase substantially all refined products produced by the refinery. At December 31, 2010, the Downstream operations had commitments totaling approximately $775 million in respect of future crude oil feedstock purchases and related transportation from Vitol.

	(b)	North Atlantic Refinery Ltd. (“North Atlantic”), a wholly-owned subsidiary of Harvest, has an agreement with Newsul Enterprises Inc. whereby North Atlantic has committed to provide Newsul with its inventory and production of sulphur to 2018.

	(c)	North Atlantic has been named as a defendant in one of more than 100 methyl tertiary butyl ether U.S. product liability litigation cases that have been consolidated for pre-trial purposes. The plaintiffs seek relief for alleged contamination of ground water from the various defendants' use of the gasoline additives. Although the plaintiffs have not made a particular monetary demand, they are asserting collective and joint liability against all defendants. All consolidated lawsuits are at a preliminary stage and, accordingly, it is too early in the legal process to reach any conclusion regarding the ability of the State of New Hampshire to properly assert jurisdiction over the Company in the lawsuit or to reach any conclusions regarding the substance of the plaintiffs' claims. Accordingly, the evaluation of the risk of liability to the Company is not determinable at this time and no amounts are accrued in the consolidated financial statements in respect of this matter. The Company is indemnified by Vitol Group B.V. in respect of this contingent liability.

	(d)	On January 7, 2010 the Downstream operations experienced a fire at the refinery in the conversion section of the operating units. As a result, the refinery was shut-down for assessment and repairs for approximately ten weeks. Harvest has submitted an insurance claim relating to the business interruption loss. If successful, the estimated net proceeds of the claim will be approximately $15 million.

	(e)	In August 2010 Harvest entered into two contracts in relation to the engineering, procurement and construction of the production and processing facilities required for its BlackGold oil sands project. An engineering and procurement contract was signed with GS Engineering & Construction Corp. (“GSE”) a Korean construction firm, for certain engineering, procurement, fabrication and transportation services. A separate construction and commissioning contract was signed with GSE&C Construction Canada Ltd. (“GSC”), a Canadian incorporated subsidiary of GSE, in respect of work to be performed in Canada. The contracted cost is $311 million. Together, GSE and GSC will perform all works and services, including commissioning and start-up of the facilities, in order to hand them over to Harvest on a turn-key basis. GSC will provide operational support for a limited duration after hand-over. Completion of the facilities for the purpose of such hand-over is scheduled to take place in the fourth quarter of 2012. Harvest provided a cash deposit of $31.1 million to GSC of which $30.6 million remained at December 31, 2010 to be applied to future payments. The remaining balance of the contract is included in the contractual obligation and commitment table below.

The following is a summary of Harvest’s contractual obligations and commitments as at December 31, 2010:

		Payments Due by Period
		2011		2012		2013		2014		2015		Thereafter		Total
Debt repayments	$	-	$	106,796	$	344,548	$	60,050	$	236,579	$	497,300	$	1,245,273
Debt interest payments⁽¹⁾		87,200		86,395		74,359		52,637		41,530		59,831		401,952
Capital commitments⁽²⁾		694,651		111,542		-		-		-		-		806,193
Operating leases⁽³⁾		7,514		7,061		6,294		6,152		1,450		280		28,751
Employee benefits⁽⁴⁾		5,318		3,763		3,827		3,892		3,958		4,025		24,783
Transportation agreements⁽⁵⁾		3,253		916		90		-		-		-		4,259
Feedstock and other purchase commitments⁽⁶⁾		900,131		-		-		-		-		-		900,131
Contractual obligations	$	1,698,067	$	316,473	$	429,118	$	122,731	$	283,517	$	561,436	$	3,411,342

	⁽¹⁾	Interest determined on bank loan balance and rate effective at year end and by using the year end U.S. dollar exchange rate for the senior notes.
	⁽²⁾	Relating to drilling contracts, AFE commitments, equipment rental contract, environmental capital projects, BlackGold oil sands project and Hunt Oil acquisition [see Note 19].
	⁽³⁾	Relating to building and automobile leases.
	⁽⁴⁾	Relating to expected contributions for employee benefit plans [see Note 15] and long term incentive plan.
	⁽⁵⁾	Relating to oil and natural gas pipeline transportation agreements.
	⁽⁶⁾	Relating to crude oil feedstock purchases and related transportation costs [see Note 18(a) above].

F - 29

19.	Subsequent Event

	On February 28, 2011, Harvest acquired certain petroleum and natural gas assets of Hunt Oil Company of Canada, Inc. and Hunt Oil Alberta, Inc. (collectively “Hunt”) for total cash consideration of $505.5 million. An additional $25 million payment to Hunt is payable in the event that Canadian natural gas prices exceed certain pre-determined levels over the next 2 years. Hunt also agreed to reimburse Harvest for costs associated with restoring production as well as the lost revenues relating to certain properties between October 1, 2010 and April 3, 2011, when production was resumed. A portion of the reimbursement may be reverted to Hunt if the future revenues earned by Harvest during the six months after the gas plant restores production exceeds the reimbursed amount. These potential adjustments to the purchase price are considered as contingent considerations and are required to be fair value. Based on forecast gas prices and production the probability of incurring such payments is assessed as low, as such $nil fair value was assigned. KNOC provided $505.4 million of equity to fund the acquisition.

	On April 29, 2011, Harvest extended the term of its credit facility by 2 years to April 30, 2015. The minimum rate charged on the credit facility was also amended from 200 bps to 175 bps over bankers’ acceptance rates as long as Harvest’s secured debt to EBITDA ratio remains below or equal to one. The borrowing capacity of the credit facility remains at $500 million and the financial covenants remain unchanged.

	On April 14, 2011, Vitol provided a six-month notice to terminate the SOA effective November 1, 2011. Harvest is evaluating various options to procure crude feedstock subsequent to the termination date.

F - 30

RECONCILIATION OF THE CONSOLIDATED FINANCIAL STATEMENTS TO U.S. GAAP

Harvest Operation Corp.’s consolidated financial statements have been prepared in accordance with Canadian GAAP which, in most respects, conforms to accounting principles generally accepted in the United States (“U.S. GAAP”). Any differences in accounting principles as they have been applied to the accompanying consolidated financial statements are not material except as described below. Items required for financial disclosure under U.S. GAAP may be different from disclosure standards under Canadian GAAP; such differences are not reflected herein.

The application of U.S. GAAP would have the following effects on net income (loss) and comprehensive income (loss) as reported:

					For the period from
					incorporation on
		For the year ended			October 9, 2009 to
(Thousands of Canadian dollars)		December 31, 2010			December 31, 2009

Net loss under Canadian GAAP	$	(44,561	)	$	-

U.S. GAAP Adjustments					-
Write-down of property, plant and equipment ^(a)		-			(1,156,746	)
Depletion, depreciation, amortization and accretion ^(b)		132,743			-
General and administrative expenses ^(c)		(263	)		-
Interest and other financing charges on long term debt ^(e)		8,109			-
Gain on acquisition ^(c)		10,267			-
Future income tax recovery (expense) ^(f)		(43,563	)		299,944
		107,293			(856,802	)

Net income (loss) under U.S. GAAP		62,732			(856,802	)

Other comprehensive income (loss)
Losses on designated hedges, net of tax		(5,020	)		-
Change to cumulative translation adjustment		(46,360	)		-
Employee future benefits – actuarial loss, net of tax ^(d)		(2,620	)		-
Comprehensive income (loss) under U.S. GAAP	$	8,732		$	(856,802	)

A continuity schedule of significant equity accounts for each reporting period is a required disclosure under U.S. GAAP. The following table is a continuity of shareholders’ equity, the Corporation’s only significant equity account.

Shareholder’s Equity

(Thousands of Canadian dollars)		December 31, 2010			December 31, 2009
Balance, beginning of year under Canadian GAAP	$	3,250,942		$	2,422,688
U.S. GAAP adjustments to the prior periods		(856,802	)		-
U.S. GAAP adjustments on net income (loss)		107,293			(856,802	)
Employee future benefits – actuarial loss, net of tax ^(d)		(2,620	)
Balance, end of year under U.S. GAAP	$	2,498,813		$	1,565,886

(a)	Under Canadian GAAP, Harvest performs an impairment test that limits the capitalized costs of its petroleum and natural gas assets to the discounted estimated future net revenues from proved and probable petroleum and natural gas reserves plus the cost of unproved properties less impairment, determined using estimated future prices and costs. The discount rate used is equal to Harvest’s risk-free interest rate.

	Under U.S. GAAP, entities using the full cost method of accounting for petroleum and natural gas activities perform an impairment (ceiling) test on each cost centre using discounted future net revenues, net of applicable income taxes, from proved petroleum and natural gas reserves discounted at 10%. The prices used under the U.S. GAAP impairment test are those that represent an average of the prices on the first day of each month in the prior 12-month period. As at December 31, 2010, the application of the ceiling test under U.S. GAAP did not result in a write down of petroleum and natural gas properties (2009 - $1,156.7 million).

F - 31

(b)	Under Canadian GAAP, proved reserves are estimated using estimated future prices and costs. These proved reserves form the basis for the depletion calculation.

	Under U.S. GAAP, proved reserves used for the depletion calculation are estimated using constant prices and costs as of the date the estimate of reserves is made and as a result, proved reserves under U.S. GAAP and Canadian GAAP differ. There was also a difference in the depletable base as a result of the 2009 impairment charge recorded in accordance with U.S. GAAP compared to Canadian GAAP as explained in note (a) above. As a result, the depletion, depreciation, amortization and accretion expense decreased by $132.7 million (2009 – $nil) in 20010.

(c)	On September 30, 2010, Harvest acquired petroleum and natural gas assets which included the remaining 40% interest in Red Earth Partnership for total cash consideration of $146.2 million. Under U.S. GAAP, this acquisition is considered to be within the scope of ASC 805-10-55, “Business Combinations”, and requires that assets and liabilities acquired in a business combination be measured at their fair values as of the date of the acquisition, and the excess of the fair value of the acquired net assets over consideration paid be recognized in the statement of income (loss).

	For U.S. GAAP purposes, Harvest has increased property, plant and equipment by $7.6 million, increased the future income tax asset by $2.5 million, and has recognized a gain of $10.3 million in the statement of income (loss). In addition, transaction costs of $0.3 million has been expensed under U.S. GAAP.

(d)	Under ASC 715-60, “Defined Benefit Plans - Other Postretirement”, the over-funded or under-funded status of the defined benefit postretirement plan are recognized on the balance sheet as an asset or liability and changes in the funded status are recognized through comprehensive income (loss). Canadian GAAP currently does not require Harvest to recognize the funding status of the plan on its balance sheet. Under U.S. GAAP, Harvest recognized in other comprehensive income $2.6 million (net of income taxes of $0.9 million) of unamortized actuarial loss relating to its defined benefit plan .

(e)	U.S. GAAP requires that for qualifying assets, the amount of interest cost to be capitalized is the portion of the interest cost incurred during the asset's acquisition period that theoretically could have been avoided if expenditures for the asset had not been made. The amount capitalized is determined by applying an interest rate (“the capitalization rate”) to the average amount of accumulated expenditures for the asset during the period. The capitalization rate used is based on the rates applicable to borrowings outstanding during the period. Under Canadian GAAP, a company must develop a policy for the method of capitalizing interest and Harvest's policy was not to apply the capitalization rate to the amounts acquired through an equity transaction. For the year ended December 31, 2010, Harvest capitalized additional interest of $8.1 million (2009 – $nil) under U.S. GAAP.

(f)	As a result of the above U.S. GAAP adjustments, Harvest recognized a future income tax expense of $43.6 million for the year ended December 31, 2010 (2009 – recovery of $300 million).

	The recognition of future income tax recovery of $300 million at December 31, 2009 resulted in the reclassification of future income tax asset of $201.3 million from future income tax liability. At December 31, 2010, due to the 2009 reclassification and the future income taxes recognized during the year, Harvest had $161.6 million of future income asset and $79.1 million of future income tax liability on its consolidated balance sheet under U.S. GAAP.

(g)	Under Canadian GAAP, deferred financing charges relating to the bank loans and the Senior Notes are netted against the carrying values of the debts. Under U.S. GAAP, the deferred financing charges are reclassified and presented as a separate asset. As at December 31, 2010, $17.5 million (2009 - $nil) of deferred financing charges were reclassified to Other Assets.

(h)	The differences between Canadian GAAP and US GAAP have not resulted in any significant variances concerning the statements of cash flows as reported.

(i)	Effective January 1, 2011 the Company will be preparing consolidated financial statements in accordance with IFRS and a reconciliation to U.S. GAAP will not be required. As a result, SAB Topic 11M, “Disclosure of the Impact that Recently Issued Accounting Standards Will Have on the Financial Statements of the Registrant When Adopted in a Future Period” was not provided for 2010.

F - 32

MANAGEMENT’S REPORT

In management’s opinion, the accompanying consolidated financial statements of Harvest Energy Trust (the “Trust”) have been prepared within reasonable limits of materiality and in accordance with Canadian generally accepted accounting principles. Since a precise determination of many assets and liabilities is dependent on future events, the preparation of financial statements necessarily involves the use of estimates and approximations. These have been made using careful judgment and with all information available up to March 5, 2010. Management is responsible for the consistency, therewith, of all other financial and operating data presented in Management’s Discussion and Analysis for the year ended December 31, 2009.

Under the supervision of our Chief Executive Officer and our Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We have concluded that as of December 31, 2009, our internal controls over financial reporting were effective.

The consolidated financial statements and the Trusts’ internal control over financial reporting have been examined by KPMG LLP, Independent Registered Public Accountants. Their responsibility is to express a professional opinion on the fair presentation of the consolidated financial statements in accordance with Canadian generally accepted accounting principles. The Independent Registered Public Accountants Report outlines the scope of their examination and sets forth their opinion on the effectiveness of internal controls over financial reporting.

(signed)	(signed)
John E. Zahary	Kyungluck Sohn
President and	Chief Financial Officer
Chief Executive Officer


Calgary, Alberta
March 5, 2010

F-33


	KPMG LLP
	Chartered Accountants	Telephone (403) 691-8000
	2700 205 - 5^thAvenue SW	Telefax (403) 691-8008
	Calgary AB T2P 4B9	Internet www.kpmg.ca

AUDITORS' REPORT

To the Unitholders of Harvest Energy Trust

We have audited the consolidated balance sheets of Harvest Energy Trust as at December 31, 2009 and 2008 and the consolidated statements of income (loss) and comprehensive income (loss), unitholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2009. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. With respect to the consolidated financial statements for the years ended December 31, 2009 and 2008, we also conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and 2008 and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2009 in accordance with Canadian generally accepted accounting principles.

KPMG LLP

Chartered Accountants

Calgary, Canada
March 4, 2010

F-34

CONSOLIDATED BALANCE SHEETS
As at December 31
(thousands of Canadian dollars)

		2009			2008
Assets
Current assets
Accounts receivable and other	$	180,839		$	173,341
Fair value of risk management contracts [Note 20]		-			36,087
Prepaid expenses and deposits		15,551			11,843
Inventories [Note 5]		81,784			55,788
		278,174			277,059

Property, plant and equipment [Note 6]		3,974,070			4,468,505
Intangible assets [Note 8]		87,846			106,002
Future income tax [Note 18]		64,822			-
Goodwill [Note 7]		-			893,841
	$	4,404,912		$	5,745,407

Liabilities and Unitholders’ Equity
Current liabilities
Bank loan [Note 11]	$	428,017		$	-
Accounts payable and accrued liabilities [Note 9]		216,563			221,418
Cash distribution payable		-			47,160
Current portion of convertible debentures [Note 13]		172,053			2,513
Current portion of 7^7/8% Senior notes [Note 12]		41,909
Fair value deficiency of risk management contracts [Note 20]		2,052			235
		860,594			271,326

Bank loan [Note 11]		-			1,226,228
7^7/8% Senior notes [Note 12]		217,210			298,210
Convertible debentures [Note 13]		665,817			825,246
Asset retirement obligation [Note 10]		284,043			265,997
Employee future benefits [Note 19]		9,394			10,551
Deferred credit		359			522
Future income tax [Note 18]		-			203,998

Unitholders’ equity
Unitholders’ capital [Note 14]		4,669,559			3,897,653
Equity component of convertible debentures		-			84,100
Contributed surplus [Note 15]		315,255			6,433
Accumulated income		(476,750	)		458,884
Accumulated distributions		(2,056,444	)		(1,891,674	)
Accumulated other comprehensive income (loss)		(84,125	)		87,933
		2,367,495			2,643,329
	$	4,404,912		$	5,745,407

Commitments and contingencies [Note 22]
Subsequent events [Note 23]
See accompanying notes to these consolidated financial statements.

Approved by the Board of Directors:

(signed)
Director

F - 35

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31
(thousands of Canadian dollars, except per Trust Unit amounts)

		2009			2008
Revenue
Petroleum, natural gas, and refined product sales	$	3,267,945		$	5,737,809
Royalty expense		(128,860	)		(248,445	)
		3,139,085			5,489,364

Expenses
Purchased products for processing and resale		2,015,671			3,850,507
Operating		500,586			537,149
Transportation and marketing		26,237			34,243
General and administrative [Note 17]		38,045			34,743
Korea National Oil Corporation acquisition related costs [Note 1 and 17]		18,393			-
Realized net (gains) losses on risk management contracts		(62,803	)		200,782
Unrealized net losses (gains) on risk management contracts		37,904			(185,921	)
Interest and other financing charges on short term debt, net		8,896			295
Interest and other financing charges on long term debt		110,943			146,375
Depletion, depreciation, amortization and accretion		527,579			519,811
Goodwill impairment [Note 7]		884,077			-
Currency exchange (gain) loss		(2,265	)		30,882
Large corporations tax and other tax		(509	)		(81	)
Future income tax expense (recovery) [Note 18]		(28,035	)		108,560
		4,074,719			5,277,345
Net income (loss) for the year		(935,634	)		212,019

Other comprehensive income (loss)
Cumulative translation adjustment		(172,058	)		284,692
Comprehensive income (loss) for the year	$	(1,107,692	)	$	496,711

Net income (loss) per Trust Unit, basic [Note 14]	$	(5.38	)	$	1.39
Net income (loss) per Trust Unit, diluted [Note 14]	$	(5.38	)	$	1.39

See accompanying notes to these consolidated financial statements.

F-36

CONSOLIDATED STATEMENTS OF UNITHOLDERS’ EQUITY
As at December 31
(thousands of Canadian dollars)

					Equity											Accumulated
					Component of											Other
		Unitholders’			Convertible			Contributed		Accumulated			Accumulated			Comprehensive
		Capital			Debentures			Surplus		Income			Distributions			Income (Loss)
At December 31, 2007		3,736,080			39,537			-		246,865			(1,340,349	)		(196,759	)
Equity component of convertible debenture issuances
7.5% Debentures Due 2015		-			51,000			-		-			-			-
Convertible debenture conversions
9% Debentures Due 2009		32			-			-		-			-			-
8% Debentures Due 2009		141			(1	)		-		-			-			-
10.5% Debentures Due 2008		13			(3	)		-		-			-			-
Settlement of convertible debentures
10.5% Debentures Due 2008		24,249			(6,433	)		6,433		-			-			-
Exercise of unit appreciation rights and other		1,494			-			-		-			-			-
Issue costs		(2,330	)		-			-		-			-			-
Currency translation adjustment		-			-			-		-			-			284,692
Net income		-			-			-		212,019			-			-
Distributions and distribution reinvestment plan		137,974			-			-		-			(551,325	)		-
At December 31, 2008	$	3,897,653		$	84,100		$	6,433	$	458,884		$	(1,891,674	)	$	87,933
Issued for cash
June 4, 2009		126,509
December 22, 2009		600,000
Issued for corporate acquisition [Note 4a]		4,618
Settlement of convertible debentures
9% Debentures Due 2009		944			-			-		-			-			-
8% Debentures Due 2009		1,588			(11	)		11		-			-			-
Elimination of equity component of convertible debentures resulting from the acquisition by Korea National Oil Corporation [Note 13]		-			(84,089	)		84,089		-			-			-
Exercise of unit appreciation rights and other		397			-			-		-			-			-
Issue costs, net of tax		(5,867	)		-			-		-			-			-
Currency translation adjustment		-			-			-		-			-			(172,058	)

Net loss		-			-			-		(935,634	)		-			-
Distributions and distribution reinvestment plan		43,717			-			-		-			(164,770	)		-
Future income tax adjustment from change in shareholder status [Note 18]		-			-			224,722		-			-			-
At December 31, 2009	$	4,669,559		$	-		$	315,255	$	(476,750	)	$	(2,056,444	)	$	(84,125	)

See accompanying notes to these consolidated financial statements.

F-37

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31
(thousands of Canadian dollars)

		2009			2008
Cash provided by (used in)
Operating Activities
Net income (loss) for the year	$	(935,634	)	$	212,019
Items not requiring cash
Depletion, depreciation, amortization and accretion		527,579			519,811
Impairment of goodwill [Note 7]		884,077			-
Unrealized currency exchange (gain) loss		(5,337	)		11,736
Non-cash interest expense and amortization of finance charges		15,521			14,197
Unrealized loss (gain) on risk management contracts [Note 20]		37,904			(185,921	)
Future income tax expense (recovery)		(28,035	)		108,560
Unit based compensation recovery		(5,212	)		(1,577	)
Employee benefit obligation		(1,157	)		(1,618	)
Other non-cash items		58			(5	)
Settlement of asset retirement obligations [Note 10]		(14,270	)		(11,418	)
Change in non-cash working capital		(1,892	)		(9,897	)
		473,602			655,887

Financing Activities
Issue of Trust Units, net of issue costs		719,504			-
Issue of convertible debentures, net of issue costs [Note 13]		-			239,498
Bank repayments [Note 11]		(810,704	)		(52,413	)
Financing costs		(3,300	)		(228	)
Cash distributions		(121,053	)		(410,678	)
Change in non-cash working capital		(47,893	)		4,098
		(263,446	)		(219,723	)

Investing Activities
Additions to property, plant and equipment		(230,151	)		(327,474	)
Business acquisitions		-			(36,756	)
Property acquisitions		(2,635	)		(138,493	)
Property dispositions		64,751			46,476
Change in non-cash working capital		(41,583	)		24,274
		(209,618	)		(431,973	)

Change in cash and cash equivalents		538			4,191

Effect of exchange rate changes on cash		(538	)		(4,191	)

Cash and cash equivalents, beginning of year		-			-

Cash and cash equivalents, end of year	$	-		$	-

Interest paid	$	87,765		$	115,209
Large corporation tax and other tax (received) paid, net	$	(509	)	$	(81	)

See accompanying notes to these consolidated financial statements.

F-38

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2009 and 2008
(tabular amounts in thousands of Canadian dollars, except Trust Unit, and per Trust Unit amounts)

1.	Nature of Operations and Structure of the 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”), a wholly owned subsidiary of subsidiary Korea National Oil Corporation, purchased all of the issued and outstanding Trust Units of the Trust.

	The business of the Trust is carried on by Harvest Operations and other operating subsidiaries of the Trust, including North Atlantic Refining Limited Partnership. The activities of Harvest Operations and the Trust’s subsidiaries are financed through interest bearing notes from the Trust, net profit interests issued to the Trust, and third party debt such as bank debt and the 7^7/8% Senior Notes. The net profit interests are determined pursuant to the terms of each respective net profit interest agreement. The Trust is entitled to net profit interests equal to the amount by which 99% of the gross proceeds from the sale of production from petroleum and natural gas properties exceed 99% of certain deductible expenditures. Under the terms of the net profits interest agreements, deductible expenditures may include discretionary amounts to fund capital expenditures, to repay third party debt and to provide for working capital required to carry out the operations of the operating subsidiaries.

	Harvest is an integrated energy trust with petroleum and natural gas operations focused on the operation and further development of assets in western Canada (“Upstream operations”) and a refining and marketing business focused on the safe operation of a medium gravity sour crude hydrocracking refinery and a retail and wholesale petroleum marketing business both located in the Province of Newfoundland and Labrador (“Downstream operations”).

	References to “Harvest” refer to the Trust on a consolidated basis. References to “North Atlantic” refer to Harvest Refining General Partnership and its subsidiaries, all of which are 100% owned by Harvest.

2.	Significant Accounting Policies

	These financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”).


	*(a)*	*Consolidation*

		These consolidated financial statements include the accounts of Harvest and its subsidiaries. All inter-entity transactions and balances have been eliminated upon consolidation.

	*(b)*	*Use of Estimates*

		The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenues and expenses during the period. Specifically, amounts recorded for depletion, depreciation, amortization and accretion expense, asset retirement obligations, fair value of risk management contracts, employee future benefits, income taxes and amounts used in the impairment tests for intangible assets, goodwill, inventory and property, plant and equipment are based on estimates. These estimates include petroleum and natural gas reserves, future petroleum and natural gas prices, future refined product prices, future interest and currency exchange rates and future costs required to develop those reserves as well as other fair value assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be material.

	*(c)*	*Revenue Recognition*

		Revenues associated with the sale of crude petroleum, natural gas, natural gas liquids and refined products are recognized when title passes to customers and payment has either been received or collection is reasonably certain. Concurrent with the recognition of revenue from the sale of refined products and included in purchased products for resale and processing are associated transportation charges. Revenues for retail services are recorded when the services are provided.

		The sales price of residential home heating fuels and automotive gasoline and diesel within the Province of Newfoundland and Labrador is subject to regulation under the Petroleum Products Act. The Petroleum Products Pricing Commissioner sets the maximum wholesale and retail prices that a wholesaler and a retailer may charge and sets the maximum mark-up between the wholesale price to the retailer and the retail price to the consumer. Prices are set biweekly using a price adjustment formula based on an allowable premium above Platt's with an interruption formula. The full effect of rate regulation is reflected in the product sales revenue as recorded by Harvest.

F-39


	*(d)*	*Inventories*

		Inventories are carried at the lower of cost or net realizable value. The costs of inventory are determined using the weighted average cost method. The valuation of inventory is reviewed at the end of each month. The costs of parts and supplies inventories are determined under the average cost method.

	*(e)*	*Joint Interest and Partnership Accounting*

		The subsidiaries of Harvest conduct substantially all of their petroleum and natural gas production activities through joint interests and through partnerships. The consolidated financial statements reflect only Harvest’s proportionate interest in such activities.

	*(f)*	*Property, Plant, and Equipment*

		Upstream Operations

		Harvest follows the full cost method of accounting for its petroleum and natural gas activities. All costs of acquiring petroleum and natural gas properties, whether productive or unproductive, related development costs, and overhead charges directly related to these activities, are capitalized and accumulated in one cost centre. Maintenance and repair costs that do not extend or enhance the recoverable reserves are charged against income.

		Proceeds from the sale of petroleum and natural gas properties are applied against capital costs. Gains and losses are not recognized on the disposition of petroleum and natural gas properties unless that disposition would alter the rate of depletion and depreciation by 20% or more.

		Provision for depletion and depreciation of petroleum and natural gas assets is calculated using the unit-of- production method, based on proved reserves net of royalties as evaluated by independent petroleum engineers. The cost basis used for the depletion and depreciation provision is the capitalized costs of petroleum and natural gas assets including undeveloped property plus the estimated future development costs of proved undeveloped reserves. Reserves are converted to equivalent units on the basis of six thousand cubic feet of natural gas to one barrel of petroleum, reflecting the approximate relative energy content.

		Harvest places a limit on the aggregate carrying amount of property, plant and equipment associated with petroleum and natural gas activities which may be amortized to depletion and depreciation in future periods. Impairment is recognized when the carrying amount of the petroleum and natural gas assets exceeds the sum of the undiscounted future cash flows expected from the proved reserves.

		To recognize impairment, Harvest would then measure the amount of impairment by comparing the carrying amounts of the petroleum and natural gas assets to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves using the risk-free discount rate. Any excess carrying amount above the net present value of Harvest’s future cash flows would be a permanent impairment and reflected as a charge to net income for the period.

		Cash flows are calculated based on future price estimates, adjusted for Harvest’s contractual arrangements related to pricing and quality differentials.

		The cost of unproved properties is excluded from the impairment test calculation described above and subject to a separate impairment test. An impairment of unproved properties is recognized when the cost base exceeds the fair value determined by a reference to market prices, historical experience or a third party independent evaluator.

		Downstream Operations

		Property, plant and equipment related to the refining assets are recorded at cost. Depreciation of recorded cost less salvage value is provided on a straight-line basis over the estimated useful life of the assets as set out below. Any gains or losses on disposal of individual assets are recognized in the year of disposal.

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	Asset	Period

	Refining and production plant:
	Processing equipment	5 – 25 years
	Structures	15 – 20 years
	Catalysts	2 – 5 years
	Tugs	25 years
	Vehicles	2 – 5 years
	Office and computer equipment	3 – 5 years


		Maintenance and repair costs, including major maintenance activities, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized.

		Property, plant and equipment related to refining assets are tested for recovery whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Property, plant and equipment related to refining assets are not recoverable if their carrying amounts exceed the sum of the undiscounted cash flows expected to result from their use and eventual disposition. If property, plant and equipment related to refining assets are not recoverable, an impairment loss is recognized in an amount by which their carrying amount exceeds their fair value, with fair value determined based on discounted estimated net cash flows.

	*(g)*	*Goodwill and Other Intangible assets*

		Goodwill is recognized when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of the acquired business. Goodwill is carried at cost less impairment and is not amortized. The carrying amount of goodwill is assessed for impairment annually at year-end or more frequently if events occur that could result in an impairment. The goodwill impairment test is a two step test. In the first step, the carrying amount of the assets and liabilities, including goodwill, is compared to the fair value of the reporting unit. The fair value of a reporting unit is determined by calculating the present value of the expected future cash flows from the reporting unit. If the fair value is less than the carrying amount of the reporting unit, a potential impairment of goodwill may exist requiring the second test to be performed. Impairment is measured by allocating the fair value of the reporting unit, as determined in the first test, over the fair value of the identifiable assets and liabilities. The excess of the fair value of the reporting unit over the fair value of the identifiable assets and liabilities represents the fair value of goodwill. The excess of the book value of goodwill over this implied fair value is then recognized as an impairment and charged to income in the period in which it occurs.

		Intangible assets with determinable useful lives are amortized using the straight line method over the estimated lives of the assets, which range from 5 to 20 years. The amortization methods and estimated service lives are reviewed annually. The carrying amounts of intangible assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Intangibles are not recoverable if their carrying amounts exceed the sum of the undiscounted cash flows expected to result from their use and eventual disposition. If intangibles are not recoverable, an impairment loss is recognized in an amount by which their carrying amount exceeds their fair value, with fair value determined based on discounted estimated net cash flows.

	*(h)*	*Asset Retirement Obligations*

		Harvest recognizes the fair value of any asset retirement obligations as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and normal use of the assets. Harvest uses a credit-adjusted risk free discount rate to estimate this fair value. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted and depreciated using the method described under “Property, Plant and Equipment”. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each subsequent period to reflect the passage of time and changes in the timing and amount of estimated future cash flows underlying the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded.

	*(i)*	*Income Taxes*

		Harvest follows the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the corporate subsidiaries and their respective tax bases, using enacted or substantively enacted income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

F-41

		Under the Income Tax Act (Canada) the Trust and its trust subsidiary entities are taxable only on income that is not distributed or distributable to their Unitholders. As the Trust and its trust subsidiaries distribute all of their taxable income to their Unitholders, neither the Trust nor its trust subsidiaries are currently subject to income tax. In 2007 the Canadian government enacted legislation to apply a tax to distributions from Canadian publicly traded income trusts; however, with the purchase of Harvest by the KNOC on December 22, 2009, Harvest is no longer a publicly traded trust and as a result is no longer subject to a distribution tax beginning in 2011. Therefore, as long as Harvest maintains its current structure and the Trust and its trust subsidiaries continue to distribute all of their taxable income, Harvest and its trust subsidiaries will not be subject to tax.

	*(j)*	*Unit-based Compensation*

		Prior to the acquisition by KNOC, Harvest had a Trust Unit Rights Incentive Plan and the Unit Award Incentive Plan. The compensation expense for these plans was determined by estimating the intrinsic value of the awards at each period end and recognizing the amount in income over the vesting period. After the awards vested, further changes in the intrinsic value were recognized in income in the period of change.

		The intrinsic value is the difference between the market value of the Units and the exercise price of the right in the case of the Trust Unit Rights Incentive Plan, and in the case of the Unit Award Incentive Plan the market value of the Units represents the intrinsic value of the Award. Under the Trust Unit Rights Incentive Plan, the intrinsic value method was used as participants in the plan had the option to either purchase the Units at the exercise price or to receive a cash payment or Trust Unit equivalent, equal to the excess of the market value of the Units over the exercise price. Under the Unit Award Incentive Plan participants had the option upon exercise to receive a cash payment or Trust Unit equivalent, equal to the value of awards outstanding, which was equivalent to the market value of the Units.

	*(l)*	*Employee Future Benefits*

		North Atlantic maintains a defined benefit plan and provides certain post-retirement health care benefits, which cover the majority of its employees and their surviving spouses.

		The cost of providing the defined benefits and other post-retirement benefits is actuarially determined based upon an independent actuarial valuation using management’s best estimates of discount rates, rate of return on plan assets, rate of compensation increase, retirement ages of employees, and expected health care costs. The cost of pensions earned by employees is actuarially determined using the projected benefit method prorated on credited service. Funding of the defined benefit pension plans complies with Canadian federal and provincial regulations, and requires contributions to the plans be made based on independent actuarial valuation. Pension plan assets are measured at fair values with the difference between the fair value of the plan assets and the total employee benefit obligation recorded on the balance sheet. For the purpose of calculating the expected return on assets, the fair value of the plan assets is used.

		The defined benefit plan provides benefits based on length of service and the best five years of the last ten years’ average earnings. There is no recognition or amortization of actuarial gains or losses less than 10% of the greater of the accrued benefit obligations and the fair value of plan assets for the defined benefit pension plans. Actuarial gains and losses over 10% are amortized on a straight-line basis over the average remaining service period of the plan participants. Actuarial gains or losses related to the other post-retirements benefits are recognized in income immediately. Past service costs are amortized on a straight-line basis over the expected average remaining service life of plan participants.

	*(m)*	*Currency Translation*

		Monetary assets and liabilities denominated in a currency other than Canadian dollars are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses denominated in a foreign currency are translated at the monthly average rate of exchange. Translation gains and losses are included in income in the period in which they arise.

		Harvest’s investment in its Downstream operations, which is considered a self-sustaining operation with a U.S. dollar denominated functional currency, is translated using the current rate method. Gains and losses resulting from this translation are recorded in the cumulative translation adjustment in accumulated other comprehensive income.

	*(n)*	*Financial Instruments*

		Harvest classifies cash and price risk management contracts as held-for-trading and measures these instruments at fair value each reporting period. The remainder of Harvest’s financial instruments are measured at amortized cost.

		Transaction costs relating to financial instruments classified as held for trading are expensed in net income in the period that they are incurred. Harvest has elected to add all other transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability to the amount of the financial asset or liability that is recorded on initial recognition.

F-42


3.	New Accounting Policies

	*(a)*	*Current Year Accounting Changes*

	Financial Instruments - Disclosures

	Effective December 31, 2009, Harvest adopted CICA issued amendments to Handbook Section 3862, Financial Instruments – Disclosures. The amendments include enhanced disclosures relating to the fair value of financial instruments and the liquidity risk associated with financial instruments. Section 3862 now requires that all financial instruments measured at fair value be categorized into one of three hierarchy levels. Refer to Note 20 Financial Instruments and Risk Management for enhanced fair value disclosures and liquidity risk disclosures.

	Goodwill and Intangibles

	Effective January 1, 2009, Harvest adopted the new Canadian Institute of Chartered Accountants (“CICA”) accounting standard “Goodwill and Intangible Assets”, Section 3064 which replaced Section 3062 “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs”. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of intangible assets and goodwill subsequent to its initial recognition. The adoption of this standard had no impact on the consolidated financial statements.

	*(b)*	*Future Accounting Changes*

	Business Combinations, Consolidated Financial Statements and Non-Controlling Interests

	The CICA Handbook Section 1582 ‘‘Business Combinations’’ is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting the standard is expected to have a material effect on the way the Company accounts for future business combinations. Entities adopting Section 1582 will also be required to adopt CICA Handbook Sections 1601 ‘‘Consolidated Financial Statements’’ and 1602 ‘‘Non-Controlling Interests’’. These standards will require non-controlling interests to be presented as part of Shareholders’ Equity on the balance sheet. In addition, the income statement of the controlling parent will include 100 per cent of the subsidiary’s results and present the allocation between the controlling and non-controlling interests. These standards will be effective January 1, 2011, with early adoption permitted. The changes resulting from adopting Section 1582 will be applied prospectively and the changes from adopting Sections 1601 and 1602 will be applied retrospectively. Harvest is currently assessing the impact of this standard on our financial position and future results.

	International Financial Reporting Standards (“IFRS”)

	In February 2008, the CICA Accounting Standards Board (“ASB”) announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (“IFRS”) commencing January 1, 2011 which will require comparative IFRS information for the 2010 year end. We will begin reporting under IFRS as of January 1, 2011, but given the current stage of the Company’s IFRS project the full impact of adopting IFRS on Harvest’s financial position and future results can not be determined.


4.	Acquisitions


	(a)	Pegasus Oil & Gas Inc. (“Pegasus”)

		On August 11, 2009, Harvest acquired approximately 93.5% of the issued and outstanding class A shares of Pegasus in exchange for 0.015 units of Harvest for each Pegasus Class A Share and approximately 90.6% of the issued and outstanding class B shares of Pegasus in exchange for 0.15 units of Harvest for each Pegasus Class B Share for total consideration of approximately $4.6 million plus the assumption of $13.9 million of debt. This amount consisted of the issuance of 670,288 Trust Units at an ascribed price of $6.89 per Trust Unit, based on the weighted average trading price of the Harvest Trust Units before and after the announcement date of June 15, 2009. The results of operations of this acquisition have been included in the consolidated financial statements since its acquisition date.

	(b)	Private petroleum and natural gas corporation

		On July 24, 2008, Harvest acquired all of the issued and outstanding shares of a private petroleum and natural gas corporation for $36.8 million in cash net of working capital adjustments and transaction costs. The purchase price was assigned primarily to oil and gas properties. The results of operations of this acquisition have been included in the consolidated financial statements since its acquisition date.

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	(c)	Petroleum and natural gas assets

		On September 8, 2008, Harvest acquired certain petroleum and natural gas assets in exchange for $130.8 million in cash plus an interest in two non-operated properties for total consideration of $136.3 million. The results of operations of these assets have been included in the consolidated financial statements since the acquisition date.


5.	Inventories

		December 31, 2009		December 31, 2008
Petroleum products
Upstream – pipeline fill	$	1,183	$	603
Downstream		76,424		50,311
		77,607		50,914
Parts and supplies		4,177		4,874
Total inventories	$	81,784	$	55,788

During the year ended December 31, 2009, Harvest recognized $2.4 million (2008 – $35.3 million) of inventory impairments and $9.7 million (2008 – nil) of recoveries of inventory impairments in its Downstream operations. At December 31, 2009, inventories held at net realizable value totaled $24.5 million (December 31, 2008 – $37.6 million).

6.	Property, Plant and Equipment

					December 31, 2009									December 31, 2008
		Upstream			Downstream			Total			Upstream			Downstream			Total
Cost	$	4,848,984		$	1,328,727		$	6,177,711		$	4,710,725		$	1,493,039		$	6,203,764
Accumulated depletion
and depreciation		(1,998,004	)		(205,637	)		(2,203,641	)		(1,572,449	)		(162,810	)		(1,735,259	)
Net book value	$	2,850,980		$	1,123,090		$	3,974,070		$	3,138,276		$	1,330,229		$	4,468,505

General and administrative costs of $10.9 million (2008 – $10.0 million) have been capitalized during the year ended December 31, 2009, of which $2.5 million (2008 - nil) relate to the Trust Unit Rights Incentive Plan and the Unit Award Incentive Plan.

All costs, except those associated with major spare parts inventory and assets under construction, are subject to depletion and depreciation at December 31, 2009 including future development costs of $446.8 million (2008 – $489.5 million). Downstream major parts inventory of $6.6 million were excluded from the asset base subject to depreciation at December 31, 2009 (2008 - $7.5 million). Downstream assets under construction of $30.3 million were excluded from the asset base subject to depreciation at December 31, 2009 (2008 - $12.7 million).

The petroleum and natural gas future prices used in the impairment test for petroleum and natural gas assets were obtained from third party engineers and accepted by management. Based on these assumptions, the undiscounted future net revenue from Harvest’s proved reserves exceeded the carrying amount of its petroleum and natural gas assets as at December 31, 2009 and 2008, and therefore no impairment was recorded in either of the periods ended on these dates.

Benchmark prices and U.S.$/Cdn.$ exchange rate assumptions reflected in the impairment test as at December 31, 2009 were as follows:

	WTI Oil⁽¹⁾	Currency	Edmonton Light Crude Oil⁽¹⁾	AECO Gas⁽¹⁾
Year	(US$/barrel)	Exchange Rate	(CDN$ barrel)	(CDN$/MMBtu)
2010	80.00	0.95	83.20	6.05
2011	83.60	0.95	87.00	6.75
2012	87.40	0.95	91.00	7.15
2013	91.30	0.95	95.00	7.45
2014	95.30	0.95	99.20	7.80
Thereafter (escalation)	2%	0%	2%	2%

⁽¹⁾Actual prices used in the impairment test were adjusted for commodity price differentials specific to Harvest.

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7.	Goodwill Impairment

	At June 30, 2009, it was determined that an impairment test of the Downstream reporting unit was required due to expectations of lower future refining margins and the probable deferral of certain future capital expenditures. Harvest completed the two-step process to determine whether the goodwill of the Downstream reporting unit was impaired. The first step of the impairment test involved comparing the fair value of the reporting unit to the carrying value, including goodwill. The fair value was determined using a discounted cash flow approach which incorporated management’s expectations of future throughput and expenses and the forward curve for refined product crack spreads. The fair value of the Downstream reporting unit was below the carrying value, indicating a potential impairment. The second step required the fair value of goodwill be determined by valuing the reporting unit’s net assets in the same manner as allocating a purchase price in a business combination. It was determined that the goodwill associated with the Downstream reporting unit was fully impaired and a pre-tax charge of $206.5 million was recorded in the financial results at June 30, 2009.

	At September 30, 2009, it was determined that the fair value of the Trust, based on the Arrangement Agreement with the KNOC, indicated a potential impairment of the Upstream goodwill. An impairment test for the Upstream reporting unit was conducted and the fair value of the reporting unit was below its carrying value as at September 30, 2009. The fair value of the Upstream goodwill was determined by valuing the reporting unit’s net assets in the same manner as allocating a purchase price in a business combination. It was determined that the goodwill associated with the Upstream reporting unit was fully impaired and a pre-tax charge of $677.6 million was recorded at September 30, 2009.

	Refer to the goodwill table in Note 21 for the change in goodwill during the year ended December 31, 2009.

8.	Intangible Assets

				December 31, 2009							December 31, 2008
				Accumulated			Net book				Accumulated			Net book
		Cost		Amortization			value		Cost		Amortization			value
Engineering drawings	$	93,539	$	(15,005	)	$	78,534	$	108,402	$	(11,969	)	$	96,433
Marketing contracts		6,505		(2,967	)		3,538		7,539		(2,480	)		5,059
Customer lists		3,938		(1,264	)		2,674		4,564		(1,008	)		3,556
Fair value of office lease		931		(875	)		56		931		(652	)		279
Financing costs		3,300		(256	)		3,044		7,300		(6,625	)		675
Total	$	108,213	$	(20,367	)	$	87,846	$	128,736	$	(22,734	)	$	106,002


9.	Accounts Payable and Accrued Liabilities

		December 31, 2009		December 31, 2008
Trade accounts payable	$	71,309	$	62,771
Accrued interest		16,530		17,262
Trust Unit Rights Incentive Plan and Unit Award Incentive Plan [Note 17]		-		3,894
Other accrued liabilities		117,539		126,170
Current portion of asset retirement obligation		11,185		11,321
Total	$	216,563	$	221,418

F-45

10.	Asset Retirement Obligation

	Harvest’s asset retirement obligations result from its net ownership interest in petroleum and natural gas assets including well sites, gathering systems and processing facilities and the estimated costs and timing to reclaim and abandon them. Harvest estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations to be approximately $1,202 million which will be incurred between 2010 and 2059. A credit-adjusted risk-free discount rate of 8% - 10% and inflation rate of approximately 2% were used to calculate the fair value of the asset retirement obligations.

	A reconciliation of the asset retirement obligations is provided below:

		December 31, 2009			December 31, 2008
Balance, beginning of year	$	277,318		$	213,529
Incurred on business acquisition of a private corporation		1,411			1,900
Liabilities incurred		1,351			4,371
Revision of estimates		7,219			49,395
Net liabilities acquired (settled) through acquisition (disposition)		(2,538	)		910
Liabilities settled		(14,270	)		(11,418	)
Accretion expense		24,737			18,631
Balance, end of year⁽¹⁾	$	295,228		$	277,318

(1) Current portion of the asset retirement obligation is included in accounts payable and accrued liabilities [Note 9]

Harvest has undiscounted asset retirement obligations of approximately $14.9 million relating to the refining and marketing assets. The fair value of this obligation cannot be reasonably determined because the assets currently have an indeterminate life.

11.	Bank Loan

	Harvest had a $1.6 billion three year syndicated credit facility with a maturity date of April 30, 2010. With the purchase of Harvest by KNOC on December 22, 2009, the facility was renegotiated and reduced to $600 million concurrent with a $600 million payment made in December. The maturity date remains unchanged at April 30, 2010. At December 31, 2009, Harvest had $428.0 million drawn from the $600 million available under the Credit Facility ($1,226.2 million drawn from the $1.6 billion available at December 31, 2008).

	The Credit Facility is secured by first floating charge over all of the assets of Harvest's operating subsidiaries plus a first mortgage security interest on the refinery assets of North Atlantic. The most restrictive covenants of Harvest’s credit facility include an aggregate limitation of $25 million on financial assistance and/or capital contributions to parties other than those included in the first floating charge, a limitation to carrying on business in countries that are not members of the Organization of Economic Co-operation and Development and a limitation on the payment of distributions to Unitholders in certain circumstances such as an event of default. The Credit Facility requires standby fees on undrawn amounts and interest on amounts borrowed at varying rates depending on Harvest's ratio of secured debt (excluding the 7^7/8% Senior Notes and Convertible Debentures) to its earnings before interest, taxes, depletion, amortization and other non-cash amounts ("EBITDA"). In addition to the availability under this facility being limited by the Borrowing Base Covenant of the 7^7/8% Senior Notes described in Note 12, availability is subject to the following quarterly financial covenants:

	Covenant	As at December 31, 2009
Secured debt to EBITDA	3.0 to 1.0 or less	0.7
Total debt to EBITDA	3.5 to 1.0 or less	2.7
Secured debt to Capitalization	50% or less	11%
Total debt to Capitalization	55% or less	40%

For the year ended December 31, 2009, Harvest’s average interest rate on advances under the Credit Facility was 1.44% (2008 – 4.12%).

F-46

12.	7^7/8% Senior Notes

	On October 14, 2004, Harvest Operations Corp., a wholly owned subsidiary of Harvest, issued US$250 million of 7^7/8% Senior Notes for cash proceeds of $311,951,000. The 7^7/8% Senior Notes are unsecured, require interest payments semi-annually on April 15 and October 15 each year, mature on October 15, 2011 and are unconditionally guaranteed by Harvest and all of its wholly-owned subsidiaries. Prior to maturity, redemptions are permitted as follows:

After October 15, 2009 at 101.969% of the principal amount
After October 15, 2010 at 100% of the principal amount

	The 7^7/8% Senior Notes contains a change of control covenant that requires Harvest Operations Corp. to commence an offer to repurchase the 7^7/8% Senior Notes at a price of 101% of the principal amount plus accrued interest within 30 days of a change of control event, as defined in the indenture. On December 22, 2009, concurrent with the acquisition of 100% of Harvest’s outstanding Trust Units by Korea National Oil Company, the change of control covenant was triggered and on January 20, 2010 Harvest Operations Corp. delivered formal notice to the trustee under the indenture of its offer to purchase all outstanding 7^7/8% Senior Notes; refer to Note 23 for details on the redemptions. There are also covenants restricting, among other things, the sale of assets and the incurrence of additional indebtedness if such issuance would result in an interest coverage ratio, as defined, of less than 2.5 to 1. Notwithstanding the interest coverage ratio limitation, the incurrence of additional indebtedness under the Credit Facilities may be limited by the Borrowing Base Covenant (as described below) and certain other specific circumstances.

	The covenants of the 7^7/8% Senior Notes also restrict Harvest’s incurrence of secured indebtedness to an amount less than 65% of the present value of the future net revenues from its proven petroleum and natural gas reserves discounted at an annual rate of 10% (the “Borrowing Base Covenant”). At December 31, 2009, the Borrowing Base Covenant restricts secured indebtedness to Cdn$1.87 billion (at December 31, 2008 - Cdn$1.91 billion).

	In addition, the covenants of the 7^7/8% Senior Notes restrict Harvest’s ability to pay distributions to Unitholders (net of distributions settled with the delivery of Trust Units) during a quarter to 80% of the prior quarter’s cash flow from operating activities before settlement of asset retirement obligations and changes in non-cash working capital if Harvest’s interest coverage ratio as described in the agreement is greater than 2.5 to 1.0 and its consolidated leverage ratio is lower than 3.0 to 1.0. Notwithstanding, distributions are permitted provided that from the date of issuance of the 7^7/8% Senior Notes, the aggregate distributions do not exceed an amount equal to $40 million plus 100% of the net cash proceeds from the sale of Trust Units plus 80% of the cumulative cash flow from operating activities less distributions paid which as at December 31, 2009, amounted to a carry-forward of approximately Cdn$2.2 billion (Cdn$1.5 billion as at December 31, 2008).

	The fair value of the 7^7/8% Senior Notes at December 31, 2009 was $265.4 million (2008 - $231.4 million).

13.	Convertible Debentures

	Harvest has five series of convertible unsecured subordinated debentures outstanding (the “Convertible Debentures”). Interest on the debentures is payable semi-annually in arrears in equal installments on dates prescribed by each series.

	KNOC’s acquisition of all the outstanding Trust Units constitutes a change of control under the debenture indenture whereby Harvest is required to make an offer to the holders of the debentures to repurchase the debentures for cash consideration equal to 101% of the principal amount plus any accrued and unpaid interest within 30 days; refer to Note 23 for details on the redemptions.

	As a result of KNOC acquiring all of the outstanding Trust Units of Harvest and will be settled with cash upon maturity, the debentures are no longer convertible into Units but investors would receive $10.00 for each unit notionally received based on each series conversion rate. Because every series of debentures carry a conversion price that exceeds $10.00 per unit, it is assumed that no investor would exercise their conversion option.

	The debentures may be redeemed by Harvest at its option in whole or in part prior to their respective redemption dates. The redemption price for the first redemption period is at a price equal to $1,050 per debenture and at $1,025 per debenture during the second redemption period. Any redemption will include accrued and unpaid interest at such time.

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The following is a summary of the five series of convertible debentures:

	Conversion price
Series	/ Trust Unit	Maturity	First redemption period	Second redemption period
6.5% Debentures Due 2010	$ 31.00	Dec. 31, 2010	Jan. 1/09-Dec. 31/09	Jan. 1/10-Dec. 30/10
6.40% Debentures Due 2012⁽¹⁾	$ 46.00	Oct. 31, 2012	Nov. 1/08-Oct. 31/09	Nov. 1/09-Oct. 31/10
7.25% Debentures Due 2013⁽¹⁾	$ 32.20	Sept. 30, 2013	Oct. 1/09-Sept. 30/10	Oct. 1/10-Sept. 30/11
7.25% Debentures Due 2014⁽¹⁾	$ 27.25	Feb. 28, 2014	Mar. 1/10-Feb. 28/11	Mar. 1/11-Feb. 29/12
7.5% Debentures Due 2015⁽¹⁾	$ 27.40	May 31, 2015	Jun. 1/11-May 31/12	Jun. 1/12-May 31/13

⁽¹⁾These series of convertible debentures may also be redeemed by Harvest at a price of $1,000 per debenture after the second redemption period until maturity.

The following table summarizes the face value, carrying amount and fair value of the Convertible Debentures:

				December 31, 2009						December 31, 2008
				Carrying						Carrying
		Face Value		Amount		Fair Value		Face Value		Amount⁽¹	⁾		Fair Value
9% Debentures Due 2009	$	-	$	-	$	-	$	944	$	940		$	984
8% Debentures Due 2009		-		-		-		1,588		1,573			1,540
6.5% Debentures Due 2010		37,062		36,187		37,562		37,062		35,387			29,650
6.40% Debentures Due 2012		174,626		170,667		176,460		174,626		169,455			75,089
7.25% Debentures Due 2013		379,256		362,216		385,703		379,256		358,533			166,835
7.25% Debentures Due 2014		73,222		68,458		74,467		73,222		67,549			36,611
7.5% Debentures Due 2015		250,000		200,342		256,875		250,000		194,322			107,500
	$	914,166	$	837,870	$	931,067	$	916,698	$	827,759		$	418,209

⁽¹⁾Excluding the equity component.

On January 31, 2008, the 10.5% Debenture matured and Harvest elected to settle its obligation by issuing 1,166,593 Trust Units rather than settling in cash.

On April 25, 2008, Harvest issued $250 million principal amount of 7.5% Convertible Debentures for total net proceeds from the issue of $239.5 million. These debentures mature on May 31, 2015 and have a conversion price of $27.40.

On May 31, 2009, the 9% Debenture matured and Harvest elected to settle its obligation by issuing 136,906 Trust Units rather than settling in cash.

On September 30, 2009, the 8% Debenture matured and Harvest elected to settle its obligation by issuing 259,184 Trust Units rather than settling in cash.

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14.

Unitholders' Capital

	*(a)*	*Authorized*

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

	*(b)*	*Number of Units Issued*

	Year ended December 31
	2009	2008
Outstanding, beginning of year	157,200,701	148,291,170
Issued for cash
June 4, 2009 at $7.30 per Trust Unit	17,330,000	-
December 22, 2009 at $10.00 per Trust Unit	60,000,000	-
Issued for corporate acquisition	670,288	-
Convertible debenture conversions
9% Debentures Due 2009	-	2,310
8% Debentures Due 2009	-	8,710
10.5% Debentures Due 2008	-	344
Settlement of convertible debentures
10.5% Debentures Due 2008	-	1,166,593
9% Debentures Due 2009	136,906	-
8% Debentures Due 2009	259,184	-
Distribution reinvestment plan issuance	6,590,755	7,655,414
Exercise of unit appreciation rights and other	80,967	76,160
Outstanding, end of year	242,268,801	157,200,701

In 2005, Harvest implemented a premium distribution reinvestment plan. The premium distribution program enables investors to receive a cash payment equal to 102% of the regular distribution amount. With the acquisition of all the issued and outstanding Trust Units of Harvest by KNOC on December 22, 2009, the distribution reinvestment plan was cancelled.

(c) Per Trust Unit Information

The following tables summarize the net income and Trust Units used in calculating income per Trust Unit:

Net income adjustments		December 31, 2009			December 31, 2008
Net (loss) income, basic	$	(935,634	)	$	212,019
Interest on Convertible Debentures		-			95
Net income, diluted⁽¹⁾⁽³⁾	$	(935,634	)	$	212,114


Weighted average Trust Units adjustments	December 31, 2009	December 31, 2008
Number of Units
Weighted average Trust Units outstanding, basic	173,785,806	152,836,717
Effect of Convertible Debentures	-	69,155
Effect of Employee Unit Incentive Plans	-	200,789
Weighted average Trust Units outstanding, diluted⁽²⁾⁽³⁾	173,785,806	153,106,661


	(1)	Net income, diluted excludes the impact of the conversions of certain of the Convertible Debentures of $69.4 million for the year ended December 31, 2008, as the impact would be anti-dilutive.

	(2)	Weighted average Trust Units outstanding, diluted for the year ended December 31, 2008 does not include the unit impact of 25,915,000 for certain of the Convertible Debentures and nil for the Employee Unit Incentive Plans, as the impact would be anti-dilutive.

	(3)	As a result of the acquisition of all the issued and outstanding Trust Units of Harvest by Korea National Oil Company on December 22, 2009, the debentures are no longer convertible into Trust Units at the option of the holder and the Employee Unit Incentive Plans have been settled; therefore, no adjustment for the effect of Convertible Debentures or the effect of Employee Unit Incentive Plans have been included in the determination of net income, diluted or weighted average Trust Units outstanding, diluted for the year ended December 31, 2009.

F-49

15.	Contributed Surplus

		December 31, 2009		December 31, 2008
Balance, beginning of year	$	6,433	$	-
Settlement of convertible debentures		11		6,433
Elimination of equity component of convertible debentures resulting from the acquisition by KNOC		84,089		-
Future income tax adjustment from change in shareholder status [Note 18]		224,722		-
Balance, end of year	$	315,255	$	6,433


16.	Capital Structure

	Harvest considers its capital structure to comprise its credit facilities, 7^7/8% Senior Notes, Convertible Debentures and unitholders’ equity.

		December 31, 2009		December 31, 2008
Bank debt	$	428,017	$	1,226,228
7^7/8% Senior Notes ⁽¹⁾		262,750		304,500
Principal amount of convertible debentures		914,166		916,698
Total Debt		1,604,933		2,447,426
Unitholders’ equity ⁽²⁾		4,669,559		2,559,229
Total capitalization	$	6,274,492	$	5,006,655

⁽¹⁾ Face value converted at the year end exchange rate. ⁽²⁾ Less equity component of convertible debentures at December 31, 2008.

Harvest evaluates its capital structure using the following non-GAAP financial ratios: bank debt to Twelve Month Trailing EBITDA; secured debt to net present value of our proved petroleum and natural gas reverses discounted at 10%; and total debt to total debt plus unitholders’ equity. These ratios are also included in our externally imposed capital requirements per our credit facility [Note 10], Senior Notes [Note 11] and Convertible Debentures [Note 12]; Harvest was in compliance with all debt covenants at December 31, 2009.

At December 31, 2008 the issuance of Trust Units was limited by the “normal growth guidelines” contained in Bill C-52 issued by the Government of Canada; however, subsequent to the acquisition of all the outstanding Trust Units by KNOC, Harvest is no longer subject to this legislation as it is no longer a publicly traded trust. Harvest’s Trust Unit indenture provides for the issuance of an unlimited number of Trust Units.

17.	Employee Unit Incentive Plans

	Harvest had a Trust Unit Rights Incentive Plan and Unit Award Incentive Plan (“Unit Award Plan”) in place prior to the KNOC acquisition.

	Trust Unit Rights Incentive Plan

	Harvest was authorized to grant non-transferable unit appreciation rights to directors, officers, consultants, employees and other service providers. The initial exercise price of rights granted under the plan was equal to the market price of the Trust Units at the time of grant and the maximum term of each right was five years. The rights vest equally over four years commencing on the first anniversary of the grant date. Any portion of a distribution that did not reduce the exercise price on exercised rights was paid to the holder in a lump sum cash payment after the rights had been exercised.

	Upon the exercise of unit appreciation rights the holder had the sole discretion to elect to receive cash or units. As a result, Harvest recognized a liability on its consolidated balance sheet associated with the rights reserved under the plan. This obligation represented the difference between the market value of the Trust Units and the exercise price of the vested unit rights outstanding under the plan. No obligation has been recorded at December 31, 2009 in accounts payable and accrued liabilities (2008 - $0.3 million) as the 7,233,661 outstanding Trust Unit Rights (2008 – 8,037,446) were settled with the acquisition of Harvest by the KNOC in December 2009.

F-50

The following table summarizes the changes in the Trust Unit Rights Incentive Plan:

	Year ended December 31, 2009				Year ended December 31, 2008
	Unit			Weighted	Unit			Weighted
	Appreciation			Average Exercise	Appreciation			Average Exercise
	Rights			Price	Rights			Price
Outstanding beginning of year	8,037,466		$	21.19	3,823,683		$	30.74
Granted	145,000			7.90	5,244,102			15.68
Exercised	(20,675	)		23.95	(68,675	)		25.67
Forfeited/settled ⁽¹⁾	(8,161,791	)		20.98	(961,644	)		28.80
Outstanding before exercise price reductions	-			-	8,037,466			21.19
Exercise price reductions	-			-	-			(4.45	)
Outstanding, end of year	-			-	8,037,466			16.74
Exercisable before exercise price reductions	-		$	-	85,200		$	22.60
Exercise price reductions	-			-	-			(15.49	)
Exercisable, end of year	-		$	-	85,200		$	7.11

⁽¹⁾Trust Unit Rights of 7,233,661 were settled on December 22, 2009 subsequent to the closing of the acquisition of Harvest by KNOC (2008 – nil).

Unit Award Plan

The Unit Award Plan authorized Harvest to grant awards of Trust Units to directors, officers, employees and consultants of Harvest and its affiliates. Awards vested annually over a two to four year period and, upon vesting, entitled the holder to elect to receive the number of Trust Units subject to the award or the equivalent cash amount. Harvest recognized a liability on its consolidated balance sheet associated with the awards granted under the plan. This obligation represented the fair value of the vested Trust Units granted under the Unit Award Plan. No obligation has been recorded at December 31, 2009 in accounts payable and accrued liabilities (2008 - $3.6 million) as the 629,347 outstanding Unit Awards (2008 – 659,137) were settled with the acquisition of Harvest by the KNOC in December 2009.

Number	December 31, 2009		December 31, 2008

Outstanding, beginning of year	659,137		348,248
Granted	17,732		390,274
Adjusted for distributions	93,523		75,310
Exercised	(101,652	)	(121,776	)
Forfeitures/settled ⁽¹⁾	(668,740	)	(32,919	)
Outstanding, end of year	-		659,137
Exercisable, end of year	-		238,817

⁽¹⁾Unit Awards of 629,347 were settled on December 31, 2009 subsequent to the closing of the acquisition of Harvest by KNOC (2008 – nil).

In conjunction with the KNOC acquisition, each of the Trust Unit Rights Incentive Plan and the Unit Award Plan was cancelled and $8.3 million was required to be paid to directors, officers and employees. The Trust had accrued $5.6 million of costs associated with the plans prior to the cancellation of the plans; on cancellation of the plans the Trust recorded an additional $2.7 million of costs of which $2.2 million has been included in KNOC acquisition related costs in the consolidated statements of income and $0.5 million was included in general and administrative expense.

Total non cash compensation recovery included in G&A is $5.2 million (2008 – recovery of $1.7 million).

18.

Income Taxes

The future income tax (“FIT”) provision reflects the net tax effects of temporary differences between the carrying amounts of assets and liabilities of the corporate subsidiaries in the Trust and their corresponding income tax bases as at that date. Changes in the temporary differences are reflected in FIT expense (recovery). Those changes that arise due to a change in capital structure are charged to equity.

As a result of the acquisition by KNOC on December 22, 2009, Harvest is no longer a public trust and is therefore no longer subject to the SIFT tax legislation that passed in Bill C-52 in June 2007 which made the distributions of publicly traded trusts subject to tax. Management does not intend on having income accumulate in the trust; however, in the event that this occurred, tax free distributions could be made to KNOC Canada to eliminate any taxable income. This results in an effective tax rate of zero for Harvest’s flow through entities which led to the reversal of the remaining FIT liability that was initially booked upon the enactment of the SIFT rates in the second quarter of 2007. A recovery of $224.7 million relating to this reversal was realized through equity during 2009 as it arose from a change in shareholder status, a recovery of $1.1 million was recognized in unitholders’ capital as it related to a capital transaction and a recovery of $28.0 million was credited through the income statement; the additional movement was due to a FIT asset of $14.9 million being recorded on the Pegasus acquisition.

F-51

At the end of 2009, Harvest had a net FIT asset on the balance sheet of $64.8 million comprised of a $91.0 million FIT liability for the Downstream corporate entities and an offsetting FIT asset of $155.8 million for the Upstream corporate entities as compared to a FIT liability of $204.0 million comprised of a $372.6 million provision for our various flow through entities and a $168.6 million net asset for our corporate entities at the end of the prior year.

FIT liability (asset)
Opening FIT Liability, January 1, 2009	203,998
Ending FIT Asset, December 31, 2009	(64,822	)
	(268,820	)
Consists of:
FIT recovery for period ended December 31, 2009	(28,035	)
FIT asset recognized on Pegasus acquisition	(14,991	)
FIT related to SIFT moved to equity	(224,723	)
FIT related to share issuance costs	(1,071	)
Total	(268,820	)

F-52

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

		Year ended December 31
		2009			2008
Income (loss) before taxes	$	(964,178	)	$	320,498
Combined Canadian Federal and Provincial statutory income tax rate		29.23%			29.85%
Computed income tax expense (recovery) at statutory rates		(281,829	)		95,669
Increased expense (recovery) resulting from the following:
Income earned by flow through entities		(48,162	)		(164,571	)
Goodwill write-down		258,416
Transfer of intangibles from trust to corporation		34,199
Temporary differences acquired in excess of fair value limitation					944
Benefit of future tax deductions previously unrecognized		(8,172	)		-
Difference between current and expected tax rates		(57,482	)		113,655
Non-taxable portion of capital (gain) loss		(5,936	)		8,216
Change in estimates of future temporary differences		52,158			54,005
Non-deductible expenses		28,773			642
FIT expense		(28,035	)		108,560

The components of the FIT (asset)/liability are as follows:

		December 31
		2009			2008
Net book value of petroleum and natural gas assets in excess of tax pools	$	214,584		$	498,725
Net book value of intangible assets in excess of tax pools		9,681			16,640
Asset retirement obligation		(52,129	)		(73,899	)
Net unrealized losses related to risk management contracts and currency exchange positions – current		(3,248	)		7,124
Net unrealized losses related to risk management contracts and currency exchange positions – long-term		6,681			1,177
Non-capital loss carry forwards for tax purposes		(239,513	)		(241,660	)
Deferral of taxable income in partnership		681			554
Future employee retirement costs		(1,514	)		(3,135	)
Working capital and other items		(45	)		(1,528	)
FIT liability (asset), net	$	(64,822	)	$	203,998

There are approximately $1.0 billion of temporary differences in the consolidated flow-through entities within the Trust on which FIT has not been recognized.

The expiry dates on the consolidated non-capital losses are as follows:

Year of Expiry
2013	$	9,768
2014		40,411
2023		366
2024		902
2025		97,444
2026		40,698
2027		457,336
2028		353,884
2029		118,424
Consolidated non-capital losses	$	1,119,233

See Commitments and Contingencies [Note 22].

F-53

19.	Employee Future Benefit Plans

	Defined Benefit Plans

	The measurement of the accrued benefit obligation and annual expense for the defined benefit plans requires actuarial calculations and several assumptions. These assumptions, set annually on December 31, are as follows:

	December 31, 2009		December 31, 2008
	Pension	Other Benefit	Pension	Other
	Plans	Plans	Plans	Benefit Plans
Discount rate	5.5%	5.5%	7.25%	7.25 %
Expected long-term rate of return on plan assets	7.0%	-	7.0%	-
Rate of compensation increase	3.5%	-	3.5%	-
Employee contribution of pensionable income	6.0%	-	6.0%	-
Annual rate of increase in covered health care benefits	-	9%	-	10%
Expected average remaining service lifetime (years)	12.2	10.5	11.7	10.7

The assets of the defined benefit plan are invested and maintain the following asset mix:

	December 31, 2009	December 31, 2008
Bonds/fixed income securities	31%	36%
Equity securities	69%	64%

Total cash payments for employee future benefits, consisting of cash contributed by Harvest to the pension plans and other benefit plans was $4.8 million for 2009 (2008 - $3.7 million).

The defined benefit pension plans and post-retirement health care benefits plan were subject to actuarial valuations on December 31, 2009; the next valuation reports are due no later than December 31, 2010.

		December 31, 2009						December 31, 2008

		Pension			Other Benefit			Pension			Other Benefit
		Plans			Plans			Plans			Plans

Employee benefit obligation, beginning of year	$	40,652		$	5,298		$	49,082		$	6,653
Current service costs		1,182			216			3,355			370
Interest		3,084			392			2,673			346
Actuarial losses (gains)		13,317			1,462			(13,086	)		(1,795	)
Benefits paid		(1,759	)		(321	)		(1,372	)		(276	)
Employee benefit obligation, end of year		56,476			7,047			40,652			5,298

Fair value of plan assets, beginning of year		35,132			-			38,903			-
Actual return on plan assets		6,510			-			(7,587	)		-
Employer contributions		4,605			224			3,485			199
Employee contributions		1,582			97			1,703			77
Benefits paid		(1,759	)		(321	)		(1,372	)		(276	)
Fair value of plan assets, end of year		46,070			-			35,132			-
Funded status		(10,406	)		(7,047	)		(5,520	)		(5,298	)
Unamortized balances:
Net actuarial losses		8,059			-			267			-
Carrying amount	$	(2,347	)	$	(7,047	)	$	(5,253	)	$	(5,298	)

		December, 31, 2009		December, 31, 2008
Summary:
Pension plans	$	2,347	$	5,253
Other benefit plans		7,047		5,298
Carrying amount	$	9,394	$	10,551

F-54

Estimated pension and other benefit payments to plan participants which reflect expected future service, expected to be paid from 2010 to 2019, are as follows:

		Pension Plans		Other Benefit Plans

2010	$	1,667	$	382
2011		1,926		543
2012		2,144		655
2013		2,419		786
2014		2,887		943
2015 to 2019		21,663		7,303
Total	$	32,706	$	10,612

The table below shows the components of the net benefit plan expense:

		Year ended December 31, 2009					Year ended December 31, 2008
		Pension Plans			Other Benefit		Pension Plans			Other Benefit
					Plans					Plans
Current service cost	$	1,182		$	216	$	3,355		$	370
Interest costs		3,084			392		2,673			346
Expected return on assets		(2,558	)		-		(2,806	)		-
Amortization of net actuarial (gains)/losses		(8	)		1365		-			(1,872	)
Net benefit plan expense	$	1,700		$	1,973	$	3,222		$	(1,156	)

A 1% percent change in the expected health care cost trend rate would have the following annual impacts as at December 31, 2009:

		1% Increase		1% Decrease
Impact on post-retirement benefit expense	$	1	$	(2	)
Impact on projected benefit obligation		16		(25	)

20.

Financial Instruments and risk management contracts

Financial instruments of Harvest consist of cash, accounts receivable, accounts payable and accrued liabilities, bank loan, risk management contracts, Convertible Debentures and the 7^7/8% Senior Notes. The carrying value and fair value of these financial instruments at December 31, 2009 is disclosed below by financial instrument category, as well as any related gains or losses and interest income or expense for the year ended December 31, 2009:

											Interest			Other
		Carrying						Gains/			Income/			Income/
		Value			Fair Value			(Losses)			(Expense)			(Expense)
Loans and Receivables
Accounts receivable	$	180,839		$	180,839		$	-		$	130	⁽²⁾	$	-
Assets Held for Trading
Net fair value of risk
management contracts		(2,052	)		(2,052	)		(24,899	) ⁽³⁾		-			-
Other Liabilities
Accounts payable⁽⁶⁾		205,378			205,378			-			-			-
Bank loan		428,017			428,017			-			(16,582	) ⁽⁴⁾		(930	)⁽⁴⁾

7^7/8% Senior Notes		259,119	⁽¹⁾		265,378			-			(24,413	) ⁽⁵⁾		-
Convertible
Debentures	$	837,870		$	931,067		$	-		$	(77,914	) ⁽⁵⁾	$	-


	⁽¹⁾	The face value of the 7^7/8% Senior Notes at December 31, 2009 is $262.8 million (U.S. $250 million).

	⁽²⁾	Included in petroleum, natural gas, and refined product sales in the statement of income and comprehensive income.

	⁽³⁾	Included in risk management contracts - realized and unrealized gains (losses) in the statement of income and comprehensive income.

	⁽⁴⁾	Included in interest and other financing charges on short term/long term debt in the statement of income and comprehensive income. The amortization of financing fees related to this liability is included in amortization of deferred finance charges in the statement of cash flows.

	⁽⁵⁾	Included in interest and other financing charges on short term/long term debt in the statement of income and comprehensive income. The non-cash interest expense relating to the accretion of premiums, discounts or transaction costs that are netted against these liabilities are included in non-cash interest in the statement of cash flows.

	⁽⁶⁾	Excludes current portion of asset retirement obligation

F-55

(a) Fair Values

The fair values of the Convertible Debentures and the 7^7/8% Senior Notes are based on quoted market prices as at December 31, 2009. The risk management contracts are recorded on the balance sheet at their fair value; accordingly, there is no difference between fair value and carrying value. The bank loan is recorded at amortized cost, but as there are no transaction costs associated with our bank debt and the financing costs are included in intangible assets, there is no difference between the carrying value and the fair value. Due to the short term nature of accounts receivable, accounts payable, cash distribution payable and the bank loan, their carrying values approximate their fair values.

Harvest’s financial assets and liabilities recorded at fair value have been classified according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

Harvest’s cash and risk management contracts have been assessed on the fair value hierarchy described above; cash is classified as Level 1 and risk management contracts as Level 2.

(b) Risk Management Contracts

At December 31, 2009, the net fair value deficiency reflected on the balance sheet for all the risk management contracts outstanding at that date was approximately $2.1 million (2008 – net fair value asset of $35.9 million), which is presented on the balance sheet as a current liability.

The following is a summary of Harvest’s risk management contracts outstanding, along with their fair value at December 31, 2009:

Quantity	Type of Contract	Term	Average Price	Fair value
Electricity Price Risk Management
25 MWh	Electricity price swap contracts	Jan. 10 – Dec. 10	Cdn $59.22	$ (2,052)

For the year ended December 31, 2009, the total unrealized loss recognized in the consolidated statement of income and comprehensive income on the change in fair value of risk management contracts was $37.9 million (2008 – gain of $185.9 million). The realized gains and losses on all risk management contracts are included in the period in which they are incurred.

(c) Risk Exposure

Harvest is exposed to market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates in the normal course of operations. Harvest is also exposed, to a lesser extent, to credit risk on accounts receivable and counterparties to price risk management contracts and to liquidity risk relating to our debt.

(i.) Credit Risk

Upstream Accounts Receivable

Accounts receivable in our Upstream operations are due from crude oil and natural gas purchasers as well as joint venture partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Concentration of credit risk is mitigated by having a broad customer base, which includes a significant number of companies engaged in joint operations with Harvest. Harvest periodically assesses the financial strength of its crude oil and natural gas purchasers and will adjust its marketing plan to mitigate credit risks. This assessment involves a review of external credit ratings; however, if external ratings are not available, Harvest requests a guarantee from the parent company that does have a credit rating. If this is not possible, Harvest performs an internal credit review based on the purchaser’s past financial performance. The credit risk associated with joint venture partners is mitigated by reviewing the credit history of partners and requiring some partners to provide cash prior to incurring significant capital costs on their behalf. Additionally, most agreements have a provision enabling Harvest to use the proceeds from the sale of production that would otherwise be taken in kind by the partner to offset amounts owing from the partner that is in default. Generally, the only instances of impairment are when a purchaser or partner is facing bankruptcy or extreme financial distress.

F-56

Risk Management Contract Counterparties

Harvest is exposed to credit risk from the counterparties to our risk management contracts. This risk is managed by diversifying Harvest’s risk management portfolio among a number of counterparties limited to lenders in our syndicated credit facilities; we have no history of impairment with these counterparties.

Downstream Accounts Receivable

The Supply and Offtake Agreement entered into in conjunction with the purchase of the Downstream operations exposed Harvest to the credit risk of Vitol Refining S.A. (“Vitol”) as all feedstock purchases and the majority of product sales are made with Vitol under this agreement. Harvest mitigates this risk by requiring that Vitol maintain a minimum B+ credit rating as assessed by Standard and Poor’s Rating Services. If the credit rating falls below this line, additional security is required to be supplied to Harvest. This credit risk is also mitigated by the amounts owing to Vitol for feedstock purchases that are offset against amounts receivable from Vitol for product sales with the balance being net settled. Harvest is in a net payable position with Vitol at December 31, 2009 and accordingly the outstanding balance is included in current trade accounts payable in the liability liquidity table below.

Harvest’s policy is to manage its credit risk by dealing with only financially sound customers, based on an evaluation of the customer’s financial condition. At December 31, 2009, Harvest had an accounts receivable balance with one customer of $23.6 million resulting from the sale of refined product, representing approximately 35% of total Downstream accounts receivable. This customer is an integrated multinational energy company with an AA public credit rating.

Our maximum exposure to credit risk relating to the above classes of financial assets at December 31, 2009 is the carrying value of accounts receivable. The table below provides an analysis of our current financial assets and the age of our past due but not impaired financial assets by type of credit risk.

		Current AR		Overdue AR
						> 30 days,		> 60 days,
				< 30 days		< 60 days		< 90 days		> 90 days
Upstream Accounts Receivable	$	93,735	$	346	$	435	$	265	$	14,065	⁽¹⁾
Risk Management Contract Counterparties		3,357		-		-		-		-
Downstream Accounts Receivable		62,238		2,902		755		374		2,367
Total	$	159,330	$	3,248	$	1,190	$	639	$	16,432

⁽¹⁾Includes a $4.2 million allowance for doubtful accounts.

(ii.) Liquidity Risk

Harvest is exposed to liquidity risk due to our borrowings under our credit facilities, convertible debentures and 7^7/8% Senior Notes. This risk is mitigated by managing the maturity dates on our obligations, complying with covenants and managing our cash flow by entering into price risk management contracts. Additionally, when we enter into price risk management contracts we select counterparties that are also lenders in our syndicated credit facility thereby using the security provided in our credit agreement eliminating the requirement for margin calls and the pledging of collateral.

F-57

The following table provides an analysis of our financial liability maturities based on the remaining terms of our liabilities as at December 31, 2009 and includes the related interest charges:

				>1 year		>4 years
		<1 year		<3 years		<5 years		>5 years		Total
Trade accounts payable and accrued liabilities	$	188,848	$	-	$	-	$	-	$	188,848
Settlement of risk management contract		2,052		-		-		-		2,052
Bank loan and interest		429,646		-		-		-		429,646
Convertible debentures and interest		236,173		211,435		448,992		243,891		1,140,491
7^7/8% Senior Notes and interest		60,272		233,892		-		-		294,164
Pension contributions		4,100		8,448		8,789		4,527		25,864
Asset retirement obligations		12,178		40,071		25,893		1,123,473		1,201,615
Total	$	933,269	$	493,846	$	483,674	$	1,371,891	$	3,282,680

(iii.) Market Risks and Sensitivity Analysis

Harvest is exposed to three types of market risks: interest rate risk, currency exchange rate risk and commodity price risk.

We have performed sensitivity analysis on the three types of market risks identified, assuming that the volatility of the risks over the next quarter will be similar to that experienced in the past year. Harvest has determined that a reasonably possible price or rate variance over the next reporting period for a given risk variable can be estimated by calculating two standard deviations for each three month period in the last year for the relevant daily price/rate settings and using an average of the standard deviation as a reasonable estimate of the expected variance. This variance is then applied to the relevant period end rate or price to determine a reasonable percentage increase and decrease in the risk variable which can then be applied to the outstanding risk exposure at period end. Using 12 months of data, we factor in the seasonality of our business and the price volatility therein.

Interest rate risk

Harvest is exposed to interest rate risk on its bank borrowings as interest rates are determined in relation to floating market rates plus an incremental charge based on our secured debt to EBITDA. Harvest’s Convertible Debentures and 7^7/8% Senior Notes have fixed interest rates and therefore do not have any additional interest rate risk. Harvest manages its interest rate risk by targeting appropriate levels of debt relative to its expected cash flow from operations.

For the year ended December 31, 2009, interest charges on bank loans aggregated to $16.1 million (2008 - $49.6 million), reflecting an effective interest rate of 1.44% (2008 – 4.12%).

At December 31, 2009, if interest rates had decreased by 100% with all other variables held constant, after-tax net income for the year would have been $1.3 million higher, as a result of lower interest expense on variable rate borrowings. If interest rates had increased by 250%, with all other variables held constant, the after-tax net income would have been $3.3 million lower.

Currency exchange rate risk

Harvest is exposed to the risk of changes in the U.S. dollar exchange rate on its U.S. dollar denominated revenues as well as Canadian dollar revenues that are based on a U.S. dollar commodity price. In addition, Harvest’s 7^7/8% Senior Notes are denominated in U.S. dollars (U.S.$250 million) and interest on these notes is payable semi- annually in U.S. dollars and accordingly the principal and any interest payable at the balance sheet date are also subject to currency exchange rate risk. Harvest is also exposed to currency exchange rate risk on its net investment in our downstream operations which is a self sustaining subsidiary that uses a U.S. dollar functional currency. Harvest manages these exchange rate risks by occasionally entering into fixed rate currency exchange contracts on future U.S. dollar payments and U.S. dollar sales receipts.

F-58

At December 31, 2009, if the U.S. dollar strengthened or weakened by 8% relative to the Canadian dollar, the impact on net income and other comprehensive income due to the translation of monetary financial instruments would be as follows:

		Impact on Net Income
U.S. Dollar Exchange Rate - 8% increase	$	(21,057	)
U.S. Dollar Exchange Rate - 8% decrease	$	21,057

As mentioned above, Harvest’s downstream operations operates with a U.S. dollar functional currency which gives rise to currency exchange rate risk on North Atlantic Refining LP’s Canadian dollar denominated monetary assets and liabilities, such as Canadian dollar bank accounts and accounts receivable and payable, as follows:

		Impact on Net Income
Canadian Dollar Exchange Rate - 8% increase	$	(22,978	)
Canadian Dollar Exchange Rate - 8% decrease	$	22,978

Commodity Price Risk

Harvest uses price risk management contracts to manage a portion of its power costs. These contracts are recorded on the balance sheet at their fair value as of the balance sheet date, with changes from the prior period’s fair value reported in net income for the period. These fair values are generally determined as the difference between the stated fixed price of the contract and an expected future power price. Variances in expected future prices expose us to commodity price risk as changes will result in a gain or loss that we will realize on settlement of these contracts. This risk is mitigated by continuously monitoring the effectiveness of these contracts. Harvest uses power hedge contracts as an effective method of reducing its cash power expense.

If the following changes in expected forward prices were applied to the fair value of risk management contracts in place at December 31, 2009, net income would be impacted as follows:

			Impact on Net Income
Contract	% Change		Due to % increase		Due to % decrease
Power	50%	$	-	$	(36	)
Total		$	-	$	(36	)

F-59

21.	Segment Information

	Harvest operates in Canada and has two reportable operating segments, Upstream and Downstream. Harvest’s upstream operations consist of development, production and subsequent sale of petroleum, natural gas and natural gas liquids, while its downstream operations include the purchase of crude oil, the refining of crude oil, the sale of the refined products including a network of retail operations and the supply of refined products to commercial and wholesale customers.


Results of Continuing Operations
		Downstream⁽¹⁾						Upstream⁽¹⁾						Total
		2009			2008			2009			2008			2009			2008
Revenue⁽²⁾	$	2,381,637		$	4,194,595		$	886,308		$	1,543,214		$	3,267,945		$	5,737,809
Royalties		-			-			(128,860	)		(248,445	)		(128,860	)		(248,445	)
Less:
Purchased products for resale and processing		2,015,671			3,850,507			-			-			2,015,671			3,850,507
Operating⁽³⁾		241,911			236,259			258,675			300,890			500,586			537,149
Transportation and marketing		12,009			20,753			14,228			13,490			26,237			34,243
General and administrative		1,593			1,875			36,452			32,868			38,045			34,743
Depletion, depreciation, amortization and accretion		77,288			71,076			450,291			448,735			527,579			519,811
Goodwill impairment⁽⁵⁾		206,465			-			677,612			-			884,077			-
	$	(173,300	)	$	14,125		$	(679,810	)	$	498,786			(853,110	)		512,911

Realized net gains (losses) on risk management contracts														62,803			(200,782	)
Unrealized net losses on risk management contracts														(37,904	)		185,921
Korea National Oil Corporation transaction costs														(18,393	)		-
Interest and other financing charges on short term debt														(8,896	)		(295	)
Interest and other financing charges on long term debt														(110,943	)		(146,375	)
Currency exchange gain (loss)														2,265			(30,882	)
Large corporations tax (expense) recovery and other tax														509			81
Future income tax (expense) recovery														28,035			(108,560	)
Net (loss) income													$	(935,634	)	$	212,019

Total Assets⁽⁴⁾	$	1,362,941		$	1,775,688		$	3,041,971		$	3,933,632		$	4,404,912		$	5,745,407

Capital Expenditures
Development and other activity	$	43,875		$	56,162		$	186,276		$	271,312		$	230,151		$	327,474
Business acquisitions		-			-			-			36,756			-			36,756
Property acquisitions		-			-			2,635			138,493			2,635			138,493
Property dispositions		-			-			(64,751	)		(46,476	)		(64,751	)		(46,476	)
Total expenditures	$	43,875		$	56,162		$	124,160		$	400,085		$	168,035		$	456,247

Property, plant and equipment
Cost	$	1,328,727		$	1,493,039		$	4,848,984		$	4,710,725		$	6,177,711		$	6,203,764
Less: Accumulated depletion, depreciation, and amortization		(205,637	)		(162,810	)		(1,998,004	)		(1,572,449	)		(2,203,641	)		(1,735,259	)
Net book value	$	1,123,090		$	1,330,229		$	2,850,980		$	3,138,276		$	3,974,070		$	4,468,505

Goodwill⁽⁵⁾
Beginning of year	$	216,229		$	175,984		$	677,612		$	676,794		$	893,841		$	852,778
Addition (reduction) to goodwill		(9,764	)		40,246			-			817			(9,764	)		41,063
Impairment of goodwill		(206,465	)		-			(677,612	)		-			(884,077	)		-
End of year	$	-		$	216,230		$	-		$	677,611		$	-		$	893,841

	⁽¹⁾	Accounting policies for segments are the same as those described in the Significant Accounting Policies.

	⁽²⁾	Of the total Downstream revenue for the year ended December 31, 2009, two customers represent sales of $1,459.7 million and $391.1 million respectively (2008 - $2,818.1 million and $592.0 million). No other single customer within either division represents greater than 10% of Harvest’s total revenue.

	⁽³⁾	Downstream operating expenses for the period ended December 31, 2009 include $47.5 million of turnaround and catalyst costs (2008 - $5.6 million).

	⁽⁴⁾	Total Assets on a consolidated basis includes nil (2008 - $36.1 million) relating to the fair value of risk management contracts.

	⁽⁵⁾	A goodwill impairment charge of $206.5 million for the Downstream segment was recognized at June 30, 2009 and of $677.6 million was recognized for the Upstream segment at September 30, 2009 (see Note 7).

	⁽⁶⁾	There is no intersegment activity.

F-60

22.	Commitments and Contingencies

	From time to time, Harvest is involved in litigation or has claims brought against it in the normal course of business operations. Management of Harvest is not currently aware of any claims or actions that would materially affect Harvest’s reported financial position or results from operations. In the normal course of operations, management may also enter into certain types of contracts that require Harvest to indemnify parties against possible third party claims, particularly when these contracts relate to purchase and sale agreements. The terms of such contracts vary and generally a maximum is not explicitly stated; as such the overall maximum amount of the obligations cannot be reasonably estimated. Management does not believe payments, if any, related to such contracts would have a material effect on Harvest’s reported financial position or results from operations.

	The following are the significant commitments and contingencies at December 31, 2009:


	(a)	North Atlantic has a Supply and Offtake Agreement with Vitol Refining S.A. (“Vitol”) which was revised effective November 1, 2009 for a primary term of two years after which the agreement will revert to evergreen. This agreement continues to provide that the ownership of substantially all crude oil feedstock and refined product inventory at the refinery be retained by Vitol and that Vitol will be granted the right and obligation to provide crude oil feedstock for delivery to the refinery, as well as the right and obligation to purchase substantially all refined products produced by the refinery. The revised terms also include the marketing of high sulphur fuel oil inventories which, along with other amendments, will increase the amount of working capital financing provided by Vitol. At December 31, 2009, North Atlantic had commitments totaling approximately $582.0 million (2008 - $319.7 million) in respect of future crude oil feedstock purchases and related transportation from Vitol.

	(b)	North Atlantic has an environmental agreement with the Province of Newfoundland and Labrador, Canada, committing to programs that reduce the environmental impact of the refinery over time. Initiatives include a schedule of activities to be undertaken with regard to improvements in areas such as emissions, waste water treatment, terrestrial effects, and other matters. In accordance with the agreement, certain projects have been completed and others have been scheduled. Costs relating to certain activities scheduled to be undertaken over the next two years are estimated to be approximately $3.4 million and are included in the table below; costs cannot yet be estimated for the remaining projects.

	(c)	North Atlantic has been named a defendant in The State of New Hampshire versus Amerada Hess Corp. et al, one of more than 100 methyl tertiary butyl ether ("MTBE") U.S. product liability litigation cases that have been consolidated for pre-trial purposes in this matter. The plaintiffs seek relief for alleged contamination of ground water from the various defendants' use of the gasoline additive MTBE. Although the plaintiffs have not made a particular monetary demand, they are asserting collective and joint liability against all defendants. All consolidated lawsuits are at a preliminary stage and, accordingly, it is too early in the legal process to reach any conclusion regarding the ability of the State of New Hampshire to properly assert jurisdiction over North Atlantic in the lawsuit or to reach any conclusions regarding the substance of the plaintiffs' claims. Accordingly, the evaluation of the risk of liability to North Atlantic is not determinable at this time and no amounts are accrued in the consolidated financial statements in respect of this matter. Harvest is indemnified by Vitol Group B.V. in respect of this contingent liability.

	(d)	Suncor Energy (formerly Petro-Canada), a former owner of the North Atlantic refinery, holds certain contractual rights in relation to production at the refinery, namely:


	i.	a right to share, subject to a maximum limit, in the profits of the sale of any refined product, refined at the refinery, sold in Canada, exclusive of the province of Newfoundland and Labrador;

	ii.	a right of first refusal to any refinery and/or terminaling capacity in excess of North Atlantic’s requirements;

	iii.	a right to participate in any venture to produce petrochemicals at the refinery; and

	iv.	the rights in paragraphs (i) and (ii) above continue for a period of 25 years from December 1, 1986, while the rights in paragraph (iii) continue until amended by the parties.


	(f)	Canada Revenue Agency Assessment

		In January 2009, Canada Revenue Agency issued a Notice of Reassessment to Harvest Energy Trust in respect of its 2002 through 2004 taxation years claiming past taxes, interest and penalties totaling $6.2 million. The CRA has adjusted Harvest Energy Trust’s taxable income to include their net profits interest royalty income on an accrual basis whereas the tax returns had reported this revenue on a cash basis. A Notice of Objection has been filed with CRA requesting the adjustments to an accrual basis be reversed. The Harvest Energy Trust 2005 tax return has also been prepared on a cash basis for royalty income with no taxes payable and, if reassessed by CRA on a similar basis, there would have been approximately $40 million of taxes owing. The Harvest Energy Trust 2006 tax return has been prepared on an accrual basis including incremental payments required to align the prior year’s cash basis of reporting with no taxes payable. Management along with our legal advisors believe the CRA has not properly applied the provisions of the Income Tax Act (Canada) that entitle income from a royalty to be included in taxable income on a cash basis and that the dispute will be resolved with no taxes payable by Harvest Energy Trust. Harvest has filed a Notice of Objection with the CRA and filed a Notice of Appeal with the Tax Court. The CRA has advised that they will file their Reply/Statement of Defense shortly and Harvest has now scheduled examinations for discovery for April 2010.

F-61

The following is a summary of Harvest’s contractual obligations and commitments as at December 31, 2009:

Payments Due by Period
	2010	2011	2012	2013	2014	Thereafter	Total
Debt repayments ⁽¹⁾	650,687	220,254	106,796	330,548	60,050	236,599	1,604,934
Debt interest payments⁽²⁾	75,404	66,537	51,740	39,957	18,437	7,292	259,367
Capital commitments⁽³⁾	19,173	1,817	-	-	-	-	20,990
Operating leases⁽⁴⁾	6,506	7,475	6,854	6,205	6,126	1,159	34,325
Pension contributions⁽⁵⁾	4,100	4,182	4,266	4,351	4,438	4,527	25,864
Transportation agreements⁽⁶⁾	3,131	1,694	631	205	-	-	5,661
Feedstock commitments⁽⁷⁾	582,050	-	-	-	-	-	582,050
Contractual obligations	1,341,051	301,959	170,287	381,266	89,051	249,577	2,533,191


	⁽¹⁾	Included in the 2010 period is the principal amount of convertible debentures and 7^7/8% Senior Notes redeemed subsequent to year end [see note 23].

	⁽²⁾	Interest determined on bank loan balance and rate effective at year end and by using the year end U.S. dollar exchange rate for the Senior Notes.

	⁽³⁾	Relating to drilling contracts, AFE commitments, equipment rental contracts and environmental capital projects.

	⁽⁴⁾	Relating to building and automobile leases.

	⁽⁵⁾	Relating to expected contributions for employee benefit plans [see Note 19].

	⁽⁶⁾	Relating to oil and natural gas pipeline transportation agreements.

	⁽⁷⁾	Relating to crude oil feedstock purchases and related transportation costs [see Note 22(a) above].


23.	Subsequent Events

	Between January 1, 2010 and March 3, 2010, an additional $54.4 million was committed to the purchase of feedstock inventory under the Supply and Offtake Agreement held with Vitol Refining S.A. [see table in Note 22].

	On January 7, 2010 the Downstream operations experienced a fire at the refinery in the conversion section of the operating units. As a result, this section of the refinery was shut-down for assessment and repairs. Subsequent to the fire, the remaining operating units were also shut-down for other repairs and economic reasons. The current assessment of the cost of repairs from the fire is approximately $7.0 million with an estimated downtime of six to eight weeks.

	On January 20, 2010, Harvest made an offer to purchase 100% of the outstanding Convertible Debentures for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest in accordance with the “change of control” provisions included within the indenture pursuant to which the Convertible Debentures were issued. The expiry date of each offer is as follows:

Series	Face Value at	Carrying Value at	Expiry Date of offer:
	December 31, 2009	December 31, 2009
6.5% Debentures due 2010	37,062	36,187	March 4, 2010
6.4% Debentures due 2012	174,626	170,667	February 11, 2010
7.25% Debentures due 2013	379,256	362,216	March 4, 2010
7.25% Debentures due 2014	73,222	68,458	February 25, 2010
7.5% Debentures due 2015	250,000	200,342	February 25, 2010
	914,166	837,870

As at March 4th all of the offers have expired and the following redemptions have been made:

6.5% Debentures due 2010 – $13.3 million principal amount tendered leaving a principal balance of $23.8 million outstanding
6.4% Debenture due 2012 – $67.8 million principal amount tendered leaving a principal balance of $106.8 million outstanding

F-62

7.25% Debentures due 2013 – $48.7 million principal amount tendered leaving a principal balance of $330.5 million outstanding
7.25% Debentures due 2014 – $13.2 million principal amount tendered leaving a principal balance of $60.1 million outstanding
7.5% Debentures due 2015 – $13.4 million principal amount tendered leaving a principal balance of $236.6 million outstanding

	On January 20, 2010, Harvest made an offer to purchase 100% of the outstanding 7^7/8% Senior Notes for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest in accordance with the “change of control” provisions included within the indenture pursuant to which the 7^7/8% Senior Notes were issued. On February 16, 2010, the offer relating to the 7^7/8% Senior Notes expired and US$40.4 million principal amount was tendered, leaving a principal balance of US$209.6 million outstanding.

	On January 29, 2010 Harvest issued 46,567,852 Trust Units to Korea National Oil Corporation at $10.00 per Unit. The total proceeds of $465.7 million were used to repay the credit facility and to establish funding for potential convertible debenture or 7^7/8% Senior Note redemptions under the “change of control” provisions included within the relevant indentures.

	In December 2009 Harvest signed a conditional letter of intent to purchase certain petroleum and natural gas assets in exchange for $31.0 million. The letter of intent is subject to certain conditions, including approval by Harvest’s Board of Directors which was received in January 2010. The acquisition is not expected to close until mid March; upon completion of this purchase, the production from these properties will be included in Harvest’s results.

24.	Comparatives

	Certain comparative figures have been reclassified to conform to the current year’s presentation.

F-63

KPMG LLP
Chartered Accountants	Telephone	(403) 691-8000
2700 205 - 5th Avenue SW	Telefax	(403) 691-8008
Calgary AB T2P 4B9	Internet	www.kpmg.ca

AUDITORS’ REPORT ON RECONCILIATION TO UNITED STATES GAAP

To the Board of Directors of Harvest Operations Corporation, Administrator of Harvest Energy Trust

On March 4, 2010, we reported on the consolidated balance sheets of Harvest Energy Trust as at December 31, 2009 and 2008 and the consolidated statements of income (loss) and comprehensive income (loss), unitholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2009, which are included in the annual report on Form 20-F. On March 2, 2009, we reported on the consolidated balance sheets of Harvest Energy Trust as at December 31, 2008 and 2007 and the consolidated statements of income (loss) and comprehensive income (loss), unitholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2008, which are included in the annual report on Form 20-F. In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related supplemental note entitled “Reconciliation to United States GAAP” as included in Form 20-F. This supplemental note is the responsibility of the Trust's management. Our responsibility is to express an opinion on this supplemental note based on our audits.

In our opinion, such supplemental note, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Chartered Accountants
Calgary, Canada

April 29, 2010

KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG
network of independent member firms affiliated with KPMG International, a Swiss cooperative.
KPMG Canada provides services to KPMG LLP.

F-64

Reconciliation of the Consolidated Financial Statements to U.S. GAAP

Harvest Energy Trust’s consolidated financial statements have been prepared in accordance with Canadian GAAP which, in most respects, conforms to accounting principles generally accepted in the United States (“U.S. GAAP”). Any differences in accounting principles as they have been applied to the accompanying consolidated financial statements are not material except as described below. Items required for financial disclosure under U.S. GAAP may be different from disclosure standards under Canadian GAAP; any such differences are not reflected here.

The application of U.S. GAAP would have the following effects on net income (loss) as reported:

		Years Ended December 31
(Thousands of Canadian dollars, except per Trust Unit amounts)		2009			2008			2007

Net income (loss) under Canadian GAAP	$	(935,634	)	$	212,019		$	(25,676	)

Adjustments
Write-down of property, plant and equipment ^(a)		-			(1,725,000	)		-
Depletion, depreciation, amortization and accretion ^(b)		249,767			38,614			78,180
Non-cash interest expense on convertible debentures ^(d)		13,612			10,688			6,371
Non-cash interest expense on senior notes ^(f)		1,992			1,397			842
Amortization of deferred financing charges ^(d)(f)		(5,415	)		(4,715	)		(3,471	)
Currency exchange (loss) gain on senior notes ^(f)		(628	)		589			1,720
Currency exchange gain on unit distribution ^(g)		1,788			11,543			10,045
Non-cash general and administrative expenses ^(c)		(419	)		(844	)		(443	)
Gain on acquisition⁽ⁱ⁾		9,117			-			-
Future income tax (expense) recovery ^(a)		23,914			112,372			91,626
Net income (loss) under U.S. GAAP		(641,906	)		(1,343,337	)		159,194

Other comprehensive income (loss)
Net change in cumulative translation adjustment ^(g)		(173,846	)		273,149			(253,677	)
Employee future benefits – actuarial gain (loss) ^(h)		(7,791	)		4,395			(4,339	)
Comprehensive loss	$	(823,543	)		(1,065,793	)		(98,822	)

Basic
Net income (loss) per Trust Unit under U.S. GAAP	$	(3.69	)		(8.79	)		1.15

Diluted
Net income (loss) per Trust Unit under U.S. GAAP	$	(3.69	)		(8.79	)		1.15

Statement of Accumulated Income
Balance, beginning of year – U.S. GAAP		816,952			564,390			33,880
Net income (loss) – U.S. GAAP		(641,906	)		(1,343,337	)		159,194
Change in redemption value of Trust Units ^(e)		(87,816	)		1,595,899			371,316
Balance, end of year – U.S. GAAP		87,230			816,952			564,390

Accumulated other comprehensive income (loss)
Balance, beginning of year – U.S. GAAP		67,114			(210,430	)		47,586
Other comprehensive income (loss) ^(g)(h)		(181,637	)		277,544			(258,016	)
Balance, end of year – U.S. GAAP		(114,523	)		67,114			(210,430	)

F-65

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

		December 31, 2009						December 31, 2008
		Canadian			U.S.			Canadian		U.S.
		GAAP			GAAP			GAAP		GAAP

Assets
Property, plant and equipment ^(a)(b)	$	3,974,070		$	2,022,854		$	4,468,505	$	2,255,407
Deferred charges ^(d)(f)	$	-		$	22,143		$	-	$	28,740
Non current benefit plan assets ^(h)	$	-		$	576		$	-	$	466
Future income tax ^(a)	$	64,822		$	64,822		$	-	$	-

Liabilities
Accounts payable and accrued liabilities ^(c)	$	216,563		$	216,563		$	221,418	$	209,474
Current portion of convertible debentures ^(d)	$	172,053		$	176,163		$	2,513	$	2,532
Current other benefit plan liability ^(h)	$	-		$	246		$	-	$	223
Current portion of 7 ^7/8% Senior notes ^(f)	$	41,909		$	43,532		$	-	$	-
Non current portion of 7 ^7/8% Senior notes ^(f)	$	217,210		$	218,284		$	298,210	$	303,453
Non current portion of convertible debentures ^(d)	$	665,817		$	741,065		$	825,246	$	918,197
Non current benefit plan liability ^(h)	$	9,394		$	17,782		$	10,551	$	11,062
Future income tax ^(a)	$	-		$	-		$	203,998	$	-

Temporary equity ^(e)	$	-		$	2,422,133		$	-	$	1,562,806

Unitholders’ Equity
Unitholders’ capital ^(e)	$	4,669,559		$	-		$	3,897,653	$	-
Equity component of convertible debentures ^(d)	$	-		$	-		$	84,100	$	-
Contributed surplus	$	315,255		$	-		$	6,433	$	-
Additional paid-in capital ^(d)	$	-		$	9,913		$	-	$	9,913
Accumulated income (loss) ^(g)	$	(476,750	)	$	87,230		$	458,884	$	816,952
Accumulated other comprehensive income (loss) ^(g)(h)	$	(84,125	)	$	(114,523	)	$	87,933	$	67,114


(a)	Under Canadian GAAP, Harvest performs an impairment test that limits the capitalized costs of its petroleum and natural gas assets to the discounted estimated future net revenue from proved and probable petroleum and natural gas reserves plus the cost of unproved properties less impairment, determined using estimated future prices and costs. The discount rate used is equal to Harvest’s risk free interest rate.

	Under U.S. GAAP, entities using the full cost method of accounting for petroleum and natural gas activities perform an impairment test on each cost centre using discounted future net revenue, net of applicable income taxes, from proved petroleum and natural gas reserves discounted at 10%. The prices used under the U.S. GAAP impairment test are those that represent an average of the prices on the first day of each month in the prior 12-month period. For 2008, prices used under the U.S. GAAP impairment test were those in effect at the end of 2008. As at December 31, 2009, the application of the ceiling test under U.S. GAAP resulted in no write down (2008 - $1,725 million).

	Prior to 2009, the US GAAP impairment test resulted in the recognition of future income tax recoveries eliminating the future income tax liability. At December 31, 2009, Harvest has a tax basis in excess of the carrying value of net assets resulting in a future tax asset under Canadian and US GAAP; for US GAAP purposes, there still remains a valuation allowance on future tax assets in excess of the Canadian future tax asset. The application of US GAAP resulted in a future income tax recovery of $23.9 million for the year ended December 31, 2009 and a future income tax asset of $64.8 million as at December 31, 2009.

(b)	Under Canadian GAAP, proved reserves are estimated using estimated future prices and costs. These proved reserves form the basis for the depletion calculation.

	Under U.S. GAAP, proved reserves used for the depletion calculation are estimated using constant prices and costs as of the date the estimate of reserves is made. In both the current and prior years there were differences in the depletable base as a result of differences in impairments recorded in accordance with U.S. GAAP compared to Canadian GAAP and in proved reserves under U.S. GAAP and Canadian GAAP and as a result, the differences are realized in the depletion expense.

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(c)	Under Canadian GAAP, the Trust determines compensation expense and the resulting obligation related to its Trust Unit Incentive Plan and Unit Award Plan using the intrinsic value method described in Note 2(j) of the December 31, 2009 consolidated financial statements. Under U.S. GAAP, Harvest follows ASC 718 - “Stock Compensation” using the modified prospective approach. Under ASC 718, expenses and obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting and are revalued at each period end. As a result, general and administrative expense is higher under U.S. GAAP by $0.4 million for the year ended December 31, 2009 (2008 - $0.8 million); the cumulative effect of this difference in accounts payable and accrued liabilities is eliminated as the Plans were settled as a result of Korea National Oil Company acquiring all of the outstanding Trust Units of Harvest at on December 22, 2009.

	To the extent compensation costs relates to employees directly involved in natural gas and crude oil exploration and development activities, such amounts are capitalized to property, plant and equipment. Amounts not capitalized are recognized as administrative expenses.

(d)	Under Canadian GAAP, Harvest’s Convertible Debentures are classified as debt with a portion, representing the value associated with the conversion feature, being allocated to equity under Canadian GAAP. Issue costs related to the debentures are netted against each respective debt and equity component. In addition, under Canadian GAAP a non-cash interest expense representing the effective yield of the debt component and the amortization of the issue costs is recorded in the consolidated statements of income with a corresponding credit to the Convertible Debenture liability balance to accrete that balance to the full principal due on maturity. As a result of Korea National Oil Company acquiring all of the outstanding Trust Units of Harvest at $10.00 per Unit on December 22, 2009, the debentures are no longer convertible into Units but investors would receive $10.00 for each unit notionally received based on each series conversion rate. As a result, under Canadian GAAP the equity component of the convertible debentures has been reclassified to contributed surplus.

	Under U.S. GAAP, the Convertible Debentures are classified as debt in their entirety, and issue costs are recorded as deferred charges. To the extent that a portion of the issue costs are netted against the respective debt and equity components of the Convertible Debentures under Canadian GAAP there is a difference in the capitalization and amortization of the related deferred charges under U.S. GAAP. The non-cash interest expense recorded under Canadian GAAP is not be recorded under U.S. GAAP.

	In addition, Convertible Debentures that are assumed in a business combination are recorded at their fair value at the date of the acquisition as part of the cost of the acquired enterprise. Under U.S. GAAP, if the conversion feature is in-the-money at the acquisition date (a beneficial conversion feature), the feature should be recognized and measured by allocating a portion of the proceeds equal to the intrinsic value of that feature to additional paid-in capital. Where the debenture has a stated redemption date, the corresponding value is recognized as a discount on the convertible debenture balance and accreted from the date of acquisition to the redemption date.

	U.S. GAAP requires issue costs to be recorded as deferred charges. Under Canadian GAAP, these costs are recorded against the related debt.

(e)	Under Harvest’s Trust Indenture, Trust Units are redeemable at any time on demand by the Unitholder for cash. Under

	U.S. GAAP, the amount included on the consolidated balance sheet for Unitholders’ Equity would be reduced by an amount equal to the redemption value of the Trust Units as at the balance sheet date. The redemption value of the Trust Units is determined with respect to the trading value of the Trust Units as at each balance sheet date, and the amount of the redemption value is classified as temporary equity. Changes, if any, in the redemption value during a period (2009 – $87.8 million; 2008 - $1,596 million) results in a charge to accumulated income. Under Canadian GAAP, such equity instruments are considered to be permanent equity and are presented as Unitholders’ Equity.

(f)	With the adoption of the accounting standards for financial instruments under Canadian GAAP effective January 1, 2007, issue costs are applied against the 7^7/8% Senior Notes balance and accreted into income using the effective interest method. Under U.S. GAAP, these amounts are capitalized as a deferred charge and expensed into income using the effective interest method. There is also a currency exchange impact under U.S. GAAP as the deferred charges and the debt balance of the Senior Notes are denominated in U.S. dollars.

(g)	With the adoption of the accounting standards for financial instruments under Canadian GAAP effective January 1, 2007, the cumulative translation adjustment generated upon translating the consolidated financial statements of Harvest’s Downstream operations denominated in a foreign currency previously recognized as a separate component of equity is now recognized in comprehensive income consistent with the treatment under U.S. GAAP. Additionally, under U.S. GAAP, partnership distributions are required to be translated at the historic foreign currency exchange rate in place at the time of initial paid-in capital and any translation gains or losses are recorded in other comprehensive income. Under Canadian GAAP, it is permissible to translate foreign currency denominated partnership distributions at the historic exchange rate that has been proportionately adjusted for the subsequent periods when income has been earned. The effects of the translation are reflected in net income.

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(h)	At December 31, 2006 the Trust adopted U.S. GAAP ASC 715-60, “Defined Benefit Plans - Other Postretirement”. Under ASC 715-60, the over-funded or under-funded status of our defined benefit postretirement plan are recognized on the balance sheet as an asset or liability and changes in the funded status are recognized through comprehensive income. Canadian GAAP currently does not require the Trust to recognize the funding status of the plan on its balance sheet.

(i)	On August 11, 2009, Harvest closed the acquisition of Pegasus Oil and Gas Inc. as disclosed in Note 4 of the December 31, 2009 consolidated financial statements. Under U.S. GAAP, the total purchase price for the acquisition was $4.2 million as U.S. GAAP requires that the Trust Units offered as consideration be valued at the price as at the transaction close date. Under Canadian GAAP the Trust Unit price is that value as at the announcement date. In addition, transaction costs of $1 million are not permitted to be included in the consideration under U.S. GAAP, and are expensed instead.

	U.S. GAAP also requires that assets and liabilities acquired in a business combination be measured at their fair values as of the date of the acquisition and the excess of the fair value of the acquired net assets over cost be recognized into the statement of income (loss). This is instead of the excess being recognized as “negative goodwill” and allocated to the extent possible to acquired non-monetary assets excluding future income tax assets as required under Canadian GAAP. Under U.S. GAAP, transaction costs are classified in the operating activities section of the consolidated statement of cash flows, whereas under Canadian GAAP this amount has been classified under the investing section of the consolidated statements of cash flows.

	For U.S. GAAP purposes, Harvest has increased property, plant and equipment and reduced the future income tax asset by $11.9 million and $3.2 million respectively, and has charged $1 million for transaction costs and recognized a gain of $9.1 million in the statement of income (loss).

New Financial Accounting Pronouncements

In December 2007, the FASB issued an update to ASC 805, Business Combinations, which applies to all transactions and other events in which one entity obtains control over one or more other businesses. It also broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations; and acquisition related costs will generally be expensed rather than included as part of the basis of the acquisition. The amended guidance also expands required disclosures to improve the ability to evaluate the nature and financial effects of business combinations. The amended guidance became effective for all transactions entered into on or after January 1, 2009. The adoption of this guidance on January 1, 2009 had an effect on Harvest’s consolidated financial statements; refer to note i) for further detail.

As of January 1, 2009, the Trust adopted ASC 810, “Consolidation”. This standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. The standard also changes the way the U.S. GAAP consolidated statement of income (loss) is presented by requiring net income (loss) to include the amounts attributable to both the parent and the non-controlling interest and to disclose these respective amounts. The adoption of this standard did not have an impact on the Trust’s consolidated financial statements.

In June 2009, the FASB issued the Accounting Standards Update (“ASU”) 2009-01, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” This update establishes the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. GAAP effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Codification did not change existing requirements under U.S. GAAP and as a result, did not impact the Trust’s consolidated financial statements.

As of December 31, 2009, the Trust was required to prospectively adopt the new reserves requirements that arise from the completion of the SEC’s project, Modernization of Oil and Gas Reporting. The new rules include provisions that permit the use of new technologies to establish proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Additionally, oil and gas reserves are now reported using an average price based upon the prior 12-month period rather than year-end prices. The new rules and standards were adopted prospectively by the Trust on December 31, 2009 and affected the reserves estimate used in the calculation of the ceiling test and depletion for U.S. GAAP.

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