North Atlantic Refining 424B3 Prospectus supplement

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Filed pursuant to Rule 424(b)(3)
Registration No. 333-182132

PROSPECTUS

Harvest Operations Corp.

6⁷/8% Senior Notes due 2017
(US$500,000,000 aggregate principal amount) and related guarantees which have been registered under the Securities Act of 1933

for

all outstanding 6⁷/8% Senior Notes due 2017
(US$500,000,000 aggregate principal amount) and related guarantees

The Notes and the Guarantees

•: We are offering to exchange US$500,000,000 of our outstanding 6⁷/8% Senior Notes due 2017 and certain related guarantees, which were issued on October 4, 2010 and which we refer to as the initial notes, for a like aggregate amount of our registered 6⁷/8% Senior Notes due 2017 and certain related guarantees, which we refer to as the exchange notes. The exchange notes will be issued under the existing Note Indenture (as defined below) dated as of October 4, 2010.
•: The exchange notes will be guaranteed by all of our existing and future restricted subsidiaries that guarantee the Credit Facility (as defined below) and every future restricted subsidiary that guarantees certain debt.
•: The exchange notes and the guarantees will be our general unsecured senior obligations and will be effectively subordinated to all of our and the guarantors' existing and future secured debt to the extent of the assets securing that secured debt. In addition, the exchange notes will be effectively subordinated to all of the liabilities of our subsidiaries that are not guaranteeing the exchange notes, to the extent of the assets of those subsidiaries.
•: The exchange notes will be redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make-whole redemption premium, plus accrued and unpaid interest to the redemption date. We may also redeem all of the notes at any time in the event that certain changes affecting Canadian withholding taxes occur.

Terms of the exchange offer

•: It will expire at 5:00 p.m., New York City time, on August 1, 2012, unless we extend it.
•: If all the conditions to this exchange offer are satisfied, we will exchange all of our initial notes that are validly tendered and not withdrawn for the exchange notes.
•: You may withdraw your tender of initial notes at any time before the expiration of this exchange offer.
•: The exchange notes that we will issue you in exchange for your initial notes will be substantially identical to your initial notes except that, unlike your initial notes, the exchange notes will have no transfer restrictions or registration rights.
•: The exchange notes that we will issue you in exchange for your initial notes are new securities with no established market for trading.

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

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act of 1933, as amended, which we refer to as the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for initial notes where those initial notes were acquired by that broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the effective date of this registration statement, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

The date of this prospectus is July 3, 2012.

TABLE OF CONTENTS



Presentation of Our Financial Information		i
Non-GAAP Financial Measures		i
Predecessor Presentation		ii
Exchange Rate Data		ii
Note Regarding Reserves Data and Other Oil And Gas Information		iii
Glossary of Certain Terms and Definitions		iv
Prospectus Summary		1
Risk Factors		14
Special Note Regarding Forward-Looking Statements		30
Use of Proceeds		33
Capitalization		34
Selected Historical Financial Information		35
Management's Discussion and Analysis of Financial Condition and Results of Operations		39
Business		74
Management		105
Related Party Transactions		113
Principal Stockholder		114
Description of Other Indebtedness		115
The Exchange Offer		116
Description of Notes		124
Book-Entry, Delivery and Form		147
Federal Income Tax Considerations		167
Plan of Distribution		172
Legal Matters		173
Independent Qualified Reserves Evaluators		173
Experts		173
Available Information		173
Index to Financial Statements		F-1

PRESENTATION OF OUR FINANCIAL INFORMATION

The financial data presented herein for Harvest Operations Corp. and Harvest Energy Trust is from the unaudited and audited consolidated financial statements. The consolidated financial statements of Harvest Operations (as defined below) for 2012, 2011 and 2010 have been prepared in accordance with IFRS (as defined below). The December 31, 2010 consolidated financial statements were initially prepared in accordance with pre-IFRS Canadian GAAP (as defined below), consistent with the prior years and the periods ended December 31, 2009, 2008 and 2007. The consolidated financial information as at and for the year ended December 31, 2010 have been adjusted in accordance with IFRS 1 "First-time Adoption of International Financial Reporting Standards", and therefore the financial information set forth in this prospectus for the year ended December 31, 2010 may differ from information previously published. Harvest adopted IFRS with a transition date of January 1, 2010. For details regarding the adjustments made with respect to the comparative data refer to Note 27 to the annual audited consolidated financial statements contained in this prospectus. The selected historical consolidated financial information presented elsewhere in this prospectus is condensed and may not contain all of the information that readers should consider. This selected financial data should be read in conjunction with the annual audited consolidated financial statements, the notes thereto and the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations." The amounts presented herein for the years 2009, 2008, and 2007 reflect the adjustments made to conform with U.S. GAAP (as defined below).

We present our financial statements in Canadian dollars. In this prospectus, except where otherwise indicated, all dollar amounts are expressed in Canadian dollars. 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.

NON-GAAP FINANCIAL MEASURES

Harvest uses certain financial reporting measures that are commonly used as benchmarks within the petroleum and natural gas industry hereinafter referred to as "non-GAAP" such as: "cash contribution", "operating netbacks", "operating netback prior to/after hedging", "operating income (loss)", "gross margin (loss)", "total debt", "total financial debt", "total capitalization", "EBITDA", "secured debt to annualized EBITDA", "total debt to annualized EBITDA", "secured debt to total capitalization", "total debt to total capitalization" and "interest coverage ratio".

"Operating netbacks" are reported on a per boe basis and used extensively in the Canadian energy sector for comparative purposes. "Operating netbacks" include revenues, operating expenses, transportation and marketing expenses, and realized gains or losses on risk management contracts. "Cash contribution" represents cash from operating activities adjusted to remove the change in non-cash working capital and settlements of decommissioning liabilities; this measure is also used extensively in the Canadian energy sector for comparative purposes, although it is referred to using various different titles. "Gross margin (loss)" 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. "Operating income (loss)" is 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 financial debt", "total capitalization", and "EBITDA" are used to assist management in assessing liquidity and the Corporation's ability to meet financial obligations. "Secured debt to annualized EBITDA", "total debt to annualized EBITDA", "secured debt to total capitalization", "total debt to total capitalization" and "interest coverage ratio" are terms defined in the Credit Facility and the Note Indenture for the purpose of calculation of Harvest's financial covenants. The non-GAAP measures do not have any standardized meaning prescribed by U.S. GAAP, Canadian GAAP or IFRS and may not be comparable to similar measures used by other issuers. The

determination of the non-GAAP measures have been illustrated throughout this prospectus, with reconciliations to IFRS measures and/or account balances, except for EBITDA which is shown below under "Selected Historical Financial Information—Reconciliation of EBITDA."

PREDECESSOR PRESENTATION

On December 22, 2009, KNOC Canada (as defined below) purchased all of the issued and outstanding Trust Units (as defined below) of Harvest Energy Trust. The acquisition of all the issued and outstanding Trust Units resulted in a change of control in which KNOC Canada became the sole unit holder of the Trust (as defined below). 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 KNOC Acquisition (as defined below).

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 prospectus. Accordingly, the financial information presented in this prospectus for the year ended and as at December 31, 2011 and 2010 and any later period, 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.

EXCHANGE RATE DATA

The following table sets forth, the high and low exchange rates between the Canadian dollar and the U.S. dollar for each month during the previous six months, the low and high exchange rates for Canadian dollars based on the Bank of Canada noon rates. Such rates are set forth as U.S. dollars per $1.00. The exchange rate information presented below is based on the Bank of Canada noon rates.



May 2012	1.0164	0.9663
April 2012	1.0197	0.9961
March 2012	1.0153	0.9985
February 2012	1.0136	0.9984
January 2012	1.0014	0.9735
December 2011	0.9896	0.9610

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

		Average

2011			1.0110
2010			0.9709
2009			0.8757
2008			0.9381
2007			0.9304

The exchange rate between the Canadian dollar and the U.S. dollar on June 29, 2012 was US$0.9813.

NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION

In order to facilitate comparability of oil and gas disclosure with that provided by U.S. and other international issuers, the oil and gas information included in this prospectus is disclosed in accordance with U.S. disclosure requirements and practices. Such information may differ from the corresponding information prepared in accordance with Canadian standards pursuant to National Instrument 51-101—Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators ("NI 51-101"), which imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities.

The primary differences between the current U.S. requirements and the NI 51-101 requirements are that the U.S. standards require (i) disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves; (ii) that the reserves and related future net revenue be estimated under existing economic and operating conditions, i.e., historic 12-month average price, whereas NI 51-101 requires disclosure of reserves and related future net revenue using forecast prices and costs; and (iii) that a discount rate of 10% be used when determining the present value of future net revenue to be derived from the reserves. In addition, under U.S. disclosure standards, reserves and production information is required to be disclosed on a net basis (after royalties). The definitions of proved reserves also differ, but according to the Canadian Oil and Gas Evaluation Handbook, the reference source for the definition of proved reserves under NI 51-101, differences in the estimated proved reserves quantities based on constant prices should not be material.

According to the SEC, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. Prices include consideration of future price changes only to the extent provided by contractual arrangements in existence at year-end.

The current U.S. requirements permit, but do not require, the disclosure of probable reserves information. We are voluntarily providing reserves and production information for both proved and probable reserves. The SEC has defined probable reserves as those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.

iii

GLOSSARY OF CERTAIN TERMS AND DEFINITIONS

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.

"6.40% Debentures Due 2012" means the 6.40% convertible unsecured subordinated debentures of Harvest Operations due October 31, 2012.

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

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

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

"7⁷/8% Senior Notes" means the Corporation's 7⁷/8% Senior Notes due 2011.

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

"BlackGold" means the BlackGold oil sands project acquired by the Corporation from KNOC on August 6, 2010, more fully described in Note 26 of the Corporation's audited consolidated financial statements for the year ended December 31, 2011 included in this registration statement.

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

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

"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.

"Credit Facility" means the $800 million revolving credit facility, as amended, provided by a syndicate of lenders to Harvest Operations as more fully described in Note 10 of the Corporation's audited consolidated financial statements for the year ended December 31, 2011 included in this registration statement.

"Debentures" means, collectively, 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 (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 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, the fifth supplemental indenture dated April 25, 2008 in respect of the 7.50% Debentures Due 2015, the sixth supplemental indenture dated April 30, 2010 and the seventh supplemental indenture dated May 1, 2010 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, the second supplemental indenture dated February 3, 2006, the third supplemental indenture dated April 30, 2010 and the fourth supplemental indenture dated May 1, 2010.

"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, predominantly located in the Province of Newfoundland and Labrador.

"EPC" means engineering, procurement and construction.

"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.

"Future Net Revenue" means the estimated net amount to be received with respect to the development and production of reserves computed by deducting, from estimated future revenues, estimated future royalty obligations, costs related to the development and production of reserves and abandonment and reclamation costs (corporate general and administrative expenses and financing costs are not deducted).

"GLJ" means GLJ Petroleum Consultants Ltd., independent oil and natural gas reserves evaluators 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 Operations" means Harvest Operations Corp., a corporation amalgamated under the laws of the Province of Alberta.

"Independent Reserves 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, 2011, 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.

"IFRS" means International Financial Reporting Standards as issued by the International Accounting Standards Board ("IASB").

"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 reserves evaluators 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.

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

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

"Note Indenture" or "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 notes.

"Operating Subsidiaries" means Redearth Partnership (prior to September 30, 2010), Breeze Resources 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.

"Redearth Partnership" means the general partnership formed on August 23, 2002 under the laws of the Province of Alberta. In September 2010 Harvest acquired 100% ownership interest, thereafter, Redearth Partnership was dissolved and Harvest Operations became the owner of all the assets and assumed all of the liabilities of the Redearth Partnership.

"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 Refining Limited.

"Reserves 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, 2011, 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.

"SEC" means the United States Securities and Exchange Commission.

"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. ("Vitol").

"Supply and Offtake Agreement (2011)" or "SOA (2011)" means the supply and offtake agreement dated October 11, 2011 and as amended December 19, 2011 entered into between North Atlantic and Macquarie Energy Canada Ltd. ("MEC").

"Trust" means Harvest Energy Trust.

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

"Trustee" means U.S. Bank National Association in its capacity as trustee under the Note Indenture.

"TSX" means the Toronto Stock Exchange.

"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.

"Viking" means Viking Holdings Inc., an amalgamation predecessor of Harvest Operations.

"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.

vii

The following terms have the following meanings in this registration statement:


/d		Per day
3-D		Three dimensional
AECO		AECO "C" hub price index for Alberta natural gas
API		The measure of the density or gravity of liquid petroleum products
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
bbl		Barrel
bbls		Barrels
EOR		Enhanced oil recovery
GJ		Gigajoule
H2S		Hydrogen sulfide gas
Mbbls		Thousand barrels
Mboe		Thousand barrels of oil equivalent
mcf		Thousand cubic feet
MMboe		Million barrels of oil equivalent
MMcf		Million cubic feet
NGLs		Natural gas liquids
SAGD		Steam-assisted gravity drainage is an enhanced oil recovery technology for producing heavy crude oil and bitumen
WTI		West Texas Intermediate, the reference price in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
$000		Thousands of dollars
$millions		Millions of dollars

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

viii

PROSPECTUS SUMMARY

This summary may not contain all of the information that may be important to you. You should read this prospectus carefully in its entirety before making an investment decision. In particular, you should read the sections entitled "Risk Factors" and "Special Note Regarding Forward-Looking Statements" included elsewhere in this prospectus, as well as the audited consolidated financial statements and notes thereto and related Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this prospectus.

Unless we state otherwise or the context otherwise requires, the terms (i) "we," "us," "our," "Harvest," and the "Corporation," refer to Harvest Operations Corp. and its subsidiaries, (ii) "Harvest Operations" refers to Harvest Operations Corp. and not its subsidiaries and (iii) "Harvest Energy Trust" refers to Harvest Energy Trust and its subsidiaries.

As used in this prospectus, the term "initial notes" refers to the 6⁷/8% Senior Notes due 2017 that were issued on October 4, 2010 in a private offering, and the term "exchange notes" refers to the 6⁷/8% Senior Notes due 2017 offered under this prospectus. The term "notes" refers to the initial notes and the exchange notes, collectively. Certain additional terms used in this prospectus are defined in "Glossary of Certain Terms and Definitions".

Overview

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. 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, 2011, Harvest's gross proved reserves represented approximately 39% of KNOC's gross proved reserves. Additionally, Harvest's crude oil and natural gas production represented 29% of KNOC's consolidated 2011 petroleum and natural gas production.

Harvest is a significant operator in Canada's energy industry offering stakeholders exposure to an integrated structure with Upstream (exploration, development and production of crude oil, bitumen and natural gas) and Downstream (refining and marketing of distillate, gasoline and fuel oil) segments. Harvest's Upstream oil and gas production is complemented by our long-life refining business that focuses on the safe and efficient operation of a medium gravity sour-crude refinery located in the Province of Newfoundland and Labrador and the associated retail and marketing operations.

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.

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. Harvest's Upstream operations are located in the Western Canadian sedimentary basin. Harvest has a high degree of operational control as it is the operator of properties that generate the majority of Harvest's production. The Corporation believes that this "hands on" approach allows it to better manage capital expenditures and accumulate institutional expertise in its operating regions.

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 that is composed of five business segments. The Downstream operations are predominantly 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.

Recent Developments

In 2011, Harvest issued $505.4 million of equity to KNOC to fund the acquisition of assets from Hunt Oil Company of Canada Inc. and Hunt Oil Alberta Inc. (collectively "Hunt"). See "Business—Recent Developments."

On April 29, 2011, Harvest extended the term of the Credit Facility by two years to April 30, 2015. On December 16, 2011, the Credit Facility was further amended to increase the capacity of the facility from $500 million to $800 million. Under the Credit Facility, Harvest and certain subsidiaries (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.

Corporate Structure

Harvest is a wholly owned subsidiary of KNOC. 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 March 31, 2012:

Additional Information

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.

Summary of the Exchange Offer


Exchange Offer		We are offering to exchange US$500,000,000 aggregate principal amount of our exchange notes for a like aggregate principal amount of our initial notes. In order to exchange your initial notes, you must properly tender them and we must accept your tender. We will exchange all outstanding initial notes that are properly tendered and not validly withdrawn.
Expiration Date		This exchange offer will expire at 5:00 p.m., New York City time, on August 1, 2012, unless we decide to extend it.
Conditions to the Exchange Offer		We will complete this exchange offer only if:
		• there is no change in the laws and regulations which would impair our ability to proceed with this exchange offer;
		• there is no change in the current interpretation of the staff of the SEC permitting resales of the exchange notes; and
		• there is no stop order issued by the SEC that would suspend the effectiveness of the registration statement which includes this prospectus or the qualification of the exchange notes under the Trust Indenture Act of 1939.
		Please refer to the section in this prospectus entitled "The Exchange Offer—Conditions to the Exchange Offer."
Procedures for Tendering Initial Notes		To participate in this exchange offer, you must complete, sign and date the letter of transmittal or its facsimile and transmit it, together with your initial notes to be exchanged and all other documents required by the letter of transmittal, to U.S. Bank National Association, as exchange agent, at its address indicated under "The Exchange Offer—Exchange Agent." In the alternative, you can tender your initial notes by book-entry delivery following the procedures described in this prospectus. For more information on tendering your notes, please refer to the section in this prospectus entitled "The Exchange Offer—Procedures for Tendering Initial Notes."
Special Procedures for Beneficial Owners		If you are a beneficial owner of initial notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your initial notes in the exchange offer, you should contact the registered holder promptly and instruct that person to tender on your behalf.
Guaranteed Delivery Procedures		If you wish to tender your initial notes and you cannot get the required documents to the exchange agent on time, you may tender your notes by using the guaranteed delivery procedures described under the section of this prospectus entitled "The Exchange Offer—Procedures for Tendering Initial Notes—Guaranteed Delivery Procedure."


Withdrawal Rights		You may withdraw the tender of your initial notes at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer. To withdraw, you must send a written or facsimile transmission notice of withdrawal to the exchange agent at its address indicated under "The Exchange Offer—Exchange Agent" before 5:00 p.m., New York City time, on the expiration date of the exchange offer.
Acceptance of Initial Notes and Delivery of Exchange Notes		If all the conditions to the completion of this exchange offer are satisfied, we will accept any and all initial notes that are properly tendered in this exchange offer on or before 5:00 p.m., New York City time, on the expiration date. We will return any initial note that we do not accept for exchange to you without expense promptly after the expiration date. We will deliver the exchange notes to you promptly after the expiration date and acceptance of your initial notes for exchange. Please refer to the section in this prospectus entitled "The Exchange Offer—Acceptance of Initial Notes for Exchange; Delivery of Exchange Notes."
Federal Income Tax Considerations Relating to the Exchange Offer		Exchanging your initial notes for exchange notes will not be a taxable event to you for Canadian or United States federal income tax purposes. Please refer to the section of this prospectus entitled "Federal Income Tax Considerations."
Exchange Agent		U.S. Bank National Association is serving as exchange agent in the exchange offer.
Fees and Expenses		We will pay the expenses related to this exchange offer. Please refer to the section of this prospectus entitled "The Exchange Offer—Fees and Expenses."
Use of Proceeds		We will not receive any proceeds from the issuance of the exchange notes. We are making this exchange offer solely to satisfy certain of our obligations under our registration rights agreement entered into with Banc of America Securities LLC, HSBC Securities (USA) Inc., CIBC World Markets Corp., Mitsubishi UFJ Securities (USA) Inc., NBF Securities (USA) Corp., Scotia Capital (USA) Inc. and TD Securities (USA) LLC, which we refer to as the registration rights agreement, in connection with the offering of the initial notes.
Consequences to Holders Who Do Not Participate in the Exchange Offer		If you do not participate in this exchange offer:
		• except as set forth in the next paragraph, you will not necessarily be able to require us to register your initial notes under the Securities Act;
		• you will not be able to resell, offer to resell or otherwise transfer your initial notes unless they are registered under the Securities Act or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, registration under the Securities Act; and


		• the trading market for your initial notes will become more limited to the extent other holders of initial notes participate in the exchange offer.
		You will not be able to require us to register your initial notes under the Securities Act unless:
		• you are prohibited by law or SEC policy from participating in the exchange offer;
		• you may not resell the exchange notes you acquire in the exchange offer to the public without delivering a prospectus and that the prospectus contained in the exchange offer registration statement is not appropriate or available for such resales by you; or
		• you are a broker-dealer and hold initial notes acquired directly from us or one of our affiliates.
		In these cases, the registration rights agreement requires us to file a registration statement for a continuous offering in accordance with Rule 415 under the Securities Act for the benefit of the holders of the initial notes described in this paragraph. We do not currently anticipate that we will register under the Securities Act any notes that remain outstanding after completion of the exchange offer.
		Please refer to the section of this prospectus entitled "The Exchange Offer—Your Failure to Participate in the Exchange Offer Will Have Adverse Consequences."
Resales		It may be possible for you to resell the notes issued in the exchange offer without compliance with the registration and prospectus delivery provisions of the Securities Act, subject to the conditions described under "—Obligations of Broker-Dealers" below.
		To tender your initial notes in this exchange offer and resell the exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act, you must make the following representations:
		• you are authorized to tender the initial notes and to acquire exchange notes, and that we will acquire good and unencumbered title to those initial notes;
		• the exchange notes acquired by you are being acquired in the ordinary course of business;
		• you have no arrangement or understanding with any person to participate in a distribution of the exchange notes and are not participating in, and do not intend to participate in, the distribution of such exchange notes;
		• you are not an "affiliate," as defined in Rule 405 under the Securities Act, of ours, or you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;
		• if you are not a broker-dealer, you are not engaging in, and do not intend to engage in, a distribution of exchange notes; and


		• if you are a broker-dealer, initial notes to be exchanged were acquired by you as a result of market-making or other trading activities and you will deliver a prospectus in connection with any resale, offer to resell or other transfer of such exchange notes.
		Please refer to the sections of this prospectus entitled "The Exchange Offer—Procedure for Tendering Initial Notes—Proper Execution and Delivery of Letters of Transmittal," "Risk Factors—Risks Relating to the Exchange Offer—Some persons who participate in the exchange offer must deliver a prospectus in connection with resales of the exchange notes" and "Plan of Distribution."
Obligations of Broker- Dealers		If you are a broker-dealer (1) who receives exchange notes, you must acknowledge that you will deliver a prospectus in connection with any resales of the exchange notes, (2) who acquired the initial notes as a result of market making or other trading activities, you may use the exchange offer prospectus as supplemented or amended, in connection with resales of the exchange notes, or (3) who acquired the initial notes directly from us in the initial offering and not as a result of market making and trading activities, you must, in the absence of an exemption, comply with the registration and prospectus delivery requirements of the Securities Act in connection with resales of the exchange notes.

Summary of Terms of the Exchange Notes


Issuer		Harvest Operations Corp.
Exchange Notes		Up to US$500 million aggregate principal amount of 6⁷/8% Senior Notes due 2017. The form and terms of the exchange notes are the same as the form and terms of the initial notes except that the issuance of the exchange notes is registered under the Securities Act, the exchange notes will not bear legends restricting their transfer and the exchange notes will not be entitled to registration rights under our registration rights agreement. The exchange notes will evidence the same debt as the initial notes, and both the initial notes and the exchange notes will be governed by the same Note Indenture.
Maturity		October 1, 2017.
Interest Payment Dates		The exchange notes will bear interest at a rate per annum equal to 6⁷/8% payable semi-annually, on April 1 and October 1 of each year, commencing on October 1, 2012.
Ranking		The exchange notes will rank equal in right of payment to all of our existing and future unsecured unsubordinated indebtedness and senior in right of payment to all future subordinated indebtedness, including our outstanding Debentures. The notes will be effectively subordinated to any of our existing and future secured indebtedness to the extent of the value of the assets securing such indebtedness. Additionally, the notes will be effectively subordinated to all liabilities, including trade payables, of any subsidiaries that are not guarantors.
		The exchange note guarantees will rank equal in right of payment with all existing and future unsecured unsubordinated indebtedness of the guarantors. In addition, the exchange note guarantees will be effectively subordinated to all of the guarantors' secured obligations to the extent of the collateral securing such obligations.
		As at March 31, 2012:
		• we had total indebtedness of approximately $1,767 million outstanding on a consolidated basis ($1,759 million net of deferred finance charges), 28.2% of which was represented by the initial notes, including $734.0 million principal amount of subordinated debt;
		• the guarantors guaranteed borrowings under our Credit Facility and the initial notes but had no additional indebtedness outstanding; and
		• on a combined basis, the subsidiaries that are not guaranteeing the notes would have had no indebtedness and other liabilities of $13.9 million.
Optional Redemption		We may redeem the exchange notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount thereof, plus a make whole redemption premium.
		See "Description of Notes—Optional Redemption."


Tax Redemption		The exchange notes may also be redeemed at our option, in whole but not in part, under certain circumstances relating to changes in applicable tax laws as described under "Description of Notes—Tax Redemption."
Change of Control		If we experience specific kinds of change of control, we must give holders the opportunity to sell their notes to us at a price of 101% of their principal amount, plus accrued and unpaid interest to the repurchase date. See "Description of Notes—Repurchase of Notes upon a Change of Control."
Basic Covenants of the Indenture		The covenants contained in the Note Indenture, among other things, limit our ability and the ability of our restricted subsidiaries to:
		• incur additional indebtedness;
		• pay dividends or make other restricted payments;
		• enter into certain types of transactions with our affiliates;
		• allow our restricted subsidiaries to issue guarantees;
		• merge, consolidate or sell substantially all of our assets.
		These covenants are subject to a number of important exceptions, limitations and qualifications that are described under "Description of Notes—Certain Covenants."
Use of Proceeds		We will not receive any proceeds from the issuance of the exchange notes in exchange for the outstanding initial notes. We are making this exchange solely to satisfy our obligations under the registration rights agreement entered into in connection with the offering of the initial notes.
Absence of a Public Market for the Exchange Notes		The exchange notes are new securities with no established market for them. We cannot assure you that a market for these exchange notes will develop or that this market will be liquid. Please refer to the section of this prospectus entitled "Risk Factors—Risks Related to the Notes—Your ability to transfer the notes may be limited by the absence of an active trading market, and an active trading market may not develop for the notes."
Form of the Exchange Notes		The exchange notes will be represented by one or more permanent global securities in registered form deposited on behalf of The Depository Trust Company, or DTC, with U.S. Bank National Association, as custodian. You will not receive exchange notes in certificated form unless one of the events described in the section of this prospectus entitled "Description of Notes—Book-Entry, Delivery and Form—Exchanges of Book-Entry Notes for Certificated Notes" occurs. Instead, beneficial interests in the exchange notes will be shown on, and transfers of these exchange notes will be effected only through, records maintained in book-entry form by DTC with respect to its participants.


Risk Factors		See "Risk Factors" beginning on page 14 for a discussion of factors you should carefully consider before deciding to invest in the exchange notes.

For additional information regarding the notes, see the "Description of Notes" section of this prospectus.

Summary Historical Financial Information

The summary historical financial data presented below as at and for each of the three-month periods ended March 31, 2012 and March 31, 2011 have been derived from, and should be read together with, our unaudited interim consolidated financial statements and accompanying notes included elsewhere in this prospectus and other operational data. The summary historical financial data presented below as at and for each of the years in the two-year period ended December 31, 2011 have been derived from, and should be read together with, our audited consolidated financial statements and the accompanying notes included elsewhere in this prospectus. The unaudited and audited consolidated financial statements referred to above are reported in Canadian dollars and have been prepared in accordance with IFRS.

The summary historical financial data presented below are qualified in their entirety by the more detailed information appearing in our consolidated financial statements and the related notes, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial information included elsewhere in this prospectus. Historical results are not necessarily indicative of results expected for any future period.

*In accordance with IFRS*	Three Months Ended March 31,

($000's, except where noted)	2012			2011
FINANCIAL
Revenues⁽¹⁾		1,426,140			1,248,924
Cash from operating activities		85,110			146,828
Net income (loss)		(72,081	)		37,961
Bank loan		531,619			29,660
Convertible debentures		741,237			744,490
Senior notes		486,611			470,676

Total financial debt⁽²⁾		1,759,467			1,244,826
Total assets		6,322,250			6,041,118
UPSTREAM OPERATIONS
Daily sales volumes (boe/d)		60,550			53,331
Average realized price
Oil and NGLs ($/bbl)⁽³⁾		79.32			73.75
Gas ($/mcf)		2.29			3.83
Operating netback prior to hedging ($/boe)⁽²⁾		29.21			33.67
Capital asset additions (excluding acquisitions)		238,592			237,649
Property and business acquisitions (dispositions), net		(1,988	)		515,496
Abandonment and reclamation expenditures		6,587			1,967
Net wells drilled		60.4			104.9
Net undeveloped land acquired in business combinations (acres)⁽⁴⁾		—			223,405
Net undeveloped land additions (acres)		44,931			53,480
DOWNSTREAM OPERATIONS
Average daily throughput (bbl/d)		100,000			97,438
Average refining margin (US$/bbl)		4.58			10.96
Capital asset additions		13,263			35,879

(1): Revenues are net of royalties and the effective portion of Harvest's realized crude oil hedges.
(2): This is a non-GAAP measure; please refer to "Non-GAAP Financial Measures" in this prospectus.
(3): Excludes the effect of risk management contracts designated as hedges.
(4): Excludes carried interest lands acquired in business combinations.

*In accordance with IFRS*	Year Ended December 31,

($000's, except for per share amounts)	2011			2010
Income statement data
Net revenues
Upstream		1,091,414			852,247
Downstream		3,239,455			3,105,957

Total		4,330,869			3,958,204

Operating loss		(36,089	)		(49,613	)
Net loss		(104,657	)		(81,163	)
Net loss per common share
Basic		(0.28	)		(0.27	)
Diluted		(0.28	)		(0.27	)
Distributions/dividends declared		—			—
Distributions/dividends declared—U.S. dollars⁽¹⁾		—			—
Distributions declared, per common share		—			—

*In accordance with IFRS*	As at December 31,

($000's)	2011		2010
Balance sheet data
Total assets		6,284,370		5,388,740
Net assets		3,453,644		3,016,855
Shareholder's capital		3,860,786		3,355,350
Temporary equity		—		—
Capital expenditures
Upstream		1,246,148		953,674
Downstream		284,244		71,234

Total		1,530,392		1,024,908

Share data
Weighted average common shares outstanding
Basic and diluted		377,908,587		303,005,645

	Year Ended December 31,

($000's)	2011		2010
Other Financial Information
EBITDA⁽²⁾		617,819		518,520

(1)

Translated using the average noon buying rate as disclosed in "Exchange Rate Information".

(2)

In evaluating EBITDA you should be aware that in the future we may incur charges and other items similar to those used in calculating EBITDA. EBITDA has limitations as an analytical tool and you should not consider it in isolation or as substitute for analysis of our results as reported under IFRS. Some of these limitations are:

•: it does not reflect every cash expenditure future cash requirements for taxes and capital expenditures or contractual commitments;
•: it does not reflect the significant interest expense or the cash requirements necessary to service interest or principal payments on our debt;
•: although depletion depreciation and amortization are non-cash charges the assets being depleted depreciated and amortized will often have to be replaced in the future and EBITDA does not reflect any cash requirements for such replacements; and

•: other companies in our industry may calculate these EBITDA differently than we do limiting its usefulness as comparative measure

You should compensate for these limitations by relying primarily on our IFRS results and using EBITDA only supplementally. See our consolidated financial statements and the related notes thereto included elsewhere in this prospectus. EBITDA is not intended as an alternative to net income as an indicator of our operating performance nor as an alternative to any other measure of performance in conformity with IFRS. You should therefore not place undue reliance on EBITDA or ratios calculated using that measure.

EBITDA is defined in Harvest's Credit Facility as earnings before finance costs, income tax expense or recovery, depletion, depreciation and amortization "DD&A", exploration and evaluation costs, impairment of assets, unrealized gains or losses on risk management contracts, unrealized gains or losses on foreign exchange, gains or losses on disposition of assets and other non-cash items. The following is a reconciliation of EBITDA to net loss, the nearest IFRS measure:

	Twelve Months Ended			Twelve Months Ended December 31,

($000's)	March 31, 2012			2011			2010
Net loss		(214,699	)		(104,657	)		(81,163	)
DD&A		657,007			626,698			553,732
Unrealized (gains) losses on risk management contracts		2,222			(746	)		(2,358	)
Unrealized (gains) losses on foreign exchange		9,408			2,555			(1,875	)
Unsuccessful exploration and evaluation costs		15,824			17,757			2,858
Impairment of PP&E		21,843			—			13,661
Gains on disposition of PP&E		(7,749	)		(7,883	)		(741	)
Income tax recovery		(56,320	)		(29,827	)		(65,309	)
Finance costs		108,946			109,127			100,808
Other non-cash items		(328	)		4,795			(1,093	)

EBITDA(a)		536,154			617,819			518,520

(a): As stipulated by the Credit Facility, annualized EBITDA is a twelve month rolling EBITDA which also includes net income impact from acquisition or disposition as if the transaction had been effected at the beginning of the period. As such, the March 31, 2012 annualized EBITDA is $1.4 million lower than EBITDA and 2011 annualized EBITDA is $5.0 million (2010—$9.8 million) higher than EBITDA.

Earnings to Fixed Charges Ratio

The earnings to fixed charges ratios presented below have been derived from the consolidated financial statements prepared in accordance with IFRS for 2010 to 2012. For the years 2007 to 2009, the ratios have been derived using the figures from the consolidated financial statements prepared in accordance with Canadian GAAP as well as based on the figures resulting from the U.S. GAAP reconciliation. If the ratio indicates less than one-to-one coverage, the dollar amount of the deficiency has been disclosed.

	Three Months Ended		Year Ended December 31,

	March 31, 2012		2011		2010
Earnings to fixed charges ratio⁽¹⁾		—		—		—
Deficiency($000's)		97,674		143,123		146,869

	*(Previous Canadian GAAP)* Year Ended December 31,

	2009		2008		2007
Earnings to fixed charges ratio⁽¹⁾		—		3.19		1.25
Deficiency($000's)		964,177		nil		nil

	*(U.S. GAAP)* Year Ended December 31,

	2009		2008		2007
Earnings to fixed charges ratio⁽¹⁾		—		—		1.86
Deficiency($000's)		694,364		1,347,230		nil

(1): This is a non-GAAP measure; please refer to "Non-GAAP Financial Measures" in this prospectus.

RISK FACTORS

Investing in the notes involves a high degree of risk. You should carefully consider the following factors in addition to the other information set forth in this prospectus before you decide to invest in the notes. The following risks could materially and adversely affect our ability to make payments with respect to the notes, our business or our financial condition or results of operations. In any such case, you may lose all or part of your original investment.

Risks Related to Our Indebtedness and the Notes

Our indebtedness may limit our financial and operating flexibility, and we may incur additional debt, which could increase the risks associated with our substantial indebtedness.

As at March 31, 2012, we had total indebtedness under the Credit Facility, our Debentures and the notes of approximately $1,767 million ($1,759 million net of deferred finance charges). Our substantial indebtedness could have material adverse consequences for our business, and may:

•: require us to dedicate a large portion of our cash flow to pay principal and interest on our indebtedness, which will reduce the availability of our cash flow to fund working capital, capital expenditures, research and development expenditures and other business activities;
•: increase our vulnerability to general adverse economic and industry conditions;
•: limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•: restrict our ability to make strategic acquisitions or dispositions or exploit business opportunities;
•: place us at a competitive disadvantage compared to our competitors that have less debt; and
•: limit our ability to borrow additional funds (even when necessary to maintain adequate liquidity) or dispose of assets.

Under the Credit Facility, the Debentures Indenture and the Note Indenture, we may incur additional indebtedness. If new debt is added to our existing debt levels, the related risks that we now face would increase.

Variations in interest rates on our current and/or future financing arrangements may result in significant increases in our borrowing costs.

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 notes will be 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 notes and Credit Facility.

The notes and the guarantees will not be secured by any of our assets and therefore will be effectively subordinated to our existing and future secured indebtedness.

The notes and the guarantees will be general unsecured obligations ranking effectively junior in right of payment to all existing and future secured debt, including indebtedness under the Credit Facility, to the extent of the collateral securing such debt. In addition, the Note Indenture permits the incurrence of additional debt, some of which may be secured debt. In the event that we or a guarantor

is declared bankrupt, becomes insolvent or is liquidated or reorganized, creditors whose debt is secured by our or the guarantors' assets will be entitled to the remedies available to secured holders under applicable laws, including the foreclosure of the collateral securing such debt, before any payment may be made with respect to the notes or the affected guarantees. As a result, there may be insufficient assets to pay amounts due on the notes and holders of the notes may receive less, if anything, ratably, than holders of secured indebtedness. As of March 31, 2012, the total amount of secured debt that we had outstanding was $534.7 million ($531.6 million net of deferred finance charges), with approximately $265.3 million of undrawn borrowing capacity available under the Credit Facility. We may also incur additional senior secured indebtedness.

The notes are structurally subordinated to the existing and future liabilities of our subsidiaries that do not guarantee the notes to the extent of the assets of such non-guarantor subsidiaries.

Certain of our subsidiaries will not guarantee the notes. The notes will be structurally subordinated to all existing and future liabilities of our subsidiaries that do not guarantee the notes. Therefore, our rights and the rights of our creditors to participate in the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganized are subject to the prior claims of such subsidiary's creditors. As a result, all indebtedness and other liabilities, including trade payables, of the non-guarantor subsidiaries, whether secured or unsecured, must be satisfied before any of the assets of such subsidiaries would be available for distribution, upon a liquidation or otherwise, to us in order for us to meet our obligations with respect to the notes. To the extent that we may be a creditor with recognized claims against any subsidiary, our claims would still be subject to the prior claims of such subsidiary's creditors to the extent that they are secured or senior to those held by us.

As of March 31, 2012, our non-guarantor subsidiaries had no indebtedness and approximately $14.0 million of other liabilities, including trade payables and accrued expenses. The non-guarantor subsidiaries represented approximately 2% of our consolidated revenues and approximately 0% of our consolidated EBITDA, respectively, for the twelve months ended March 31, 2012 and at March 31, 2012 represented approximately 0% of our consolidated assets (excluding intercompany receivables).

Our ability to generate the significant amount of cash needed to pay interest and principal on the notes and service our other debt and financial obligations and our ability to refinance all or a portion of our indebtedness or obtain additional financing depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness, including the notes, depends on our ability to generate cash in the future. We are subject to general economic, climatic, industry, financial, competitive, legislative, regulatory and other factors that are beyond our control. In particular, economic conditions could adversely affect our ability to repay our indebtedness, including the notes. As a result, we may need to refinance all or a portion of our indebtedness, including the notes, on or before maturity. Our ability to refinance debt or obtain additional financing will depend on, among other things:

•: our financial condition at the time;
•: restrictions in the Note Indenture and restrictions in the agreements governing our other indebtedness; and
•: other factors, including financial and capital markets or oil and natural gas industry conditions.

We may not be able to refinance any of our indebtedness, including the notes, on commercially reasonable terms, or at all. If our operations do not generate sufficient cash flow from operations, and additional borrowings or refinancings are not available to us, we may not have sufficient cash to enable us to meet all of our obligations, including payments on the notes. 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, to continue construction on its BlackGold assets and to debottleneck its refinery operations will be impaired.

We may be unable to repurchase the notes upon a change of control.

Upon the occurrence of a Change of Control (as defined in the Note Indenture), we will be required to offer to repurchase all outstanding notes at a price of 101% of their principal amount plus accrued and unpaid interest. Any Change of Control also would constitute a default under the Credit Facility. Therefore, upon the occurrence of a Change of Control, the lenders under the Credit Facility would have the right to accelerate the payment obligations with respect to outstanding loans under the facility, and if so accelerated, we would be required to pay all of our outstanding obligations under such facility. Our source of funds for any such purchase of the notes will be available cash, cash generated from our subsidiaries or other sources, including borrowings, sales of assets or sales of equity. The sources of cash may not be adequate to permit us to repurchase the notes upon a Change of Control. Any failure on our part to offer to repurchase the notes, or to repurchase notes tendered following a Change of Control, may result in a default under the Note Indenture and may be an event of default under the agreements governing our other indebtedness. For further information, see "Description of Notes—Repurchase of Notes upon a Change of Control."

The terms of the Note Indenture provide only limited protection against significant events that could adversely impact your investment in the notes.

Upon the occurrence of a Change of Control you will have the right to require us to repurchase the notes as provided in the Note Indenture, and on the terms set forth in the notes. However, the Change of Control provisions will not afford you protection in the event of certain highly leveraged transactions that may adversely affect you. For example, any leveraged recapitalization, refinancing, restructuring or acquisition initiated by us generally will not constitute a Change of Control (as defined in the Note Indenture). As a result, we could enter into any such transaction even though the transaction could increase the total amount of our outstanding indebtedness, adversely affect our capital structure or credit rating or otherwise adversely affect the holders of the notes. If any such transaction were to occur, the value of your notes could decline. The Note Indenture does not contain any financial covenants or other provisions that would afford the holders of the notes any substantial protection in the event we participate in a highly leveraged transaction.

Certain laws may permit courts to void the guarantees of the notes in specific circumstances, which would interfere with the payment of the guarantees.

Under certain bankruptcy and fraudulent transfer laws, any guarantee of the notes made by any of our subsidiaries could be voided, or claims under the guarantee made by any of our subsidiaries could be subordinated to all other obligations of any such subsidiary, if the subsidiary, at the time it incurred the obligations under such guarantee:

•

incurred the obligations with the intent to hinder, delay or defraud creditors; or

•

received less than reasonably equivalent value in exchange for incurring those obligations; and

(1): was insolvent or rendered insolvent by reason of that incurrence;
(2): was engaged in a business or transaction for which the subsidiary's remaining assets constituted unreasonably small capital; or
(3): intended to incur, or believed that it would incur, debts beyond our ability to pay those debts as they mature.

The Note Indenture limits the liability of each guarantor on its guarantee to the maximum amount that such guarantor could incur without risk that its guarantee would be subject to avoidance as a fraudulent transfer. However, this limitation may not protect such guarantees from fraudulent transfer challenges or, if it does, that the remaining amount due and collectible under the guarantees would suffice, if necessary, to pay the notes in full when due. In a recent Florida bankruptcy case, this kind of provision was found to be unenforceable and, as a result, the subsidiary guarantees in that case were found to be fraudulent conveyances. We do not know if that case will be followed if there is litigation on this point under the Note Indenture. However, if it is followed, the risk that the guarantees will be found to be fraudulent conveyances will be significantly increased.

A legal challenge to the obligations under any guarantee on fraudulent conveyance grounds could focus on any benefits received in exchange for the incurrence of those obligations. We believe that each of our subsidiaries making a guarantee received reasonably equivalent value for incurring the guarantee, but a court may disagree with our conclusion or elect to apply a different standard in making its determination. A court could thus void the obligations under a guarantee, subordinate it to a guarantor's other debt or take other action detrimental to the holders of the notes. The measures of insolvency for purposes of the fraudulent transfer laws vary depending on the law applied in the proceeding to determine whether a fraudulent transfer has occurred. Generally, however, an entity would be considered insolvent if:

•: the sum of its debts, including contingent liabilities, is greater than the fair saleable value of all of its assets;
•: the present fair saleable value of its assets is less than the amount that would be required to pay its probable liabilities on its existing debts, including contingent liabilities, as they become absolute and mature; or
•: it cannot pay its debts as they become due.

Your ability to transfer the exchange notes may be limited by the absence of an active trading market, and an active trading market may not develop for the exchange notes.

The exchange notes are a new issue of securities for which there is no established trading market. We do not intend to list the exchange notes on any national or regional securities exchange or seek approval for quotation through any automated quotation system. An active trading market may not develop for the exchange notes. Subsequent to their initial issuance, the exchange notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar notes, our operating performance and financial condition and other factors.

You might have difficulty enforcing your rights against us and our directors and officers.

We are a corporation incorporated under the laws of the Province of Alberta, Canada and the guarantors are organized under the laws of Canadian jurisdictions. Most of our directors and officers and certain of the experts named in this prospectus reside principally in Canada. Because we and these persons are located outside the United States, it may not be possible for you to effect service of process within the United States on us or them. Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in United States courts, because a substantial portion of our and their assets are located outside the United States. We have been advised by Bennett Jones LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based on the United States federal securities laws or the securities or "blue sky" laws of any state within the United States and as to the enforceability in Canadian courts of judgments of United States courts obtained in actions based on the civil liability provisions of the United States federal securities laws or any such state securities or "blue sky" laws.

Therefore, it may not be possible to enforce those judgments against us, our current and proposed directors and officers or certain of the experts named in this prospectus.

Risks Related to the Exchange Offer

The issuance of the exchange notes may adversely affect the market for the initial notes.

To the extent the initial notes are tendered and accepted in the exchange offer, the trading market for the untendered and tendered but unaccepted initial notes could be adversely affected. Because we anticipate that most holders of the initial notes will elect to exchange their initial notes for exchange notes due to the absence of restrictions on the resale of exchange notes under the Securities Act, we anticipate that the liquidity of the market for any initial notes remaining after the completion of this exchange offer may be substantially limited. Please refer to the section in this prospectus entitled "The Exchange Offer—Your Failure to Participate in the Exchange Offer Will Have Adverse Consequences."

Some persons who participate in the exchange offer must deliver a prospectus in connection with resales of the exchange notes.

Based on interpretations of the staff of the SEC contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983), we believe that you may offer for resale, resell or otherwise transfer the exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act. However, in some instances described in this prospectus under "Plan of Distribution," you will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer your exchange notes. In these cases, if you transfer any exchange note without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from registration of your exchange notes under the Securities Act, you may incur liability under the Securities Act. We do not and will not assume, or indemnify you against, this liability.

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 and natural gas 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 petroleum 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 petroleum and natural 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 petroleum 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 and natural gas products produced by Harvest at such reduced prices would lower its revenues.

Harvest conducts an impairment assessment of the carrying value of its assets to the extent required by IFRS. If petroleum 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 petroleum and natural gas prices over recent years has affected the profitability of the oil and gas industry and Harvest. Harvest did not incur any impairment charges to the petroleum and natural gas assets in 2011. During the first quarter of 2012, Harvest recognized an impairment charge of $21.8 million as a result of lower forecasted natural gas prices. There can be no assurance that declines in petroleum and natural gas prices or other circumstances will not result in impairment charges at some future dates.

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

In the first quarter of 2012, Harvest's production was approximately 41% light and medium gravity crude oil, 15% heavy oil, 9% NGLs and 35% 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 Harvest receiving lower prices for 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 petroleum 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 petroleum, natural gas and other related products, drilling and completion of petroleum and natural gas wells, and the operation and development of petroleum 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 petroleum, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks. Harvest's corporate environmental, health and safety 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 would 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 access to people 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 there from, 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 the 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 diluents 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 reserves reports are estimates and actual production and recovery rates may vary from the estimates and the variations may be significant.

The reserves and recovery information contained in the Reserves Report prepared by the Independent Reserves Evaluators are complex estimates and the actual production and ultimate reserves recovered from the Properties may differ from the estimates prepared by the independent reserves evaluators. There are numerous uncertainties inherent in estimating quantities of petroleum and natural gas reserves, including many factors beyond the Corporation's control. The reserves data in this prospectus represents estimates only. In general, petroleum 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 petroleum 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 there from, prepared by different evaluators or by the same evaluators 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 reserves of the Properties as estimated by Independent Reserves Evaluators are based in part on cash flows to be generated in future years as a result of future capital expenditures. The reserves value of the Properties as estimated by the Independent Reserves 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 reserves report estimates and the assumptions made in preparing the reserves 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 independent reserves valuators in the related reserves 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 the Properties.

Absent capital reinvestment or acquisition and development, production levels from petroleum and natural gas properties and reserves, and cash generated, will decline over time.

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 petroleum 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 reserves 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.

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 petroleum and natural gas production. These royalty regimes may be amended or supplemented from time to time. 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 BlackGold.

The development of BlackGold 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 may negatively 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. Harvest has entered into an EPC 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, estimated project cost may increase and production may be reduced and/or delayed.

BlackGold 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 the 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 is 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 green house gas 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.

In addition to the factors above, refinery margin 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. As a result, it can be reasonably expected that Downstream results will fluctuate over time and from period to period. Harvest conducts an assessment of the carrying value of its assets to the extent required by IFRS. If refined product margins decline, the carrying value of Harvest's Downstream assets could be subject to downward revision and the Corporation's earnings could be adversely impacted. Although Harvest did not incur any impairment charges to its Downstream assets in 2011 or in the first quarter of 2012, there can be no assurance that further decline in refined product margins will not result in such impairment charges at some future dates.

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 the respective refined products. Harvest's Upstream operations does not produce crude oil that can be economically transported to the Refinery and, as a result, the Refinery purchases 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 $0.043 per kilowatt hour in 2011 and $0.0407 per kilowatt hour in 2009, as compared to $0.0396 in 2007. 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.

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 a suite of expansion or debottlenecking projects. However, if unanticipated costs occur or 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 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 virtually all 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 67% 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 MEC terminates the SOA (2011) prior to expiration or does not agree to renew the SOA (2011) upon expiration, Harvest's business could be adversely affected.

Under the SOA (2011), the Refinery receives all of its feedstock from MEC and sells almost all of the refined product produced to MEC. If MEC terminates the SOA (2011) prior to expiration or does not agree to renew the SOA (2011) upon expiration, Harvest would seek to enter into a similar agreement with another party that has a similar credit profile and expertise to that of MEC'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 (2011) with another party or to enter into agreements with a number of different parties to replicate the economics of the SOA (2011). If the SOA (2011) 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 effect on Harvest's business.

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

MEC purchases crude oil feedstock to supply to North Atlantic pursuant to the SOA (2011). Accordingly, should the creditworthiness of MEC deteriorate, crude oil producers and suppliers may

change their view on contracting with MEC for the supply of crude oil. Due to the large dollar amount of credit associated with the volume of crude oil purchases, any imposition of more burdensome payment terms may have a material adverse effect on MEC which could hinder its ability to supply sufficient quantities of crude oil to operate the Refinery. This in turn hinders North Atlantic's ability to operate the Refinery at full capacity. 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 shut-down caused by an accident or be damaged by severe weather and these potential disruptions 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.

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 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 Downstream operations produces aviation fuels, which involves 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.

Collective bargaining agreements with North Atlantic'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, 2011, 67% of full-time employees and 97% of part-time employees in the Downstream operations are represented by the United Steel Workers of America pursuant to collective bargaining agreements. Upon the expiry of existing collective 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 Refinery is subject to operational risks that include severe weather, access to skilled labor, availability of materials, competing projects and equipment failures which may cause a refinery shut-down or a reduction in production thereby reducing or eliminating Harvest's cash flow.

The operation of the Refinery requires physical access for people and equipment on a regular basis which could be affected by weather, accidents, government regulations or third party actions. Skilled labor is necessary to run our operations and there is a risk that we may have difficulty in sourcing skilled labor which could lead to increased operating and capital costs. There are risks and uncertainties affecting construction or planned maintenance schedules and costs, including the availability of materials, equipment, qualified personnel, impacts of competing projects drawing on the same resources during the same time period; and the potential for disruptions to operations and construction projects. Accordingly, actual costs can be materially different from estimates and could have a material adverse effect on our costs, results of operations and cash flows. In addition, maintenance activities may not improve operational performance or the output of related facilities and construction projects may not deliver anticipated results.

Risks Related to Harvest's Structure

Reliance on management of Harvest

Holders of securities of Harvest will be dependent on the management of Harvest in respect of the administration and management of 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 its 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.

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 petroleum, 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.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus 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: "budget", "outlook", "forecast", "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 prospectus should not be unduly relied upon. These statements speak only as of the date of this prospectus or as of the date specified in the documents incorporated by reference into this prospectus, as the case may be.

In particular, this prospectus, 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, net income and cash flows 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, and capital projects;
•: 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 and other capital projects;
•: future sources of funding, debt levels and availability of committed credit facilities;
•: factors upon which to decide whether or not to undertake a capital project;
•: plans to make acquisitions and expected synergies from acquisitions made;
•: possible commerciality of exploration and development projects;
•: expectations regarding the development and production potential of petroleum and natural gas properties;
•: expected timing cost and associated impact of facility turnaround and maintenance;
•: treatment under government regulatory regimes including without limitation, environmental and tax regulation;
•: ultimate recoverability of the Corporation's assets;

•: 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 prospectus and the documents incorporated 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 ability to maintain Harvest's operations;
•: 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;
•: the impact of technology on operations and developments of Harvest's assets;
•: 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;
•: labor and material shortages;
•: the volatility of refining gross margins including the price of feedstocks as well as the prices for refined products; and
•: the stability of the Refinery throughput performance.

Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this prospectus 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 the "Risk Factors" section.

USE OF PROCEEDS

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

The net proceeds from the issuance of the initial notes was approximately US$485.3 million after deducting the initial purchaser discounts of US$3.4 million and the expenses of this offering incurred by us of approximately US$11.3 million. We used such proceeds to purchase or redeem the US$209.6 million aggregate principal amount of our then outstanding 7⁷/8% Senior Notes due October 15, 2011, including related premiums, accrued interest and fees. Any remaining proceeds from the issuance of the initial notes were used to repay amounts owed under the Credit Facility and for working capital and general purposes.

CAPITALIZATION

The following table summarizes the Corporation's capital structure as at March 31, 2012:

($000's, except where noted)		As at March 31, 2012

Debts
Bank loan⁽¹⁾			534,675
Convertible debentures, at principal amount			733,973
Senior notes, at principal amount (US$500 million)⁽²⁾			498,750

Total Debt			1,767,398
Shareholder's Equity			3,355,333

Total Capitalization			5,122,731

(1): The bank loan net of deferred financing costs is $531.6 million.
(2): Principal amount converted at the period end exchange rate.

SELECTED HISTORICAL FINANCIAL INFORMATION

The selected historical financial data presented below as at and for each of the three-month periods ended March 31, 2012 and March 31, 2011 have been derived from, and should be read together with, our unaudited interim consolidated financial statements and accompanying notes included elsewhere in this prospectus and other operational data. The selected historical financial data presented below as at and for each of the years in the two-year period ended December 31, 2011 have been derived from, and should be read together with, our audited consolidated financial statements and the accompanying notes included elsewhere in this prospectus. The unaudited and audited consolidated financial statements referred to above are reported in Canadian dollars and have been prepared in accordance with IFRS.

Our audited consolidated financial statements were previously prepared in accordance with Canadian GAAP, which differs from IFRS in certain respects. For a discussion of the principal differences between IFRS and Canadian GAAP as they relate to our financial results, see note 27 to our audited consolidated financial statements included elsewhere in this prospectus. The selected historical financial data presented below as at and for each of the years in the three-year period ended December 31, 2009 have been derived from, and should be read together with, our audited consolidated financial statements prepared in accordance with Canadian GAAP and reflect the adjustments made to conform with U.S. GAAP, which are not included in this prospectus.

The selected historical financial data presented below are qualified in their entirety by the more detailed information appearing in our financial statements and the related notes, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial information included elsewhere in this prospectus. Historical results are not necessarily indicative of results expected for any future period.

	Three Months Ended March 31,

($000's, except for per share amounts)	2012			2011
FINANCIAL
Revenues⁽¹⁾		1,426,140			1,248,924
Cash from operating activities		85,110			146,828
Net income (loss)		(72,081	)		37,961
Bank loan		531,619			29,660
Convertible debentures		741,237			744,490
Senior notes		486,611			470,676

Total financial debt⁽²⁾		1,759,467			1,244,826
Total assets		6,322,250			6,041,118
UPSTREAM OPERATIONS
Daily sales volumes (boe/d)		60,550			53,331
Average realized price
Oil and NGLs ($/bbl)⁽³⁾		79.32			73.75
Gas ($/mcf)		2.29			3.83
Operating netback prior to hedging ($/boe)⁽²⁾		29.21			33.67
Capital asset additions (excluding acquisitions)		238,592			237,649
Property and business acquisitions (dispositions), net		(1,988	)		515,496
Abandonment and reclamation expenditures		6,587			1,967
Net wells drilled		60.4			104.9
Net undeveloped land acquired in business combinations (acres)⁽⁴⁾		—			223,405
Net undeveloped land additions (acres)		44,931			53,480

	Three Months Ended March 31,

($000's, except for per share amounts)	2012		2011
DOWNSTREAM OPERATIONS
Average daily throughput (bbl/d)		100,000		97,438
Average refining margin (US$/bbl)		4.58		10.96
Capital asset additions		13,263		35,879

(1): Revenues are net of royalties and the effective portion of Harvest's realized crude oil hedges.
(2): This is a non-GAAP measure; please refer to "Non-GAAP Financial Measures" in this prospectus.
(3): Excludes the effect of risk management contracts designated as hedges.
(4): Excludes carried interest lands acquired in business combinations.

*In accordance with IFRS*	Year Ended December 31,

($000's, except for per share amounts)	2011			2010
Income statement data
Net revenues
Upstream		1,091,414			852,247
Downstream		3,239,455			3,105,957

Total		4,330,869			3,958,204

Operating loss		(36,089	)		(49,613	)
Net loss		(104,657	)		(81,163	)
Net loss per common share
Basic		(0.28	)		(0.27	)
Diluted		(0.28	)		(0.27	)
Distributions/dividends declared		—			—
Distributions/dividends declared—U.S. dollars⁽¹⁾		—			—
Distributions declared, per common share		—			—

*In accordance with IFRS*	As at December 31,

($000's, except for share data)	2011		2010
Balance sheet data
Total assets		6,284,370		5,388,740
Net assets		3,453,644		3,016,855
Shareholder's capital		3,860,786		3,355,350
Temporary equity		—		—
Capital expenditures
Upstream		1,246,148		953,674
Downstream		284,244		71,234

Total		1,530,392		1,024,908

Share data
Weighted average common shares outstanding
Basic and diluted		377,908,587		303,005,645

*In accordance with IFRS*	As at December 31,

($000's)	2011		2010
Other Financial Information
EBITDA⁽²⁾		617,819		518,520

(1)

Translated using the average noon buying rate as disclosed in "Exchange Rate Information".

(2)

•: it does not reflect every cash expenditure future cash requirements for taxes and capital expenditures or contractual commitments;
•: it does not reflect the significant interest expense or the cash requirements necessary to service interest or principal payments on our debt;
•: although depletion depreciation and amortization are non-cash charges the assets being depleted depreciated and amortized will often have to be replaced in the future and EBITDA does not reflect any cash requirements for such replacements; and
•: other companies in our industry may calculate these EBITDA differently than we do limiting its usefulness as comparative measure.

	Twelve Months Ended			Twelve Months Ended December 31,

($000's)	March 31, 2012			2011			2010
Net loss		(214,699	)		(104,657	)		(81,163	)
DD&A		657,007			626,698			553,732
Unrealized (gains) losses on risk management contracts		2,222			(746	)		(2,358	)
Unrealized (gains) losses on foreign exchange		9,408			2,555			(1,875	)
Unsuccessful exploration and evaluation costs		15,824			17,757			2,858
Impairment of PP&E		21,843			—			13,661
Gains on disposition of PP&E		(7,749	)		(7,883	)		(741	)
Income tax recovery		(56,320	)		(29,827	)		(65,309	)
Finance costs		108,946			109,127			100,808
Other non-cash items		(328	)		4,795			(1,093	)

EBITDA(a)		536,154			617,819			518,520

(a): As stipulated by the Credit Facility, annualized EBITDA is a twelve month rolling EBITDA which also includes net income impact from acquisition or disposition as if the transaction had been effected at the beginning of the period. As such, the March 31, 2012 annualized EBITDA is $1.4 million lower than EBITDA and 2011 annualized EBITDA is $5.0 million (2010—$9.8 million) higher than EBITDA.

*In accordance with U.S. GAAP*	Year Ended December 31,

($000's, except for per Trust Unit amounts)	2009			2008			2007
Income statement data
Net revenues
Upstream		757,448			1,294,769			971,044
Downstream		2,381,637			4,194,595			3,098,556

Total		3,139,085			5,489,364			4,069,600
Operating income (loss)		(603,762	)		550,681			339,430
Net income (loss)		(641,906	)		(1,343,337	)		159,194
Net income (loss) per Trust Unit
Basic		(3.69	)		(8.79	)		1.15
Diluted		(3.69	)		(8.79			1.14
Distributions/dividends declared		164,770			551,325			610,280
Distributions/dividends declared—U.S. dollars⁽¹⁾		144,289			517,197			567,805
Distributions declared, per Trust Unit		1.00			3.60			4.40

*In accordance with U.S. GAAP*	As at December 31,

($000's, except for share data)	2009			2008			2007
Balance sheet data
Total assets		2,476,415			3,561,515			4,953,634
Net assets		(2,073,824	)		(997,695	)		(976,476	)
Shareholder's capital		—			—			—
Temporary equity		2,422,133			1,562,806			2,997,136
Capital expenditures
Upstream		124,160			400,085			438,830
Downstream		43,875			56,162			44,111

Total		168,035			456,247			482,941

Share data
Weighted average Trust Units outstanding
Basic		173,785,806			152,836,717			138,440,869
Diluted		173,785,806			152,836,717			139,088,543

(1): Translated using the average noon buying rate as disclosed in "Exchange Rate Information".

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

The following discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in "Risk Factors" and elsewhere in this prospectus. Actual results may differ materially from those contained in any forward-looking statements. See "Special Note Regarding Forward-Looking Statements" included elsewhere in this prospectus. The following discussion should be read in conjunction with "Selected Historical Financial Information" and our financial statements and related notes included elsewhere in this prospectus.

Results of Operations

Upstream Operations

Summary of Financial and Operating Results

	Three Months Ended March 31,						Year Ended December 31,

($000's, except where noted)	2012			2011			2011			2010
FINANCIAL
Petroleum and natural gas sales⁽¹⁾		324,151			281,051			1,286,866			1,007,004
Royalties		(53,417	)		(35,858	)		(195,452	)		(154,757	)

Revenues		270,734			245,193			1,091,414			852,247
Expenses
Operating		99,975			83,595			350,456			265,593
Transportation and marketing		5,686			3,003			29,626			9,394
Realized (gains) losses on risk management contracts⁽²⁾		—			(2,223	)		(6,000	)		1,808

Operating netback after hedging⁽³⁾		165,073			160,818			717,332			575,452
General and administrative		12,153			13,522			60,804			45,303
Depreciation, depletion and amortization		144,482			121,344			535,692			470,641
Exploration and evaluation		6,736			6,215			18,289			3,300
Impairment of property, plant and equipment		21,843			—			—			13,661
Unrealized gains on risk management contracts⁽⁴⁾		(271	)		(3,240	)		(746	)		(2,358	)
Gains on disposition of property, plant and equipment		(106	)		(240	)		(7,883	)		(741	)

		(19,764	)		23,217			111,176			45,646

Capital asset additions (excluding acquisitions)		238,592			237,649			733,380			403,848
Property and business acquisitions (dispositions), net		(1,988	)		515,496			505,355			175,657
Abandonment and reclamation expenditures		6,587			1,967			22,110			20,257
OPERATING
Light / medium oil (bbl/d)		24,936			25,523			24,380			24,077
Heavy oil (bbl/d)		9,272			9,038			8,992			9,253
Natural gas liquids (bbl/d)		5,668			3,455			5,062			2,587
Natural gas (mcf/d)		124,045			91,888			112,360			80,881

Total (boe/d)		60,550			53,331			57,161			49,397

(1): Inclusive of the effective portion of Harvest's realized crude oil hedges.
(2): Realized (gains) losses on risk management contracts include the settlement amounts for power derivative contracts and the ineffective portion of realized crude oil hedges.
(3): This is a non-GAAP measure; please refer to "Non-GAAP Financial Measures" in this prospectus.
(4): Unrealized gains on risk management contracts reflect the change in fair value of the power derivative contracts and the ineffective portion of crude oil hedges.

Commodity Price Environment

	Three Months Ended March 31,							Year Ended December 31,

	2012		2011		Change			2011		2010		Change
West Texas Intermediate crude oil (US$/bbl)		102.93		94.10		9%			95.12		79.53		20%
West Texas Intermediate crude oil ($/bbl)		103.02		92.74		11%
Edmonton light crude oil ($/bbl)		92.37		88.04		5%			95.18		77.58		23%
Bow River blend crude oil ($/bbl)		82.93		71.33		16%			78.41		68.25		15%
Western Canadian Select ("WCS") crude oil ($/bbl)		81.61		70.19		16%
AECO natural gas daily ($/mcf)		2.15		3.76		(43%	)		3.62		4.00		(10%	)
U.S. / Canadian dollar exchange rate		0.999		1.014		(1%	)		1.011		0.971		4%
Differential Benchmarks
Bow River blend differential to WTI ($/bbl)		20.09		21.41		(6%	)
Bow River blend differential as a % of WTI		19.5%		23.1%		(16%	)
WCS differential to WTI ($/bbl)		21.41		22.55		(5%	)
WCS differential as a % of WTI		20.8%		24.3%		(14%	)
Bow River blend differential to Edmonton Par ($/bbl)									16.77		9.33		80%
Bow River blend differential as a % of Edmonton Par									17.6%		12.0%		47%

Three Months Ended March 31, 2012

The average WTI benchmark price in the first quarter of 2012 was 9% higher than the first quarter of 2011. The average Edmonton light crude oil price ("Edmonton Par") also experienced an increase over the first quarter of the prior year, due to the higher WTI prices but partially offset by the widening of the light sweet differential.

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. The Bow River blend crude oil price ("Bow River") increased 16% from the first quarter of 2011, which is consistent with the higher WTI price and the narrowing of the Bow River and WCS differential relative to WTI.

Year Ended December 31, 2011

The Bow River heavy oil differential relative to Edmonton Par widened during 2011 as compared to 2010. 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. The Bow River increased in 2011 with the higher WTI prices, and was partially offset by the stronger Canadian dollar and wider Bow River differential.

The average WTI benchmark price for the year ended December 31, 2011 was 20% higher than the same period in 2010. The average Edmonton Par increased for the year ended December 31, 2011 due to the higher WTI prices and improvement of the light sweet differential, partially offset by the strengthening of the Canadian dollar on an annual average basis.

Realized Commodity Prices

	Three Months Ended March 31,							Year Ended December 31,

	2012		2011		Change			2011		2010		Change
Light to medium oil prior to hedging ($/bbl)		84.88		78.69		8%			85.67		71.09		21%
Heavy oil ($/bbl)		74.24		61.51		21%			69.71		59.94		16%
Natural gas liquids ($/bbl)		63.20		69.32		(9%	)		67.92		58.83		15%
Natural gas ($/mcf)		2.29		3.83		(40%	)		3.83		4.21		(9%	)
Average realized price prior to hedging ($/boe)⁽¹⁾		58.07		59.19		(2%	)		62.13		55.85		11%
Light to medium oil after hedging ($/bbl)⁽²⁾		86.72		77.37		12%			84.61		71.09		19%
Average realized price after hedging ($boe)⁽¹⁾⁽²⁾		58.83		58.55		—			61.68		55.85		10%

(1): Inclusive of sulphur revenue.
(2): Inclusive of the realized gains (losses) from crude oil contracts designated as hedges. Foreign exchange swaps and power contracts are excluded from the realized price.

Three Months Ended March 31, 2012

Prior to hedging activities, our realized price for light to medium oil increased by 8% in the first quarter of 2012 as compared to the same period in the prior year. This increase is consistent with the upward movement in Edmonton Par prices during the first three months of 2012.

In order to mitigate the risk of fluctuating cash flows due to crude oil price volatility, Harvest has entered into fixed-for-floating swaps. The impact of this hedging activity resulted in an increase of $1.84/bbl (2011—decrease of $1.32/bbl) in Harvest's realized light to medium oil price in the first quarter of 2012.

Harvest's realized heavy oil prices for the first quarter of 2012 increased by 21%, mainly due to the increase in the Bow River prices.

�� Although NGL benchmark prices have increased from the first quarter of 2011, the realized prices for NGLs decreased by 9% due to a higher percentage of ethane in the NGL product mix. This change is a result of the assets acquired from Hunt.

The average realized price for Harvest's natural gas sales decreased by 40% compared to the first quarter of 2011, reflecting the 43% decrease in the AECO benchmark price.

Year Ended December 31, 2011

Prior to hedging activities, our realized price for light to medium oil for the year ended December 31, 2011 increased by 21% compared to the same period in 2010. This is consistent with the upward movement in Edmonton Par prices in 2011. In order to manage commodity price volatility effects on cash flow, Harvest has entered into various crude oil fixed-for-floating swaps. The impact of this hedging activity resulted in a decrease of $1.06/bbl (2010—$nil) for the year ended December 31, 2011. See "—Cash Flow Risk Management."

Sales Volumes

	Three Months Ended March 31,

	2012				2011
	2012				2011				% Volume Change
	Volume		Weighting		Volume		Weighting		% Volume Change
Light to medium oil (bbl/d)⁽¹⁾		24,936		41%		25,523		48%		(2%	)
Heavy oil (bbl/d)		9,272		15%		9,038		17%		3%
Natural gas liquids (bbl/d)		5,668		9%		3,455		6%		64%

Total liquids (bbl/d)		39,876		65%		38,016		71%		5%
Natural gas (mcf/d)		124,045		35%		91,888		29%		35%

Total oil equivalent (boe/d)		60,550		100%		53,331		100%		14%

(1): Harvest classifies all 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 24o (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.

	Year Ended December 31,

	2011				2010
	2011				2010				% Volume Change
	Volume		Weighting		Volume		Weighting		% Volume Change
Light to medium oil (bbl/d)⁽¹⁾		24,380		43%		24,077		49%		1%
Heavy oil (bbl/d)		8,992		16%		9,253		19%		(3%	)
Natural gas liquids (bbl/d)		5,062		9%		2,587		5%		96%

Total liquids (bbl/d)		38,434		68%		35,917		73%		7%
Natural gas (mcf/d)		112,360		32%		80,881		27%		39%

Total oil equivalent (boe/d)		57,161		100%		49,397		100%		16%

(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 24o (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.

Three Months Ended March��31, 2012

Harvest's sales volumes increased to 60,550 boe/d in the first quarter of 2012, a 14% increase over the first quarter of 2011. The increase reflects a full quarter of production from the assets acquired from Hunt at the end of February 2011 as well as production increases resulting from Harvest's capital program during the second half of 2011.

Harvest's average light/medium oil sales were 24,936 bbl/d for the first quarter of 2012, a 2% decrease from the same quarter in 2011. The slight decrease from Q1 2011 reflects natural declines and minor production interruptions during the quarter.

Heavy oil sales for the first quarter of 2012 increased by 3% to an average of 9,272 bbl/d, reflecting production increases from Harvest's 2011 drilling and reactivation programs.

Natural gas sales averaged 124,045 mcf/d in the first quarter of 2012 compared to 91,888 mcf/d in 2011. The increase reflects a full quarter of production from assets acquired from Hunt.

Natural gas liquids sales for the three months ended March 31, 2012 increased by 64%, compared to the same period in 2011. Similar to the increase in natural gas sales, the increase was mainly due to the sales volumes reflecting a full quarter of production from assets acquired from Hunt.

Year Ended December 31, 2011

Total sales volumes were 57,161 boe/d for the year ended December 31, 2011, an increase of 16% compared to the same period in 2010. The increase was primarily attributable to the acquisition of the Hunt assets at the end of February 2011.

Harvest's year-to-date light/medium oil sales increased by 1% from 2010 to 24,380 bbl/d. The increase reflects a full year of production from assets acquired in the third quarter of 2010 as well as ten months of production from assets acquired from Hunt in 2011. Sales in 2011 were negatively impacted by the Plains Rainbow Pipeline outage, fires at Red Earth and flooding in southeast Saskatchewan during the summer of 2011.

Heavy oil sales decreased by 3% for the year ended December 31, 2011 compared to 2010. The decrease was primarily due to natural declines and minor production interruptions during the first and second quarter of 2011, partially offset by production increases resulting from Harvest's capital program.

For the year ended December 31, 2011, natural gas sales increased by 31,479 mcf/d (39%), compared to 2010. The increase was mainly due to the acquisition of the Hunt assets at the end of February 2011.

Natural gas liquids sales for the year ended December 31, 2011 increased by 96% compared to the same period in 2010. Similar to the increase in natural gas sales volumes, these increases were mainly due to the acquisition of the Hunt assets at the end of February 2011.

Revenues

	Three Months Ended March 31,									Year Ended December 31,

($000's)	2012			2011			Change			2011			2010			Change
Light / medium oil sales after hedging⁽¹⁾		196,774			177,725			11%			752,898			624,778			21%
Heavy oil sales		62,642			50,032			25%			228,794			202,445			13%
Natural gas sales		25,877			31,679			(18%	)		156,942			124,226			26%
Natural gas liquids sales		32,596			21,473			52%			125,507			55,385			127%
Other⁽²⁾		6,262			142			100%			22,725			170			100%

Petroleum and natural gas sales		324,151			281,051			15%			1,286,866			1,007,004			28%
Royalties		(53,417	)		(35,858	)		49%			(195,452	)		(154,757	)		26%

Revenues		270,734			245,193			10%			1,091,414			852,247			28%

(1): Inclusive of the effective portion of realized gains (losses) from crude oil contracts designated as hedges.
(2): Inclusive of sulphur revenue and miscellaneous income.

Three Months Ended March 31, 2012

Harvest's revenue is subject to changes in sales volumes, commodity prices and currency exchange rates. In the first quarter of 2012, total petroleum and natural gas sales increased by $43.1 million, mainly due to the 14% increase in sales volumes and the increase in sulphur revenue from the acquired Hunt assets. Sulphur revenue represented $6.0 million (2011—$0.1 million) of the total in other revenues for the three months ended March 31, 2012.

Year Ended December 31, 2011

Harvest's revenue is subject to changes in sales volumes, commodity prices and currency exchange rates. For the year ended December 31, 2011, total petroleum and natural gas sales increased by

$279.9 million. The 28% increase in annual revenues is attributable to the 10% increase in realized prices after hedging activities, the 16% increase in sales volumes and the increase in sulphur revenue from the acquired Hunt assets. Sulphur revenue represented $21.3 million (2010—$0.2 million) of the total in other revenues for the year ended December 31, 2011.

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 our Crown royalties are based on a sliding scale dependent on production volumes and commodity prices.

Three Months Ended March 31, 2012

Royalties as a percentage of gross revenue averaged 16.5% as compared to 12.8% in the same quarter of 2011. The increase is mainly due to the higher oil prices in the first quarter of 2012 combined with adjustments made to Freehold Mineral Tax estimates in the first quarter of 2011.

Year Ended December 31, 2011

The annual royalties as a percentage of gross revenue for 2011 were 15.2%, slightly below the 2010 percentage of 15.4%.

Operating and Transportation Expenses

	Three Months Ended March 31,

($000's, except where noted)	2012		$/boe		2011		$/boe		$/boe Change
Power and purchased energy		20,501		3.72		21,551		4.49		(0.77	)
Well servicing		18,520		3.36		16,912		3.52		(0.16	)
Repairs and maintenance		16,164		2.93		12,871		2.68		0.25
Lease rentals and property tax		9,520		1.73		7,768		1.62		0.11
Labor—internal		9,190		1.67		7,048		1.47		0.20
Labor—contract		5,319		0.97		4,073		0.85		0.12
Chemicals		4,584		0.83		3,826		0.80		0.03
Trucking		4,555		0.83		2,554		0.53		0.30
Processing and other fees		8,693		1.58		1,307		0.27		1.31
Other		2,929		0.52		5,685		1.19		(0.67	)

Total operating expenses		99,975		18.14		83,595		17.42		0.72

Transportation and marketing		5,686		1.03		3,003		0.63		0.40

	Year Ended December 31,

($000's, except where noted)	2011		$/boe		2010		$/boe		$/boe Change
Power and purchased energy		83,092		3.98		59,106		3.28		0.70
Well servicing		61,592		2.95		50,427		2.80		0.15
Repairs and maintenance		60,038		2.88		43,720		2.42		0.46
Lease rentals and property tax		34,728		1.66		30,637		1.70		(0.04	)
Labor—internal		28,137		1.35		22,641		1.26		0.09
Labor—contract		19,378		0.93		15,966		0.89		0.04
Chemicals		15,360		0.74		12,981		0.72		0.02
Trucking		13,261		0.64		9,645		0.53		0.11
Processing and other fees		22,643		1.09		13,538		0.75		0.34
Other		12,227		0.58		6,932		0.38		0.20

Total operating expenses		350,456		16.80		265,593		14.73		2.07

Transportation and marketing		29,626		1.42		9,394		0.52		0.90

Three Months Ended March 31, 2012

Operating expenses for the first quarter of 2012 totaled $100.0 million, an increase of $16.4 million as compared to the same quarter in the prior year. The increase in operating costs is attributable to the acquisition of Hunt assets combined with higher activity levels on well servicing and repairs and maintenance.

Operating expenses on a per barrel basis increased to $18.14/boe as compared to $17.42/boe in the first quarter of 2011. The 4% increase on a per barrel basis is substantially attributed to higher activity levels on gas processing and repairs and maintenance.

Year Ended December 31, 2011

On a year-to-date basis, operating expenses for 2011 totaled $350.5 million, an increase of $84.9 million when compared to 2010, mainly due to acquisition of assets in 2011 and higher power and purchased energy, repairs and maintenance, and well servicing costs. On a per barrel basis, year-to-date operating expenses increased by $2.07/boe (14%) which is mainly attributable to higher power and purchased energy, repairs and maintenance, and processing costs.

Power and Purchased Energy

	Three Months Ended March 31,								Year Ended December 31,

($/boe)	2012		2011			Change			2011			2010		Change
Power and purchased energy costs		3.72		4.49			(0.77	)		3.98			3.28		0.70
Realized (gains) losses on electricity risk management contracts		—		(0.47	)		0.47			(0.37	)		0.10		(0.47	)

Net power and purchased energy costs		3.72		4.02			(0.30	)		3.61			3.38		0.23

Alberta Power Pool electricity price ($/MWh)		59.76		83.34			(23.58	)		76.65			50.78		25.87

Three Months Ended March 31, 2012

Power and purchased energy costs, comprised primarily of electric power costs, represented approximately 21% of our total operating costs during the first quarter of 2012 (2011—26%). The 5% decrease in power and purchased energy costs is primarily attributable to the lower average Alberta electricity price of $59.76/MWh for the quarter (2011—$83.34/MWh).

Transportation and marketing expenses relate primarily to delivery of natural gas to Alberta's natural gas sales hub, the AECO Storage Hub, and the cost of trucking clean crude oil to pipeline receipt points. As a result, the total dollar amount of costs generally fluctuates in relation to our sales volumes. Transportation and marketing expenses increased by $0.40/boe or $2.7 million in the first quarter of 2012 compared to the same quarter in 2011, primarily due to the acquisition of Hunt assets at the end of February 2011.

Year Ended December 31, 2011

Power and purchased energy costs, comprised primarily of electric power costs, represented approximately 24% (2010—22%) of the total operating expenses for the year ended December 31, 2011. The power and purchased energy costs for the year ended December 31, 2011 totaled $83.1 million, an increase of 41% compared to 2010, mainly attributable to the higher average Alberta electricity price of $76.65/MWh for the year (2010—$50.78/MWh).

Transportation and marketing expenses relate primarily to delivery of natural gas to Alberta's natural gas sales hub, the AECO Storage Hub, and the cost of trucking clean crude oil to pipeline receipt points. As a result, the total dollar amount of costs generally fluctuates in relation to our sales volumes. The $0.90/boe or $20.2 million year-to-date increase is mainly due to Harvest incurring higher oil trucking costs at Hay River and Red Earth in response to the outage of the Plains Rainbow Pipeline during the summer of 2011 combined with the 2011 acquisition of assets.

Operating Netback⁽¹⁾

	Three Months Ended March 31,									Year Ended December 31,

($/boe)	2012			2011			Change			2011			2010			Change
Petroleum and natural gas sales prior to hedging		58.07			59.19			(1.12	)		62.13			55.85			6.28
Royalties		(9.69	)		(7.47	)		(2.22	)		(9.37	)		(8.58	)		(0.79	)
Operating expenses		(18.14	)		(17.42	)		(0.72	)		(16.80	)		(14.73	)		(2.07	)
Transportation expenses		(1.03	)		(0.63	)		(0.40	)		(1.42	)		(0.52	)		(0.90	)

Operating netback prior to hedging⁽¹⁾		29.21			33.67			(4.46	)		34.54			32.02			2.52
Hedging gains (losses)⁽²⁾		0.76			(0.17	)		0.93			(0.16	)		(0.10	)		(0.06	)

Operating netback after hedging⁽¹⁾		29.97			33.50			(3.53	)		34.38			31.92			2.46

(1): This is a non-GAAP measure; please refer to "Non-GAAP Financial Measures" in this prospectus.
(2): Hedging gains (losses) include the settlement amounts for crude oil and power contracts.

Harvest's operating netback represents the net amount realized on a per boe basis after deducting directly related costs.

Three Months Ended March 31, 2012

In the first quarter of 2012, our operating netback prior to hedging decreased by $4.46/boe or 13% compared to the same quarter in the prior year. The decrease in our operating netback is primarily attributed to lower realized commodity prices prior to hedging and increases in royalties and operating expenses.

Year Ended December 31, 2011

On an annual basis, Harvest's 2011 operating netback prior to hedging increased by $2.52/boe or 8% over 2010. The increase is primarily attributable to increases in realized commodity prices, partially offset by increases in royalties, operating expenses and transportation expenses.

General and Administrative ("G&A") Expense

	Three Months Ended March 31,				Year Ended December 31,

	2012		2011		2011		2010
G&A expenses ($000's)		12,153		13,522		60,804		45,303
G&A per boe ($/boe)		2.21		2.82		2.91		2.51

Three Months Ended March 31, 2012

For the three months ended March 31, 2012, G&A expenses decreased by $1.4 million compared to the same period in 2011. The decrease was mainly due to the reversal of a $4.3 million provision for potential renunciation shortfall on a series of flow-through shares that was no longer required, partially offset by the increase in salary expense. G&A expenses are mainly comprised of salaries and other employee related costs. Harvest does not have a stock option program, however there is a long-term cash incentive program.

Year Ended December 31, 2011

For 2011, G&A expenses increased by 34% compared to 2010. The increase in G&A is primarily due to increased salary expense, partially resulting from the acquisition of assets in 2011. Approximately 90% of the G&A expenses are related to salaries and other employee related costs. Harvest does not have a stock option program, however there is a long-term incentive program, which is a cash settled plan that has been included in the G&A expense.

Depletion, Depreciation and Amortization ("DD&A")

	Three Months Ended March 31,				Year Ended December 31,

	2012		2011		2011		2010
DD&A ($000's)		144,482		121,344		535,692		470,641
DD&A per boe ($/boe)		26.22		25.28		25.68		26.10

Three Months Ended March 31, 2012

DD&A expenses for the three months ended March 31, 2012 were $23.1 million (19%) higher compared to the same period in the prior year, mainly due to higher sales volumes.

Year Ended December 31, 2011

DD&A expenses for year ended December 31, 2011 increased by $65.1 million compared to 2010, mainly due to higher sales volumes.

Impairment

Three Months Ended March 31, 2012

In the first quarter of 2012, Harvest recorded a pre-tax impairment charge of $21.8 million against the South Alberta Gas cash generating unit, as a result of the declining forecasted natural gas prices

during the quarter. The fair value was determined based on the total proved plus probable reserves estimated by our Independent Reserves Evaluators using the April 1, 2012 commodity price forecast discounted at a pre-tax discount rate of 10%.

Year Ended December 31, 2011

No impairment charge was recognized in the year ended December 31, 2011.

Capital Asset Additions

	Three Months Ended March 31,

($000's)	2012		2011
Drilling and completion		124,679		137,599
Well equipment, pipelines and facilities		62,429		57,689
Geological and geophysical		6,723		10,800
Land and undeveloped lease rentals		8,923		5,690
Corporate		248		646
Other		4,225		2,450

Total additions before BlackGold		207,227		214,874
BlackGold oil sands ("BlackGold")
Drilling and completion		18,904		4,910
Well equipment, pipelines and facilities		8,904		17,130
Geological and geophysical		714		107
Land and undeveloped lease rentals		72		—
Other		2,771		628

Total BlackGold additions		31,365		22,775

Total additions excluding acquisitions		238,592		237,649

	Year Ended December 31,

($000's)	2011		2010
Drilling and completion		386,454		222,964
Well equipment, pipelines and facilities		195,062		107,933
Geological and geophysical		15,694		12,719
Land and undeveloped lease rentals		17,959		23,388
Corporate		2,218		1,935
Other		14,753		13,853

Total additions before BlackGold		632,140		382,792
BlackGold oil sands ("BlackGold")
Drilling and completion		23,443		70
Well equipment, pipelines and facilities		70,146		18,299
Geological and geophysical		135		445
Other		7,516		2,242

Total BlackGold additions		101,240		21,056

Total additions excluding acquisitions		733,380		403,848

Three Months Ended March 31, 2012

During the first quarter of 2012, Harvest drilled 69 gross (60.4 net) wells (2011—115 gross; 104.9 net). Capital asset additions, excluding BlackGold for the quarter totaled $207.2 million (2011—$214.9 million), of which $124.7 million was spent on drilling and completion and $39.5 million was spent on equipping and tie-in of wells. The higher drilling and completion costs per well in the first quarter of 2012 compared to 2011 is mainly due to Harvest drilling more horizontal wells into deeper zones during 2012. In addition, Harvest spent $22.8 million during the first quarter of 2012 to complete wells that were drilled in the fourth quarter of 2011.

For the quarter, Harvest mainly focused on oil drilling opportunities with only 6 gross gas wells being drilled. In Hay River, Harvest continued with the drilling program that began in November 2011 where 17 producer and 10 injector wells were drilled in the Bluesky formation. Harvest began bringing this new production on from Hay River in March 2012 and will be ramping up production through April 2012. In Red Earth, Harvest drilled 10 gross stage stimulated horizontal oil wells in the Slave Point formation. These wells were tied into existing infrastructure or were set-up as single well batteries from which Harvest began trucking production into Harvest operated facilities. In Southeast Saskatchewan, Harvest continued with drilling its 100% working interest horizontal wells, where 7 wells were drilled into the Souris Valley and Tilston formations. Harvest also drilled 3 gross stage stimulated horizontal liquids rich gas wells in the Deep Basin area. These wells were completed and tied into third party infrastructure during the quarter. The remainder of Harvest's capital program during the quarter was focused on developing our existing oil pools.

Year Ended December 31, 2011

During 2011, Harvest drilled a total of 251 gross (214.3 net) wells (2010—171 gross; 141.4 net wells) with an overall success ratio of 98%. Of the total wells drilled in 2011, Harvest drilled 180 gross (160.5 net) oil wells, 37 gross (21.0 net) gas wells, 30 gross (29.8 net) service wells and 4 gross (3.0 net) dry and abandoned wells. Capital asset additions, excluding BlackGold oil sands, for the year totaled $632.1 million (2010—$382.8 million). The increase in additions compared to 2010 is mainly due to a more active drilling program in the Corporation's large resource oil pools as well as drilling on new lands acquired from Hunt in 2011. In addition, Harvest spent approximately $80.2 million to equip and tie-in wells, $8.3 million to build a compressor station in Crossfield and $3.1 million to build a new trucking terminal in the Hay River area.

Harvest also invested in EOR projects using polymer flooding technology during the year with focus in the Wainwright and Suffield areas. Harvest expects the 2012 production to increase in these areas as a result of the polymer injection.

BlackGold oil sands

The BlackGold oil sands project continued to progress through 2011. During the fourth quarter of 2011, Harvest began drilling the surface holes for the first SAGD well pairs which are expected to be finished in early 2012. In 2011, Harvest invested a total of $101.2 million (2010—$21.1 million) in the BlackGold oil sands project for engineering and procurement and drilling of 12 observation wells as well as the construction of the central processing facility and well pads.

See "Business—Property, Plant and Equipment—Upstream—Material Properties" and "Business—Recent Developments."

Decommissioning Liabilities

Three Months Ended March 31, 2012

Harvest's Upstream decommissioning and environmental remediation liabilities at March 31, 2012 were $676.0 million (2011—$672.7 million) for future remediation, abandonment, and reclamation of Harvest's oil and gas properties. The increase of $3.2 million during the first three months of 2012 was a result of new liabilities of $4.8 million incurred on new drills and environmental remediation plus accretion of $5.0 million, partially offset by $6.6 million of remediation, abandonment and reclamation expenditures. The total of our decommissioning and environmental remediation liabilities are based on management's best estimate of costs to remediate, abandon and reclaim our wells, pipelines and facilities. The costs will be incurred over the operating lives of the assets with the majority being at or after the end of reserve life. See "—Tabular Disclosure of Contractual Obligations."

Year Ended December 31, 2011

Harvest's Upstream decommissioning liabilities at December 31, 2011 were $672.7 million (2010—$652.6 million) for future remediation, abandonment, and reclamation of Harvest's oil and gas properties. The increase of $20.1 million during 2011 was a result of $38.0 million of liabilities acquired from Hunt, new liabilities of $28.4 million incurred on new drills, accretion of $23.2 million, partially offset by a revision of estimates of $46.6 million and $22.1 million of reclamation and abandonment expenditures. The total decommissioning liabilities are based on management's best estimate of costs to remediate, reclaim, and abandon our wells and facilities. The costs will be incurred over the operating lives of the assets with the majority being at or after the end of reserve life. See "—Tabular Disclosure of Contractual Obligations."

Goodwill

Goodwill is recorded when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of that acquired business. At December 31, 2011, Harvest had $404.9 million (2010—$404.9 million) of goodwill on the balance sheet related to the Upstream segment. The goodwill balance is assessed annually for impairment or more frequently if events or changes in circumstances occur that would reasonably be expected to reduce the fair value of the acquired business to a level below its carrying amount. Management has assessed goodwill for impairment and determined that there is no impairment at December 31, 2011.

Downstream Operations

Summary of Financial and Operational Results

	Three Months Ended March 31,					Year Ended December 31,

($000's, except where noted)	2012			2011		2011			2010
FINANCIAL
Refined products sales⁽¹⁾		1,155,406			1,003,731		3,239,455			3,105,957
Purchased products for processing and resale⁽¹⁾		1,101,716			892,013		3,055,236			2,893,805

Gross margin⁽²⁾		53,690			111,718		184,219			212,152
Expenses
Operating		27,133			26,083		108,400			109,514
Power and purchased energy		47,348			27,856		117,275			106,126
Marketing		1,365			1,694		6,293			6,366
General and administrative		150			441		1,764			1,764
Depreciation and amortization		26,570			19,400		91,006			83,091

Operating income (loss)⁽²⁾		(48,876	)		36,244		(140,519	)		(94,709	)

Capital asset additions		13,263			35,879		284,244			71,234
OPERATING
Feedstock volume (bbl/d)⁽³⁾		100,000			97,438		66,417			86,142
Yield (% of throughput volume)⁽⁴⁾
Gasoline and related products		31%			32%		32%			31%
Ultra low sulphur diesel and jet fuel		43%			35%		41%			36%
High sulphur fuel oil		24%			29%		25%			31%

Total		98%			96%		98%			98%

Average refining gross margin (US$/bbl)⁽⁵⁾		4.58			10.96		5.28			5.13

(1): Refined product sales and purchased products for processing and resale are net of intra-division sales of $148.8 million for the three months ended March 31, 2012 (2011—$116.4 million), reflecting the refined products produced by the Refinery and sold by the marketing division. Refined product sales and purchased products for processing and resale are net of intra-segment sales of $507.8 million for the twelve months ended December 31, 2011 (2010—$443.6 million), reflecting the refined products produced by the Refinery and sold by the marketing division.
(2): These are non-GAAP measures; please refer to "Non-GAAP Financial Measures" in this prospectus.
(3): Barrels per day are calculated using total barrels of crude oil feedstock and vacuum gas oil.
(4): Based on production volumes after adjusting for changes in inventory held for resale.
(5): Average refining gross margin is calculated based on per barrel of feedstock throughput.

Refining Benchmark Prices

	Three Months Ended March 31,

	2012			2011			Change
WTI crude oil (US$/bbl)		102.93			94.10			9%
Brent crude oil (US$/bbl)		118.28			105.01			13%
Harvest's feedstock costs (US$/bbl)		118.24			94.95			25%
Brent—WTI differential (US$/bbl)		15.35			10.91			41%
Crack spread to Brent crude oil
RBOB (US$/bbl)		9.80			6.87			43%
Heating Oil (US$/bbl)		14.27			13.04			9%
High Sulphur Fuel Oil discount (US$/bbl)		(9.92	)		(16.42	)		(40%	)
U.S. / Canadian dollar exchange rate		0.99	9		1.01	4		(1%	)

	Year Ended December 31,

	2011			2010			Change
WTI crude oil (US$/bbl)		95.12			79.53			20%
Brent crude oil (US$/bbl)		110.89			80.40			38%
Mars premium (discount) (US$/bbl)		12.39			(1.40	)		985%
RBOB crack spread (US$/bbl)		23.40			9.58			144%
Heating Oil crack spread (US$/bbl)		29.03			10.50			176%
High Sulphur Fuel Oil premium (discount) (US$/bbl)		1.75			(8.96	)		120%
U.S. / Canadian dollar exchange rate		1.01	1		0.97	1		4%

Summary of Gross Margin

	Three Months Ended March 31,

	2012						2011
($000's, except where noted)			Volumes (000s bbls)		(US$/bbl)				Volumes (000s bbls)		(US$/bbl)
Refinery
Sales
Gasoline products		350,101		2,819		124.07		345,883		3,194		109.81
Distillates		537,661		3,996		134.42		395,340		3,261		122.93
High sulphur fuel oil		239,244		2,274		105.10		221,310		2,577		87.08

Total sales		1,127,006		9,089		123.87		962,533		9,032		108.06
Feedstock⁽¹⁾
Middle Eastern		935,854		7,946		117.66		809,752		8,648		94.95
Russian		—		—		—		1,311		14		94.95
South American		58,621		473		123.81		—		—		—

		994,475		8,419		118.00		811,063		8,662		94.95
Vacuum Gas Oil ("VGO")		82,601		681		121.17		10,050		107		95.24

Total feedstock		1,077,076		9,100		118.24		821,113		8,769		94.95
Other⁽²⁾		8,215						46,617

Total feedstock and other costs		1,085,291						867,730

Refinery gross margin⁽³⁾		41,715				4.58		94,803				10.96
Marketing
Sales		177,152						157,583
Cost of products sold		165,177						140,668

Marketing gross margin⁽³⁾		11,975						16,915

Total gross margin⁽³⁾		53,690						111,718

(1): Cost of feedstock includes all costs of transporting the crude oil to the Refinery in Newfoundland.
(2): Includes inventory adjustments and additives and blendstocks.
(3): This is a non-GAAP measure; please refer to "Non-GAAP Financial Measures" in this prospectus.

	Year Ended December 31,

	2011						2010
($000's, except where noted)			Volumes (000s bbls)		(US$/bbl)				Volumes (000s bbls)		(US$/bbl)
Refinery
Sales
Gasoline products		1,055,020		9,309		114.58		985,737		10,838		88.31
Distillates		1,385,985		11,073		126.54		1,251,160		13,188		92.12
High sulphur fuel oil		628,518		6,679		95.14		744,628		10,195		70.92

Total sales		3,069,523		27,061		114.68		2,981,525		34,221		84.60
Feedstock⁽¹⁾
Middle Eastern		2,172,600		20,938		104.90		1,713,780		21,456		77.56
Russian		178,246		1,460		123.43		485,884		5,884		80.18
South American		—		—		—		211,318		2,978		68.90

		2,350,846		22,398		106.11		2,410,982		30,318		77.22
Vacuum Gas Oil ("VGO")		220,656		1,844		120.98		95,519		1,124		82.52

Total feedstock		2,571,502		24,242		107.24		2,506,501		31,442		77.41
Other⁽²⁾		371,463						308,928

Total feedstock and other costs		2,942,965						2,815,429

Refinery gross margin⁽³⁾		126,558				5.28		166,096				5.13
Marketing
Sales		677,738						568,001
Cost of products sold		620,077						521,945

Marketing gross margin⁽³⁾		57,661						46,056

Total gross margin⁽³⁾		184,219						212,152

(1): Cost of feedstock includes all costs of transporting the crude oil to the Refinery in Newfoundland.
(2): Includes inventory adjustments, additives and blendstocks and purchase of product for local sales
(3): This is a non-GAAP measure; please refer to "Non-GAAP Financial Measures" in this prospectus.

The Downstream operations' refining gross margin is impacted by several factors including the configuration of the Refinery product yields, timing of sales under the SOA and the SOA (2011), transportation costs, location differentials, quality differentials and variability in throughput volume over a given period of time. Product pricing under the SOA and the SOA (2011) is based primarily on New York Harbour reference prices whereas feedstock costs are determined by crude oil reference prices and feedstock crude quality.

Three Months Ended March 31, 2012

Feedstock throughput averaged 100,000 bbl/d in the first quarter of 2012, a moderate increase of 3% from 97,438 bbl/d average feedstock throughput in the first quarter of the prior year. The lower crude oil throughput in 2012 as compared to 2011 has been offset by the higher consumption of purchased VGO. The lower consumption of purchased VGO in 2011 resulted from the temporary outage of the isomax and hydrogen units due to a steam leak in the hydrogen plant. Current year throughput rates are less than the nameplate capacity of 115,000 bbl/d reflecting the strategic decision to reduce rates in the latter part of the quarter in response to declining refining margins.

Our refinery sales increased by $164.5 million in the first quarter of 2012 from $962.5 million in the same quarter of 2011, mainly due to increased product prices. The cost of our crude oil feedstock in the first quarter of 2012 was US$0.04/bbl discount to the Brent crude oil benchmark as compared to a discount of US$10.06/bbl in the same period of the prior year. Our feedstock costs in 2012 continue to reflect the high cost of crude oil commitments from the fourth quarter of 2011 with such crude oil feedstocks processed early in the first quarter of 2012. The increased feedstock costs have resulted in the 56% decrease in gross margin for the three months ended March 31, 2012 as compared to 2011.

The gross margin from the marketing operations is comprised of the margin from both the retail and wholesale distribution of gasoline and home heating fuels as well as the revenues from marine services including tugboat revenues, and for 2011, the inclusion of the US$5.0 million settlement from the business interruption claim relating to the fire in the first quarter of 2010.

During the three months ended March 31, 2012, the Canadian dollar weakened as compared to the U.S. dollar. The weakening of the Canadian dollar in 2012 has had a positive impact to the contribution from our refinery operations relative to the prior year as substantially all of its gross margin, cost of purchased energy and marketing expense are denominated in U.S. dollars.

Year Ended December 31, 2011

The daily average throughput rate for the year ended December 31, 2011 is 23% lower than the prior year as a consequence of an extended planned maintenance shutdown in 2011, the pre-start-up and commissioning of the new heat exchangers for the platformer and naphtha hydrotreater units and a reduction in throughput rates in the fourth quarter of 2011 due to declining refining margins.

Refinery sales increased by $88.0 million for the year ended December 31, 2011 as compared to the prior year mainly as a result of higher market prices on refined products that have been partially offset by lower sales volumes.

The cost of feedstock for the year ended December 31, 2011 was a US$12.12/bbl premium to the benchmark WTI as compared to a discount of US$2.12/bbl in 2010. The change from a discount to a premium in 2011 is a result of the wide spread between WTI and Brent.

For the year ended December 31, 2011, refinery gross margin decreased by 24% as compared to the prior year mainly as a result of the fourth quarter negative refining margins.

The relatively strong Canadian dollar in 2011 has also reduced the contribution from our refinery operations as compared to the prior year as substantially all of the gross margin, cost of purchased energy and marketing expense are transacted in U.S. dollars.

The gross margin from the marketing operations is comprised of the margin from both the retail and wholesale distribution of gasoline and home heating fuels as well as the revenues from marine services including tugboat revenues, and for 2011, the inclusion of the US$10 million settlement from the business interruption claim relating to the fire in the first quarter of 2010.

Operating Expenses

	Three Months Ended March 31,

	2012						2011
($000's)	Refining		Marketing		Total		Refining		Marketing		Total
Operating cost		21,858		5,275		27,133		21,577		4,506		26,083
Power and purchased energy		47,348		—		47,348		27,856		—		27,856

		69,206		5,275		74,481		49,433		4,506		53,939

($/bbl of feedstock throughput)
Operating cost		2.40		—		—		2.46		—		—
Power and purchased energy		5.21		—		—		3.18		—		—

		7.61		—		—		5.64		—		—

	Year Ended December 31,

	2011						2010
($000's)	Refining		Marketing		Total		Refining		Marketing		Total
Operating cost		88,424		19,976		108,400		92,655		16,859		109,514
Power and purchased energy		117,275		—		117,275		106,126		—		106,126

		205,699		19,976		225,675		198,781		16,859		215,640

($/bbl of feedstock throughput)
Operating cost		3.65		—		—		2.95		—		—
Power and purchased energy		4.84		—		—		3.37		—		—

		8.49		—		—		6.32		—		—

Three Months Ended March 31, 2012

During the three months ended March 31, 2012, refining operating costs were comparable to the same period in the prior year with a modest increase of 1%.

Power and purchased energy, consisting of low sulphur fuel oil ("LSFO") and electricity, is required to provide heat and power to refinery operations. Power and purchased energy expenses in the first quarter of 2012 increased 70% over the first quarter of 2011 due to a volume variance of $9.2 million combined with a price variance of $10.2 million. The additional LSFO was purchased to supplement internally produced butane that normally would have been used to heat the refinery units but instead was blended with winter RBOB gasoline for sale under the SOA (2011).

Year Ended December 31, 2011

The refining operating cost per barrel of feedstock throughput increased by 24% for the year ended December 31, 2011 as compared to the same period in the prior year, reflecting lower throughput volumes in 2011. Power and purchased energy, consisting of LSFO and electricity, is required to provide heat and power to refinery operations. The power and purchased energy cost per barrel of feedstock throughput increased by 44% from the year ended December 31, 2010. The increase in costs is mainly the result of higher prices in 2011, and is partially offset by lower consumption due to lower feedstock throughput.

Capital Asset Additions

Three Months Ended March 31, 2012

Capital spending for the three months ended March 31, 2012 totaled $13.3 million (2011—$35.9 million) relating to various capital improvement projects including $3.3 million (2011—$14.6 million) for the debottlenecking project.

Year Ended December 31, 2011

Capital asset additions for the year ended December 31, 2011 totaled $284.2 million (2010—$71.2 million), relating to various capital improvement projects including $62.6 million (2010—$38.1 million), for the debottlenecking project. Other additions in 2011 include turnaround costs of $102.4 million, catalyst replacement of $32.2 million, tubing and piping replacement of $26.0 million and other significant capital work completed during the turnaround period.

Depreciation and Amortization Expense

	Three Months Ended March 31,				Year Ended December 31,

($000's)	2012		2011		2011		2010
Refining		25,609		18,479		87,346		79,615
Marketing		961		921		3,660		3,476

Total depreciation and amortization		26,570		19,400		91,006		83,091

The process units are amortized over an average useful life of 20 to 30 years and turnaround costs are amortized to the next scheduled turnaround. The increase in refining depreciation in 2011 as compared to 2010 is a consequence of the increased capital and turnaround expenditures completed during the year.

Decommissioning Liabilities

Harvest's Downstream decommissioning liabilities result from our ownership of the Refinery and marketing assets. At December 31, 2011, Harvest's Downstream decommissioning liabilities were $14.6 million (2010—$10.4 million), relating to the reclamation and abandonment of these assets with an expected abandonment date of 2069.

Corporate

Cash Flow Risk Management

Three Months Ended March 31, 2012

Harvest uses electricity price swap contracts to manage some of its price risk exposure. These swap contracts are not designated as hedges and are entered into for periods consistent with forecast electricity purchases. Harvest did not have any electricity price swap contacts during the three months ended March 31, 2012.

consistent with the forecast petroleum sales. The following is a summary of Harvest's risk management contracts outstanding at March 31, 2012:

As at March 31, 2012

Contract Quantity	Type of Contract	Term	Contract Price	Fair Value
4,200 bbls/day	Crude oil price swap	Apr – Dec 2012	US$111.37/bbl	$	10,578
US$468/day	Foreign exchange swap	Apr – Dec 2012	$1.0236 Cdn/US		67

				$	10,645

The following is a summary of Harvest's realized and unrealized (gains) losses on risk management contracts:

	Three Months Ended March 31,

	2012								2011
($000's)	Power		Currency			Total			Power			Currency		Total
Contracts not designated as hedges	Power		Currency			Total			Power			Currency		Total
Realized gains		—		—			—			(2,282	)		—		(2,282	)
Unrealized (gains) losses		—		(66	)		(66	)		(3,554	)		29		(3,525	)

(Gains) losses recognized in net income		—		(66	)		(66	)		(5,836	)		29		(5,807	)
Contracts designated as hedges						Crude Oil								Crude Oil
Realized (gains) losses
Reclassified from OCI to revenues, net of tax							(3,126	)							2,224
Ineffective portion recognized in net income							—								59

							(3,126	)							2,283
Unrealized (gains) losses
Recognized in OCI, net of tax							4,195								42,631
Ineffective portion recognized in net income							(205	)							285

							3,990								42,916
Net losses recognized in OCI							7,321								40,407
Net (gains) losses recognized in revenues							(3,126	)							2,224
Net gains recognized in net income outside of revenues							(271	)							(5,463	)

Year Ended December 31, 2011

The Corporation enters into crude oil and foreign exchange contracts to reduce the volatility of cash flows from some of its forecast sales. Harvest designates all of its crude oil derivative contracts and certain foreign exchange contracts as cash flow hedges, which are entered into for periods consistent with the forecast petroleum sales. Harvest also enters into 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 following is a summary of Harvest's risk management contracts outstanding at December 31, 2011:

As at December 31, 2011

Contract Quantity	Type of Contract	Term		Contract Price	Fair Value
4,200 bbls/day	Crude oil price swap		2012	US$111.37/bbl	$	19,718
US$468/day	Foreign exchange swap		2012	$1.0236 Cdn/US		444

					$	20,162

Any gains and losses recognized on risk management contracts are generally recorded in net income except for when hedge accounting is applied. When risk management contracts qualify for hedge accounting, the fair value of the hedges is recorded in risk management contracts assets or liabilities. The changes in the fair value are reported in other comprehensive income ("OCI") until the settlement of the contracts, except for the ineffective portion of the changes which is reported in net income. Upon settlement of the contracts, the gains or losses previously reported in OCI are reclassified to net income.

The following is a summary of Harvest's realized and unrealized (gains) losses on risk management contracts:

	Year Ended December 31,

	2011								2010
($000's)	2011								2010
($000's)	Power			Currency		Total			Power			Currency		Total
Contracts not designated as hedges	Power			Currency		Total			Power			Currency		Total
Realized (gains) losses		(7,730	)		—		(7,730	)		1,808			—		1,808
Unrealized (gains) losses		1,008			—		1,008			(3,060	)		—		(3,060	)

(Gains) losses recognized in net income		(6,722	)		—		(6,722	)		(1,252	)		—		(1,252	)
Contracts designated as hedges						Crude Oil								Crude Oil
Realized (gains) losses
Reclassified from OCI to revenues, net of tax							7,050								—
Ineffective portion recognized in net income							1,730								—

							8,780								—
Unrealized (gains) losses
Recognized in OCI, net of tax							(12,371	)							5,020
Ineffective portion recognized in net income							(1,754	)							702

							(14,125	)							5,722
Net (gains) losses recognized in net income outside of revenues							(6,746	)							(550	)

Financing Costs

	Three Months Ended March 31,						Year Ended December 31,

($000's)	2012			2011			2011			2010
Bank loan		3,463			1,633			7,972			4,947
Convertible debentures		12,332			12,327			49,706			51,926
Senior notes		9,025			8,776			35,657			20,897
Amortization of deferred finance charges		255			281			881			750

Interest and other financing charges		25,075			23,017			94,216			78,520
Capitalized interest		(2,892	)		(1,296	)		(8,640	)		(397	)

		22,183			21,721			85,576			78,123
Accretion of decommissioning liabilities		5,153			5,796			23,551			22,685

Total finance costs		27,336			27,517			109,127			100,808

Three Months Ended March 31, 2012

Interest and other financing charges, including the amortization of related financing costs, increased by $2.1 million (9%) compared to the three months ended March 31, 2012, mainly due to the increased interest expense on Harvest's bank loan as a result of the increased amount of loan principal outstanding. During the quarter, interest charges on our bank loan reflected an effective interest rate of 2.84% (2011—3.06%).

Year Ended December 31, 2011

Interest and other financing charges for the year ended December 31, 2011, including the amortization of related financing costs, increased $15.7 million (20%) respectively compared to 2010.

Interest expense on Harvest's bank loan for the twelve months ended December 31, 2011 increased by $3.0 million due to the increase in the amount of loan principal outstanding. The effective interest rate for interest charges on our bank loan for the year ended December 31, 2011 was 3.03% compared to 3.65% in 2010.

Interest expense on the notes increased by 71% for the year ended December 31, 2011 compared to 2010. The increase is due to the higher principal balance of the notes issued in the fourth quarter of 2010, as compared to the 7⁷/8% senior notes that were fully redeemed by the end of 2010.

During the year ended December 31, 2011, interest expense of $8.6 was capitalized to the BlackGold project and the Downstream debottlenecking project (2010—$0.4 million).

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 notes and on any U.S. dollar denominated monetary assets or liabilities.

The cumulative translation adjustment recognized in other comprehensive income results from the translation of the Downstream operation's U.S. dollar functional currency financial statements to Canadian dollars.

Three Months Ended March 31, 2012

At March 31, 2012, the Canadian dollar relative to the U.S. dollar strengthened compared to December 31, 2011, resulting in an unrealized foreign exchange gain of $2.8 million (2011—$9.6 million

gain) for the three months ended March 31, 2012. Harvest recognized a realized foreign exchange loss of $1.6 million for the three months ended March 31, 2012 (2011—$0.2 million gain) as a result of the settlement of U.S. dollar denominated transactions.

During the first quarter of 2012, Downstream recognized a net cumulative translation loss of $16.1 million (2011—$23.9 million loss), which resulted from the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2012 compared to December 31, 2011. As Downstream's functional currency is U.S. dollars, the weakening of the U.S. dollar would result in losses from decommissioning liabilities, pension obligations, accounts payable and other balances that are denominated in Canadian dollars, which partially offset the unrealized gains recognized on the notes and Upstream U.S. dollar denominated monetary items.

Year Ended December 31, 2011

For the year of 2011, Harvest recognized an unrealized foreign exchange loss of $2.6 million (2010—$1.9 million gain) as a result of the weakening of the Canadian dollar relative to the U.S. dollar from $0.99 Cdn/U.S. at December 31, 2010 to $1.02 Cdn/U.S. at December 31, 2011. Harvest recognized a realized foreign exchange gain of $6.5 million (2010—$1.5 million gain) for the year ended December 31, 2011 as a result of the settlement of U.S. dollar denominated transactions.

For the year ended December 31, 2011, Downstream operations recognized a net cumulative translation gain of $21.5 million (2010—loss of $45.9 million). The Canadian dollar relative to the U.S. dollar weakened at December 31, 2011 compared to December 31, 2010, resulting in a net cumulative translation gain for the year of 2011. As Downstream operations' functional currency is denominated in U.S. dollars, the strengthening of the U.S. dollar would result in gains from decommissioning liabilities, pension obligations, accounts payable and other balances that are denominated in Canadian dollars, which partially offset the unrealized losses recognized on the notes and Upstream U.S. dollar denominated monetary items.

Deferred Income Taxes

Our deferred income tax liability will fluctuate during each accounting period to reflect changes in the temporary differences between the book value and tax basis of assets as well as legislative tax rate changes. Currently, the principal source of our temporary differences is the net book value of the Corporation's property, plant and equipment and the unclaimed tax pools.

Three Months Ended March 31, 2012

For the three months ended March 31, 2012, Harvest recorded a deferred income tax recovery of $22.7 million (2011—expense of $3.8 million).

Year Ended December 31, 2011

For the year ended December 31, 2011, Harvest recorded a deferred income tax recovery of $29.9 million (2010—recovery of $65.1 million).

Liquidity and Capital Resources

Liquidity

Harvest manages its cash requirements by optimizing the capital structure of the Corporation and maintaining sufficient liquid financial resources to cost-effectively fund obligations as they come due. The Corporation's liquidity needs are met through the following sources: cash generated from operations, borrowings under the 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.

Three Months Ended March 31, 2012

For the three months ended March 31, 2012, cash flow from operating activities was $85.1 million (2011—$146.8 million) including $7.7 million (2011—$32.8 million) used in reducing non-cash working capital and $6.6 million (2011—$2.0 million) used in the settlement of decommissioning and environmental remediation liabilities. At March 31, 2012, Harvest's financing activities provided $175.8 million (2011—$524.1 million) of cash from net borrowings from the Credit Facility. Harvest funded $249.9 million (2011—$275.6 million) of capital expenditures and net asset acquisition activity during the first quarter of 2012 with cash generated from operating activities and financing activities.

Harvest had a working capital deficiency of $258.7 million at March 31, 2012, as compared to a $265.6 million deficiency at December 31, 2011. The slight improvement in our working capital deficiency at March 31, 2012 compared to December 31, 2011 was primarily due to the decrease in accrued liabilities relating to capital expenditures during the period. 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 the Credit Facility, as required.

Through a combination of cash available at March 31, 2012, cash from operating activities and the available undrawn amount from the Credit Facility, it is anticipated that Harvest will have adequate liquidity to fund future operations, debt repayments and forecasted capital expenditures (excluding major acquisitions).

BlackGold Oil Sands Project

Harvest signed an engineering, procurement and construction ("EPC") contract in 2010 for phase 1 of the BlackGold project, of which $98.2 million (including a $31.1 million deposit) has been paid to the end of March 31, 2012. Together with capital expenditures relating to drilling and completion of 17 wells, Harvest has invested $153.7 million since acquiring the assets in 2010. For 2012, $215 million of the capital expenditure program is allocated to the continued development of BlackGold. Harvest plans to fund the capital expenditures with cash flows from operating activities and the undrawn amount from the Credit Facility.

The Corporation is engaging in an active drilling program under which the drilling of 30 wells (15 well pairs) is expected to be completed by the end of 2012. Five wells were drilled during the first quarter of 2012. Engineering of the project is now 70% complete and the site has been cleared and graded. Other near-term activities include completion of the detailed engineering work, site preparation and the commencement of major equipment fabrication. Phase 2 of the project, which is targeted to increase production capacity to 30,000 bbl/d, is in the regulatory approval process and approval is anticipated in 2012.

The BlackGold project faces similar cost and schedule pressures as other oil sand projects, including shortage of skilled labor, rising costs, and logistics issues surrounding module transportation; phase 1 production is now expected to start in 2014. As a result of these pressures, Harvest is actively reviewing changes to the EPC contract terms with the contractor and revising methods to execute the project; these changes are expected to result in material increases to the project cost.

Year Ended December 31, 2011

Cash flow from operating activities for the year ended December 31, 2011 was $560.5 million, compared to $439.2 million in 2010. For the year ended December 31, 2011, the change in non-cash working capital relating to operating activities was a surplus of $51.1 million (2010—surplus of

$32.3 million), and $22.1 million (2010—$20.3 million) was incurred in the settlement of decommissioning liabilities. During 2011, Harvest's financing activities provided $848.8 million of cash, including $505.4 million of capital injection from KNOC and $343.3 million of net borrowings from the Credit Facility. Harvest funded $1,013.2 million of capital additions and net asset acquisition activities in 2011 with cash generated from operating activities and financing activities. The acquisition of the Hunt assets in 2011 was funded primarily by the capital injection from KNOC.

Harvest had a working capital deficiency of $265.6 million as at December 31, 2011, as compared to a $20.3 million deficiency at December 31, 2010. The negative working capital in 2011 was primarily related to the classification of $107.1 million of Debentures as current liabilities, the use of the $40 million deposit paid in 2010 for the Hunt assets acquisition, and accrued liabilities relating to capital expenditures during the period, partially offset by increased assets arising from the risk management contracts. 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 the Credit Facility, as required.

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 enters into risk management contracts (see "—Cash Flow Risk Management") to protect the Corporation from cash flow fluctuations due to commodity price changes.

Through a combination of cash available at December 31, 2011, cash from operating activities and undrawn amounts from the Credit Facility, Harvest will have adequate liquidity to fund future operations, debt repayments and forecasted capital expenditures (excluding any major acquisitions). Harvest's 2012 capital program, excluding acquisitions for Upstream and Downstream, is budgeted to be $770 million. Harvest has the ability to modify our capital program in response to changes in commodity prices, market conditions, and cash flows. See "—Tabular Disclosure of Contractual Obligations" for Harvest's future commitments including the maturity of our existing debt and our capital commitments. For information on risks associated with Harvest liquidity, see "Risk Factors."

Capital Resources

The following table summarizes the Corporation's capital structure as at March 31, 2012, December 31, 2011 and 2010:

			As at December 31,

	As at March 31, 2012		As at December 31,
($000's, except where noted)	As at March 31, 2012		2011		2010
Debts
Bank loan⁽¹⁾		534,675		358,885		14,000
Convertible debentures, at principal amount		733,973		733,973		733,973
Senior notes, at principal amount (US$500 million)⁽²⁾		498,750		508,500		497,300

		1,767,398		1,601,358		1,245,273
Shareholder's Equity
386,078,649 common shares issued at March 31, 2012 and December 31, 2011⁽³⁾		3,355,333		3,453,644		—
335,535,047 common shares issued at December 31, 2010		—		—		3,016,855

		5,122,731		5,055,002		4,262,128

Financial Ratios⁽⁴⁾⁽⁵⁾
Secured Debt to Annualized EBITDA⁽⁶⁾		1.18		0.73		0.06
Total Debt to Annualized EBITDA⁽⁷⁾		3.48		2.72		2.39
Secured Debt to Total Capitalization⁽⁶⁾⁽⁸⁾		13%		10%		1%
Total Debt to Total Capitalization⁽⁷⁾⁽⁸⁾		39%		36%		31%

(1): The bank loan net of deferred financing costs is $531.6 million (2011—$355.6 million; 2010—$11.4 million).
(2): Principal amount converted at the period end exchange rate.
(3): As at June 13, 2012, the number of common shares issued is 386,078,649.
(4): Calculated based on the Credit Facility covenant requirements (see note 10 of the December 31, 2011 financial statements).
(5): The financial ratios and their components are non-GAAP measures; please refer to the "Non-GAAP Financial Measures" section of this prospectus.
(6): Secured debt includes bank loan of $531.6 million (2011—$355.6 million; 2010—$11.4 million), letters of credit of $8.7 million (2011—$8.7 million; 2010—$2.5 million), and guarantees of $90.3 million (2011—$92.1 million; 2010—$15.1 million) at March 31, 2012.
(7): Total debt includes the secured debt, Debentures of $741.2 million (2011—$742.1 million; 2010—$745.3 million) and the notes of $486.6 million (2011—$495.7 million; 2010—$482.4 million) at March 31, 2012.
(8): Total capitalization includes total debt and shareholder's equity less equity attributed to BlackGold of $458.9 million (2011—$459.9 million; 2010—$459.9 million) at March 31, 2012.

The outstanding securities of Harvest consist of the common shares, notes and Debentures.

The authorized capital consists of an unlimited number of common shares. All of the outstanding common shares are held by KNOC.

The most significant restrictions on dividends which can be paid by Harvest exist under the Credit Facility pursuant to provisions restricting Distributions (as defined thereunder). Distributions include dividends on Harvest shares. Under those restrictions, a dividend can be paid as follows:

1.: Debt/EBITDA basis: if the Total Debt to EBITDA Ratio after such dividend will not exceed 2.5:1 (including for the purposes of calculations for the ratio, any debt to fund the dividend);

2.: Cash flow basis: if the aggregate amount of that dividend and any other Distributions previously paid is less than the amount of EBITDA in excess of aggregate capital expenditures. The aggregate Distributions and aggregate capital expenditures are calculated with respect to a period including the current and three prior fiscal quarters and EBITDA is calculated for the four most recent fiscal quarters; and
3.: Stipulated amount basis: on the basis of an aggregate amount of Distributions since April 29, 2011 not to exceed $100 million.

For the purposes of these calculations, all Distributions by Harvest and restricted subsidiaries are included, and similarly capital expenditures are those of Harvest and restricted subsidiaries.

As of December 31, 2011, the Debt/EBITDA restriction and the cash flow restriction as described above resulted in no amount of allowed dividends payable by Harvest. However, on the stipulated amount basis, Harvest would be permitted to pay dividends up to $100 million, since no Distribution has been made since April 29, 2011.

Bank Loan

As at December 31, 2011, Harvest had $441.1 million of unutilized borrowing capacity under the Credit Facility. The unused borrowing capacity and the option to increase the capacity limit to $1.0 billion provide Harvest the flexibility to manage fluctuations in its liquidity needs. See Note 10 of the audited consolidated financial statements for the year ended December 31, 2011, which has been included elsewhere in this prospectus.

Convertible Debentures

At December 31, 2011, Harvest had $734.0 million (2010—$734.0 million) of principal amount of Debentures issued in four series with the earliest maturity date in 2012. As a result of KNOC'S acquisition of Harvest Energy Trust in 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. 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. After the second redemption period, the debentures are redeemable at par. Any redemption will include accrued and unpaid interest at such time. Please refer to note 12 of the audited consolidated financial statements for the year ended December 31, 2011 included elsewhere in this prospectus for details of the redemption periods.

The 6.4% Debentures Due 2012 with a face value of $106.8 million will be maturing on October 31, 2012. Harvest plans to repay the debenture holders on maturity date through a combination of cash on hand, incremental borrowing from the Credit Facility, debt issuance and capital injection.

Senior Notes

On October 4, 2010 Harvest issued the initial notes, which are governed by the terms and conditions of the Note Indenture. See "Description of Notes." Harvest had $508.5 million (2010—$497.3 million) of principal amount of notes outstanding at December 31, 2011. These notes are guaranteed by all of Harvest's existing and future restricted subsidiaries that guarantee the Credit Facility and future restricted subsidiaries that guarantee certain debt. Prior to maturity, redemptions are permitted in whole or in part, at any time at a redemption price equal to the greater of 100% of the

principal amount redeemed and the make-whole redemption premium plus any unpaid interest to the redemption date. Harvest may also redeem all of the notes at any time in the event that certain changes affecting Canadian withholding taxes occur.

Research and Development

We did not conduct significant research and development activities in 2011.

Trend Information

Harvest continues to be subject to variation in energy commodity prices. Prices for natural gas have declined significantly since the end of 2011 due to increased North American supply and mild winter weather. Harvest has responded, along with other producers, by shutting in some natural gas production with higher operating costs and focusing its capital spending program on oil and liquids-rich gas. The forward markets indicate a gradual increase in natural gas prices over the next several years; actual prices will depend on the usual factors such as weather, demand, supply and several other issues, all of which are beyond Harvest's control. High levels of industry operating activity continue to put upward pressure on operating and capital costs and this trend is expected to continue. Despite low natural gas prices, strong pricing for natural gas liquids and corresponding higher production levels have resulted in some restrictions to processing capacity through third party gas plants. Harvest continues to work with third party gas plant operators but expects some periodic interruption of natural gas and natural gas liquid production over the next few years until new capacity is brought on line. Harvest and third party infrastructure, particularly pipelines, require ongoing maintenance and replacement due to corrosion and age. Harvest will continue to invest capital in these projects to support base production in our more mature fields. In the Downstream segment, product crack spreads have been narrow and refinery margins are expected to remain tight under pressure. Feedstock acquisition costs are high due to global reference benchmark prices, while product prices, particularly gasoline, remain low due to demand destruction and slow demand recovery.

The above trend information is based on assumptions that management believes to be reasonable in the light of the group's operational and financial experience. However, no assurance can be given that the above trends will be realized. You should not rely on past performance as an indicator of future performance. See "Risk Factors."

Outlook

Harvest actively monitors commodity prices and overall market conditions on an ongoing basis and will continue to manage commodity price volatility through a combination of prudent capital expenditures funded largely through operating cash flows, maintaining a solid balance sheet and hedging commodity prices as appropriate to support our strategy.

Upstream

Three Months Ended March 31, 2012

During the first quarter of 2012, Harvest's Upstream operations (excluding BlackGlold) spent $207 million of the $435 million 2012 capital budget. Harvest drilled 69 (60.4 net) wells and intends to drill an additional 86 wells during the remainder of 2012. The majority of the capital spending and drilling activity takes place within the first few months of the year as we have a very active winter drilling program.

Harvest will continue to concentrate activity on our oil weighted assets which include large pools of light/medium and heavy crude oils that have significant opportunity for development through drilling or optimization. These are complemented by our liquids-rich natural gas opportunities with attractive

economics, despite low natural gas prices. Production during the first quarter of 60,550 boe/d exceeded expectations. We maintain production guidance of 60,000 boe/d for 2012, weighted approximately 30-35% percent natural gas and 65-70% percent crude oil and NGLs.

There have been no changes to the previously reported royalty, general and administrative and operating costs guidance. We anticipate royalties to be approximately 16% of revenue, general and administrative costs to average $2.80/boe and operating costs to average approximately $16.50/boe in 2012.

Harvest has allocated 2012 capital spending of $215 million for the BlackGold oil sands project, of which $31.4 million has been spent in the first quarter of 2012. The 2012 activities for the BlackGold team will be module assembly, facility construction and an active drilling program of 30 wells (15 SAGD well pairs). First oil production from phase 1 is expected in 2014 and we anticipate ERCB approval in 2012 for an additional 20,000 bbl/d for phase 2 expansion of the project.

Year Ended December 31, 2011

Harvest's Upstream operations (excluding BlackGold) has a capital budget of approximately $435 million for 2012. Of the Upstream budget, approximately 65% will be allocated to drilling activities. Harvest plans to drill 155 wells in 2012 with the majority of the activity taking place within the first few months of the year in a very active winter drilling program. We will also continue investing in Enhanced Oil Recovery ("EOR") and optimization activities with approximately 15% of the Upstream budget.

Our focus will continue to be on our oil weighted and NGLs rich natural gas assets as our asset base is predominantly large pools of light/medium and heavy crude oils that have significant opportunity for development through drilling or optimization. This is complemented by liquids-rich natural gas opportunities with attractive economics, despite low natural gas prices. We expect production volume from the Upstream operations to average 60,000 boe/d for 2012, weighted approximately 30% percent natural gas and 70% percent crude oil and NGLs.

Cost guidance for 2012 includes royalties at 16% of revenue, general & administrative costs averaging $2.80/boe and operating costs to average approximately $16.50/boe.

Harvest has allocated 2012 capital spending of $215 million for the BlackGold oil sands project. The 2012 activities for the BlackGold team will be module assembly, facility construction and an active drilling program in which 30 wells (15 SAGD well pairs) are currently underway. First oil production of 10,000 bbl/d is expected in 2014 and we anticipate ERCB approval in 2012 for an additional 20,000 bbl/d for phase 2 expansion of the project.

Downstream

Three Months Ended March 31, 2012

Harvest's Downstream operations has revised the 2012 capital budget from $120 million to $84 million as a result of deferring certain discretionary projects from 2012 to later years. Of the revised budget, approximately 25% is earmarked for a crude tank and engineering on projects involving low cost and simple debottlenecking of existing process units. Approximately 50% of the budget will be used for mandatory maintenance projects with the remainder on smaller value-add projects.

Throughput in the first quarter of 2012 was 100,000 bbl/d. Throughput volume is expected to average 100,000 to 106,000 bbl/d in 2012, with operating costs and purchased energy costs aggregating to approximately $8.00/bbl.

Year Ended December 31, 2011

Harvest's Downstream operations have a 2012 capital budget of $120 million. Approximately 50% is earmarked for projects involving low cost and simple debottlenecking of existing process units and tanks to enhance distillate yields and improve operating costs, energy efficiency and operating reliability. We have also budgeted approximately 25% for mandatory maintenance projects with the remainder on smaller value-add projects.

Harvest anticipates throughput volume to average 100,000 to 106,000 bbl/d in 2012, with operating costs and purchased energy costs aggregating to approximately $7.00/bbl.

Corporate

Three Months Ended March 31, 2012

In October of this year, the 6.40% Debentures Due 2012 (TSX: HTE.DB.D) will mature. The principal amount outstanding at the end of the first quarter is $106.8 million. The debentures may be redeemed at the Corporation's option in whole or in part prior to maturity at 100% of the face value. On redemption, Harvest will repay the indebtedness through a combination of cash on hand, draws on the Credit Facility, debt issuance and capital injection.

Harvest mitigates commodity 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. Harvest's cash flow risk management strategies are financially integrated, reflecting that the commodity price risk of its Upstream cash flows from producing crude oil is partially financially offset partially by its requirement to purchase crude oil feedstock for the Downstream even though the crude oil produced by the Upstream does not physically flow to the Refinery in Newfoundland.

Year Ended December 31, 2011

Harvest maintains a strong credit rating and healthy balance sheet which includes our Debentures, notes, and the Credit Facility, balanced with KNOC-held equity. Our exposure to interest rate fluctuations will continue to be managed through maintaining a mix of financing that carries both floating and fixed interest rates. We will extend maturities as appropriate when our obligations mature or become eligible for repayment.

At December 31, 2011, Harvest had $734.0 million of principal amount of Debentures issued in four series. On October 31, 2012, Harvest's 6.40% Debentures Due 2012 (TSX: HTE.DB.D) will mature in the amount of $106.8 million. This series of debentures is currently redeemable at par, as are next year's maturing series of 7.25% debentures. At maturity, Harvest plans to repay the indebtedness through a combination of cash on hand, undrawn amounts from the Credit Facility, debit issuance and capital injection.

While we do not speculate on commodity prices or refining margin, we do enter into risk management contracts from time-to-time to mitigate some portion of our price volatility with the objective of stabilizing our cash flow from operating activities. For the remainder of 2012, we have 4,200 bbl/d of WTI hedges under contract with an average price of US$111.37/bbl.

Future development activities and acquisitions in our Upstream business, as well as the maintenance and optimization program in our Downstream business, will be funded substantially from cash generated by operating activities. Funding of more significant acquisitions and growth initiatives will generally rely on a combination of cash from operating activities, incremental debt and capital injections from KNOC.

Harvest is focused on environmental, health and safety issues both in the Upstream and in the Downstream segments of our business. We use responsible practices to ensure the protection of people and the environment. Safety is at the core of our operations and is of utmost importance as we strive to always protect our people, our neighbors and the environment that we all share. As a result, we continue to show better than industry average performance on many EH&S measures in our businesses.

Off-Balance Sheet Arrangements

As of March 31, 2012 and December 31, 2011, we had no off-balance sheet arrangements in place.

Tabular Disclosure of Contractual Obligations

Harvest has recurring and ongoing contractual obligations and commitments entered into in the normal course of operations including the purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, and land lease obligations.

As at March 31, 2012, Harvest has the following significant contractual commitments:

	Payments Due by Period

($000's)	1 year		2-3 years		4-5 years		After 5 years		Total
Debt repayments⁽¹⁾		106,796		390,598		771,254		498,750		1,767,398
Debt interest payments⁽¹⁾		106,158		145,976		75,646		19,288		347,068
Purchase commitments⁽²⁾		222,988		42,144		—		—		265,132
Operating leases		12,100		19,713		7,224		2,358		41,395
Transportation agreements⁽³⁾		8,803		12,808		4,186		237		26,034
Feedstock and other purchase commitments⁽⁴⁾		940,304		—		—		—		940,304
Employee benefits⁽⁵⁾		4,102		7,433		5,178		2,877		19,590
Decommissioning liabilities⁽⁶⁾		16,687		53,884		34,343		1,349,810		1,454,724

Total		1,417,938		672,556		897,831		1,873,320		4,861,645

(1): Assumes constant foreign exchange rate.
(2): Relates to drilling commitments, AFE commitments, BlackGold capital commitment and Downstream capital commitments.
(3): Relates to firm transportation commitments.
(4): Includes commitments to purchase refinery crude stock and refined products for resale under the SOA (2011).
(5): Relates to the expected contributions to employee benefit plans and long-term incentive plan payments.
(6): Represents the undiscounted obligation by period.

As at the end of December 31, 2011, Harvest has the following significant contractual commitments:

	Payments Due by Period

($000's)	1 year		2-3 years		4-5 years		After 5 years		Total
Debt repayments⁽¹⁾		106,796		390,598		595,464		508,500		1,601,358
Debt interest payments⁽¹⁾		92,360		139,745		79,182		26,220		337,507
Purchase commitments⁽²⁾		207,207		48,409		1,143		—		256,759
Operating leases		9,368		15,267		2,187		564		27,386
Transportation agreements⁽³⁾		13,936		22,606		9,680		317		46,539
Feedstock and other purchase commitments⁽⁴⁾		776,092		—		—		—		776,092
Employee benefits⁽⁵⁾		4,534		7,828		4,944		3,837		21,143
Decommissioning liabilities⁽⁶⁾		12,782		58,989		33,805		1,343,584		1,449,160

Total		1,223,075		683,442		726,405		1,883,022		4,515,944

(1): Assumes constant foreign exchange rate.
(2): Relates to drilling commitments, AFE commitments, BlackGold capital commitment and Downstream capital commitments.
(3): Relates to firm transportation commitments.
(4): Includes commitments to purchase refinery crude stock and refined products for resale under the SOA (2011) with MEC.
(5): Relates to the expected contributions to employee benefit plans and employee long-term incentive plan payments.
(6): Represents the undiscounted obligation by period.

Quantitative and Qualitative Disclosures About Market Risk and Uncertainties

Harvest is exposed to three types of market risks: interest rate risk, currency exchange rate risk and commodity price risk. All market risk sensitive instruments are entered into for purposes other than trading.

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 Corporation's secured debt to EBITDA. Harvest's Debentures and the 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.

If the interest rate applicable to Harvest's bank borrowings at December 31, 2011 increased or decreased by 25% with all other variables held constant, after-tax net income for the year would decrease by $0.1 million and increase by $0.9 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, the 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's Downstream operations operate with a U.S. dollar functional currency which gives rise to currency exchange rate risk on the Corporation's Canadian dollar denominated monetary assets and liabilities such as Canadian dollar bank accounts and accounts receivable and payable. Harvest is also exposed to currency exchange rate risk on its net investment in its Downstream operations. 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.

At December 31, 2011, if the U.S. dollar strengthened or weakened by 10% 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:

($000's)

U.S. Dollar Exchange Rate—10% increase	(19,870	)	(34,754	)
U.S. Dollar Exchange Rate—10% decrease	19,870		34,754

(1): The sensitivity to net income and other comprehensive income is done independently.

Commodity Price Risk

Harvest is exposed to electricity, crude oil and natural gas price movements as part of its normal business operations. The Corporation uses price risk management contracts to protect a portion of the Corporation's future cash flows and net income against unfavorable movements in commodity prices. These contracts are recorded on the consolidated statement of financial position 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, the pre-tax impact would be as follows:

	As at December 31, 2011

($000's)	Increase (decrease) in Net Income			Increase (decrease) in Other Comprehensive Income
Forward price of crude oil—10% increase		(1,020	)		(18,517	)
Forward price of crude oil—10% decrease		621			11,390

Harvest uses electricity price swap contracts to manage some of its price risk exposure. These swap contracts are not designated as hedges and are entered into for periods consistent with forecast electricity purchases. The Corporation enters into crude oil and foreign exchange contracts to reduce the volatility of cash flows from some of its forecast sales. Harvest designates all of its crude oil

derivative contracts and certain foreign exchange contracts as cash flow hedges. Harvest did not have any electricity price swap contracts during the three months ended March 31, 2012.

Contracts Designated as Hedges

The following is a summary of Harvest's risk management contracts.

As at March 31, 2012

Contract Quantity	Type of Contract	Term	Contract Price	Fair Value
4,200 bbls/day	Crude oil price swap	Apr – Dec 2012	US$111.37/bbl	$	10,578
US$468/day	Foreign exchange swap	Apr – Dec 2012	$1.0236 Cdn/US		67

				$	10,645

As at December 31, 2011

Contract Quantity	Type of Contract	Term	Contract Price	Fair Value
4,200 bbls/day	Crude oil price swap	2012	US$111.37/bbl	$	19,718
US$468/day	Foreign exchange swap	2012	$1.0236 Cdn/US		444

				$	20,162

Contracts not Designated as Hedges

At December 31, 2011, there were no contracts that were not designated as hedges.

As at December 31, 2010

Contract Quantity	Type of Contract	Term	Contract Price	Fair Value
30 MWh	Electricity price swap contracts	2011	$46.87	$	1,007

Harvest's maximum exposure to credit risk relating to financial assets at December 31, 2011 is the carrying value of accounts receivable. The table below provides an analysis of Harvest's current and past due but not impaired receivables.

	As at December 31, 2011

($000's)	Current AR		<30 days		Overdue AR >30 days, <60 days		>60 days, <90 days		>90 days
Upstream accounts receivable	$	146,164	$	1,286	$	556	$	1,168	$	4,000
Downstream accounts receivable		50,660		6,155		1,702		206		355

	$	196,824	$	7,441	$	2,258	$	1,374	$	4,355	⁽¹⁾

(1): Net of $3.3 million of allowance for doubtful accounts.

The following table provides an analysis of Harvest's financial liability maturities based on the remaining terms of its liabilities as at December 31, 2011, and includes the related interest charges:

	As at December 31, 2011

($000's)	<1 year		>1 year <3 years		>3 years <5 years		>5 years		Total
Accounts payable and accrued liabilities	$	464,148	$	—	$	—	$	—	$	464,148
Bank loan and interest		5,643		11,287		360,756		—		377,686
Convertible debentures and interest		158,554		449,138		243,972		—		851,664
6⁷/8% senior notes and interest		34,959		69,919		69,919		534,720		709,517
Guarantees⁽¹⁾		47,004		—		—		—		47,004

	$	710,308	$	530,344	$	674,647	$	534,720	$	2,450,019

(1): Amounts are net of the related payables and receivables to and from counterparties.

BUSINESS

Recent Developments

Equity

In 2011, Harvest issued $505.4 million of equity to KNOC to fund the acquisition of assets from Hunt. See the Capital Expenditures section below for more details.

Credit Facility

Capital Expenditures

The following table provides a summary of Harvest's capital expenditures in accordance with IFRS for the last two years ended December 31:

	Year Ended December 31,

($000's)	2011			2010
Upstream capital expenditures		733,380			403,848
Downstream capital expenditures		284,244			71,234

Total capital expenditures		1,017,624			475,082
Acquisitions
Business		509,829			145,144
Property		4,254			527,470
Divestitures
Property		(8,728	)		(122,788	)

Net acquisition and divestiture activities		505,355			549,826
Addition to other long term assets		7,413			—

Net capital investment		1,530,392			1,024,908

On February 28, 2011, Harvest closed the acquisition of assets from Hunt for cash consideration of $511.0 million. KNOC provided $505.4 million of equity to fund the acquisition. An additional $25 million is payable to Hunt in the event that Canadian natural gas prices exceed certain pre-determined levels in 2012. Based on forecast gas prices at April 27, 2012, the probability of incurring this payment was assessed as low. Assets acquired include approximately 377,000 net acres of undeveloped land, with complementary land positions in Willesden Green, the Peace River Arch and Southern Alberta. This acquisition includes access to resource plays in the Willesden Green area of Alberta and the Horn River basin of British Columbia.

In 2010, Harvest Operations acquired the remaining 40% interest in Redearth Partnership and other petroleum and natural gas properties for cash consideration of $145.2 million. This amount was finalized during 2011 and the total cash consideration was revised to $144.2 million as a result of adjustments made during the measurement period.

On August 6, 2010, Harvest completed the acquisition of the BlackGold oil sands project from KNOC for $374 million. Harvest signed an EPC contract in 2010 for phase 1 of BlackGold, under which $92.4 million (including a $31.1 million deposit) has been paid to the end of 2011. Between project inception and December 31, 2011, Harvest has capitalized $122.3 million of expenditures relating to drilling and completion of observation 12 wells and EPC activities. See "—Property, Plant and Equipment."

The following table provides a summary of Harvest's capital expenditures in accordance with U.S. GAAP for the year ended December 31, 2009:

($000's)

Upstream capital expenditures	186,276
Downstream capital expenditures	43,875

Total capital expenditures	230,151
Acquisitions
Business	—
Property	2,635
Divestitures
Property	(64,751	)

Net acquisition and divestiture activities	(62,116	)

Net capital investment	168,035

On August 11, 2009, Harvest acquired approximately 93.5% of the issued and outstanding class A shares and 90.6% of the issued and outstanding class B shares of Pegasus Oil and Gas Inc. ("Pegasus"), a natural gas weighted producer with approximately 650 boe/d of production, in exchange for Trust Units. Subsequent to August 11, 2009 and pursuant to the compulsory acquisition provisions of the Business Corporations Act (Alberta), Harvest purchased the remaining Pegasus shares and de-listed the Pegasus shares from the TSX Venture exchange. Including the obligation to assume approximately $13.9 million of bank debt, the acquisition metrics were approximately $30,000 per boe of production and approximately $4.25 per boe of reserves on a proved plus probable basis. The principal asset in this acquisition was a 7% working interest in liquids rich natural gas production from a property in the Crossfield area which is operated by Harvest. This acquisition includes access to over 150,000 acres of land and over $50 million of income tax pools.

Business Overview

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. Harvest's Upstream operations are located in the Western Canadian sedimentary basin. See "—Property, Plant and Equipment." Harvest has a high degree of operational control as it is the operator on properties that generate the majority of Harvest's production. The Corporation believes that this "hands on" approach allows it to better manage capital expenditures and accumulate institutional expertise in its operating regions.

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 23 of the consolidated financial statements for the year ended December 31, 2011 included elsewhere in this prospectus.

Marketing Channels

Crude Oil and 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. These commodities typically receive the prevailing monthly market prices. Harvest has a small number of condensate purchase contracts required for blending heavy oil to meet pipeline specifications. These are a combination of one year and monthly spot contracts, both at the prevailing monthly prices.

Natural Gas

Approximately 87% of Harvest's natural gas production is currently being sold at the prevailing daily spot market prices in Western Canada. Harvest receives Chicago based prices on 9% of its natural gas production relating to certain pipeline transportation commitments. The remaining 4% of production is dedicated to aggregator contracts, which are reflective of market prices and are under contract until 2015.

The following is Harvest's Upstream sales by product for each of the three years ended December 31:

*In accordance with IFRS*	Year Ended December 31,

($000's)	2011			2010
Light / medium oil sales after hedging⁽¹⁾⁽⁴⁾		752,898			624,778
Heavy oil sales⁽⁴⁾		228,794			202,445
Natural gas sales⁽²⁾		156,942			124,226
Natural gas liquids sales⁽⁴⁾		125,507			55,385
Other⁽³⁾		22,725			170

Petroleum and natural gas sales		1,286,866			1,007,004
Royalties		(195,452	)		(154,757	)

Revenues		1,091,414			852,247

(1): Inclusive of the effective portion of realized gains (losses) from crude oil contracts designated as hedges.
(2): In 2011, 9% of natural gas was delivered to a pipeline that ships to the United States (2010—nil).
(3): Inclusive of sulphur revenue and miscellaneous income.
(4): All of Harvest's crude oil and NGLs are sold in Canada.



*In accordance with U.S. GAAP*
($000's)
Light / medium oil sales after hedging	502,239
Heavy oil sales	198,168
Natural gas sales	141,225
Natural gas liquids sales	44,676

Petroleum and natural gas sales⁽¹⁾	886,308
Royalties	(128,860	)

Revenues	757,448

(1): All of Harvest's products were sold in Canada.

Pipeline Capacity

Pipeline capacity is an important consideration and may significantly impact the oil and natural gas industry if a considerable imbalance exists between pipeline capacity and export nominations. If there is a significant shortfall of export capacity, it will result in oil and gas being unable to get to market which will result in discounted pricing and/or shut-in production. Conversely, if the basin has a significant amount of excess export capacity it can make transportation more expensive, which will also have a negative effect to the netback.

Competitive Conditions, Seasonality and Trends

The exploitation and development of petroleum 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. See "Risk Factors" for a description of competitive conditions.

Environment, Health and Safety Procedures and Practices

Harvest takes an active role in the Canadian Association of Petroleum Producers ("CAPP") Responsible Canadian Energy ("RCE") 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 2011, Harvest continued to take steps to build on its existing environmental, health and safety ("EH&S") management systems using the RCE framework for continuous improvement. This included formalizing the environment and regulatory components of the EH&S management system. Component improvements included creating a process for identifying potential high impact spill locations as well as a formalized risk process for classifying historical spill sites so that annual environmental budgets can be allocated appropriately. It is expected that in 2012 all components of the environment and regulatory portions of the EH&S management system will be formalized which will improve overall environmental performance.

In 2011, Harvest spent $22.1 million on the management and retirement of environmental obligations which included retirement of wells and facilities, restoration of spill sites, remediation of sites with historical contamination, and the reclamation of abandoned well sites and access roads. In 2011, Harvest had 310 active (operated) reclamation sites with 40 of these sites being submitted to regulators for reclamation certification. In addition, Harvest completed 46 surface well abandonments which will add to the number of active reclamation sites in 2012.

Enhancements to the health and safety program in 2011 included Harvest formalizing its Contractor Engagement Program for evaluating and approving third party contractors that work at Harvest sites. As a result Harvest outperformed the industry average with regard to contractor incident statistics. Additional improvements included the implementation of health and safety committees within each of the key functional groups at Harvest and revisions to the hazard identification and risk assessment processes. Finally, emergency response plans underwent the required annual review which included revising critical information within the plans and the providing training to key response personnel at Harvest.

Harvest met all regulatory compliance obligations in 2011 including the submission of the annual National Pollutant Release Inventory ("NPRI"), the BC Greenhouse Gas ("GHG") Inventory, the annual Facility Approval summary reports, the inventory of all benzene emissions from Glycol Dehydrators, the annual Caribou Protection Plans and completion of all Indian and Oil and Gas ("IOGC") required environmental audits. In addition, Harvest continued to be diligent with its Fugitive Emission Management Program, with leak detection testing conducted at 559 facilities. All repairable emission sources detected were repaired representing a reduction in GHG emissions and savings in fuel gas usage. In late 2011/early 2012, Harvest continued to improve on its GHG inventory with the initiation of the use of an on-line database that will improve data collection and reporting accuracy, as well as ensuring continued compliance with provincial regulatory bodies.

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. It is common to sell on an index, which is published on a daily and/or monthly basis. These indices are generated from calculations that consider volume-weighted-industry-reported purchase and sales transactions. They are generated at various sales points and are reflective of the current value of the specific commodity, adjusted for quality and location differentials. While these indices tend to directionally track benchmark prices (i.e. WTI 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.

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 favor 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%, of gross revenue, 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% of net operating income.

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, the 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 Corporation'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, 2012 (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 metres 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 metres into the Deep Royalty Credit Program. An additional $50 million was allocated in the fall of 2009 for the Infrastructure Royalty Credit Program to stimulate investment in oil and gas roads and pipelines.

Land Tenure

Crude oil and natural gas located in western Canada is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms 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.

Reserves and Other Oil and Gas Information

Harvest retained qualified Independent Reserves Evaluators to evaluate and prepare reports on 100% of Harvest's crude oil and natural gas proved plus probable reserves as of December 31, 2011; no attempt was made to evaluate possible reserves. Harvest's reserves were evaluated by McDaniel (who evaluated approximately 17% of Harvest's total proved plus probable reserves), and GLJ (who evaluated approximately 83% of Harvest's total proved plus probable reserves). All of Harvest's reserves were evaluated using the cost assumptions as at December 31, 2011 and the average first-day-of-the-month prices for the period ended December 31, 2011. All of Harvest's reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia and Saskatchewan. See Exhibits 99.6 and 99.7 for Independent Reserve Evaluators' reports on evaluation methodology.

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.

Description of Harvest's Internal Controls Used in Reserve Estimation

The person primarily responsible for overseeing the year-end reserves evaluation is the Vice President ("VP"), Engineering, Jim Sheasby, Professional Engineer who has been at Harvest since February 2006.

Independent Reserves 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 VP, Engineering. 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 Reserves Evaluators. Normally, more than one Independent Reserves Evaluator would be appointed to ensure independence. The allocation of assets to be reviewed by each Independent Reserves Evaluator is based on the evaluator's expertise, information databases and past experience in evaluating the relevant properties. The allocations are reviewed by the VP, Engineering to ensure that there is no duplication of areas.

For 2011, Harvest engaged GLJ and McDaniel 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. Computer software is used to establish the appropriate level of certainty for reserves estimates. 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 reports were received.

The VP, Engineering reviews the final reports, ensuring that they are consistent with the previous reports and that appropriate changes have been made. After completing the review, the VP, Engineering presents the reports 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 VP, Engineering and key areas and significant differences between management and the Independent Reserves Evaluators are discussed.

A due diligence checklist 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 Reserves Evaluator attests to the Reserves Committee that the Reserves Report satisfies NI 51-101 and SEC definitions; this representation is also included in the final signed reports.

Net Reserves (Harvest's 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, 2011. The year-end numbers represent estimates derived from the Reserve Reports. 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. See "Risk Factors" for discussion on the uncertainties involved in estimating our reserves.

The crude oil, natural gas liquids and natural gas reserve estimates presented are based on the definitions provided in the SEC's regulations. 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 with reasonable 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. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.

If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

(c): Probable reserves estimates are provided as optional disclosure under the SEC regulations. 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. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

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.

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.

	Reserves

	Light and Medium Oil⁽¹⁾				Heavy Oil⁽¹⁾				Bitumen
	Gross (Mbbls)		Net (Mbbls)		Gross (Mbbls)		Net (Mbbls)		Gross (Mbbls)		Net (Mbbls)
Proved
Developed producing		51,334		45,914		34,739		31,521		—		—
Developed non-producing		1,288		1,112		1,335		1,115		—		—
Undeveloped		9,650		8,302		3,181		2,666		93,483		82,237

Total proved		62,272		55,328		39,255		35,302		93,483		82,237
Probable		26,206		23,284		16,975		14,651		165,762		138,847

Total proved plus probable		88,478		78,612		56,230		49,953		259,245		221,084

	Reserves

	Natural Gas				Natural Gas Liquids				Total Oil Equivalent
	Gross (MMcf)		Net (MMcf)		Gross (Mbbls)		Net (Mbbls)		Gross (Mboe)		Net (Mboe)
Proved
Developed producing		231,867		206,968		11,058		8,015		135,775		119,944
Developed non-producing		21,735		19,606		793		620		7,039		6,115
Undeveloped		60,098		53,800		1,930		1,596		118,261		103,767

Total proved		313,700		280,374		13,781		10,231		261,075		229,826
Probable		139,138		124,271		7,197		5,323		239,330		202,817

Total proved plus probable		452,838		404,645		20,978		15,554		500,405		432,643

(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. Harvest has presented Hay River reserves as medium gravity crude in the reserves 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 gross light/medium oil reserves by the following amounts: Proved Developed Producing: 12.2 MMbbl (10.8 MMbbl net), Proved Undeveloped: 5.0 MMbbl (4.1 MMbbl net), Total Proved: 17.2 MMbbl (14.9 MMbbl net), Probable: 5.9 MMbbl (5.4MMbbl net) and Proved plus Probable: 23.1 MMbbl (20.3 MMbbl net).

Undeveloped Reserves

As at December 31, 2011, Harvest has a total of 125.3 MMboe of gross reserves that are classified as proved non-producing, and of these non-producing reserves approximately 94% 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 December 31, 2011. Substantially all of the undeveloped reserves are based on Harvest's then current 2012 budget and long range development plans for the major assets noted elsewhere in this document. Approximately 22% of the conventional undeveloped 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 BlackGold oil sands 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 2011, Harvest drilled a gross total of 251.0 wells (214.3 net) with the vast majority of the development taking place in the following properties: Hay River, Red Earth, Rimbey, Markerville, West Central, Lloydminster, Hayter, Murray Lake and Kindersley. 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 2011 were gross 11.1 MMboe with related capital expenditures of approximately $238.4 million.

New PUD reserves were also assigned during the 2011 year-end evaluation recognizing the ongoing development of Harvest's properties. Total gross PUD reserves added for the 2011 year-end evaluation were 10.1 MMboe.

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

Production Volumes

	Production Volumes—2011

	Year		Q4		Q3		Q2		Q1
Natural Gas(Mcf/d)		112,360		121,547		124,259		111,291		91,888
Oil and Natural Gas Liquids(bbls/d)
Light and Medium Oil⁽¹⁾		24,380		26,106		23,621		22,294		25,523
Heavy Oil		8,992		9,521		8,825		8,559		9,038
Natural Gas Liquids		5,062		5,440		5,392		5,937		3,455

Total Oil and Natural Gas Liquids		38,434		41,067		37,838		36,790		38,016

Total(boe/d)		57,161		61,324		58,548		55,338		53,331

	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

Per-Unit Results

	Per-Unit Results—2011

	Year		Q4		Q3		Q2		Q1
Natural Gas and Natural Gas Liquids ($/boe)
Average sales price		32.53		31.02		32.82		34.62		31.46
Royalties		4.58		4.93		3.61		7.76		1.28
Operating expenses⁽²⁾		11.40		12.01		11.33		11.33		10.73

Netback⁽³⁾		16.55		14.08		17.88		15.53		19.45
Crude Oil—Light and Medium⁽¹⁾ ($/bbl)
Average sales price		85.67		89.90		80.43		94.08		78.69
Royalties		14.01		15.00		14.29		15.21		11.65
Operating expenses⁽²⁾		20.60		20.22		20.52		20.41		21.23

Netback⁽³⁾		51.06		54.68		45.62		58.46		45.81
Crude Oil—Heavy ($/bbl)
Average sales price		69.71		79.28		62.84		74.84		61.51
Royalties		9.45		9.56		8.98		10.81		8.53
Operating expenses⁽²⁾		20.78		22.23		20.11		20.12		20.53

Netback⁽³⁾		39.48		47.49		33.75		43.91		32.45
Crude Oil—Total ($/bbl)
Average sales price		81.37		87.06		75.65		88.74		74.20
Royalties		12.78		13.54		12.84		13.99		10.83
Operating expenses⁽²⁾		20.65		20.76		20.41		20.33		21.05

Netback⁽³⁾		47.94		52.76		42.40		54.42		42.32
Total ($/boe)
Average sales price		62.13		64.61		57.85		66.73		59.19
Royalties		9.37		9.93		8.72		11.23		7.47
Operating expenses⁽²⁾		16.80		17.09		16.36		16.35		17.42

Netback⁽³⁾		35.96		37.59		32.77		39.15		34.30

	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

(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): This is a non-GAAP measure. Please see "Non-GAAP Financial Measures" in this prospectus. 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 and net interest in wells drilled for the periods indicated.

	2011

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net
Oil Wells		15		14.0		163		145.0
Gas Wells		1		1.0		37		20.8
Service Wells		3		3.0		25		25.0
Dry Holes		7		5.5		—		—

Total Wells		26		23.5		225		190.8

	2010

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net
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		Net		Gross		Net
Oil Wells		—		—		42		35.1
Gas Wells		—		—		38		15.7
Service Wells		1		1		25		24.5
Dry Holes		—		—		1		0.3

Total Wells		1		1		106		75.6

Present Activities

Conventional

At December 31, 2011 Harvest was in the process of drilling a gross total of 10 wells (9.8 net) which was the beginning of the 2012 capital program (estimated to be approximately $436 million with a focus on oil projects). In Hay River there were 3 gross horizontal oil wells and 4 gross injectors all targeting the Bluesky formation; in Red Earth there were 2 gross Horizontal Slave Point oil wells and in the Deep Basin there was one gross horizontal Falher liquids gas well. Harvest also plans to continue with its enhanced oil recovery projects in the larger oil reservoirs at Hay River, Wainwright and Suffield.

Oil Sands

At December 31, 2011 engineering, procurement and construction of the facilities for the BlackGold oil sands project were in progress, as well as detailed engineering and fabrication of major equipment. Site preparation was completed and Harvest was in the process of drilling 15 SAGD well pairs.

Location of Wells

The following table summarizes Harvest's interests in producing wells and wells capable of producing as at December 31, 2011.

	Gas				Oil				Total⁽¹⁾⁽²⁾

	Gross		Net		Gross		Net		Gross		Net
Alberta		3,019		1,127		4,499		3,351		7,518		4,478
British Columbia		166		125		538		299		704		424
Saskatchewan		63		95		1,613		1,317		1,676		1,412

Total		3,248		1,347		6,650		4,967		9,898		6,314

(1): Harvest has varying royalty interests in 700 natural gas wells and 240 crude oil wells which are producing or capable of producing.
(2): Includes wells containing multiple completions as follows: 41 gross natural gas wells (19.1 net wells) and 21 gross crude oil wells (11.2 net wells).

Developed and Undeveloped Acreage

The following table summarizes Harvest's developed, undeveloped and total landholdings as at December 31, 2011.

	Developed⁽¹⁾				Undeveloped⁽²⁾				Total

(thousands of acres)	Gross		Net		Gross		Net		Gross		Net
Alberta		1,310		734		781		543		2,091		1,277
British Columbia		142		79		309		192		451		271
Saskatchewan		89		81		91		81		180		162

Total		1,541		894		1,181		816		2,722		1,710

The following table summarizes Harvest's developed and undeveloped land holdings, expiring within one year from December 31, 2011.

	Developed⁽¹⁾				Undeveloped⁽²⁾				Total

(thousands of acres)	Gross		Net		Gross		Net		Gross		Net
Alberta		29		23		86		71		115		94
British Columbia		4		3		62		49		66		52
Saskatchewan		2		2		18		18		20		20

Total		35		28		166		138		201		166

(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. Users of this information should not confuse undeveloped acreage with undrilled acreage held by production under the terms of the lease.

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

Delivery Commitments

Harvest does not have any material delivery commitments. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Tabular Disclosure of Contractual Obligations" for commitments relating to transportation agreements.

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. The Downstream operations are predominantly located in the Province of Newfoundland and Labrador.

Products and Markets

Refining Business

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"). Approximately 10-15% of North Atlantic's refined products are sold in the Province of Newfoundland and Labrador while approximately 70-85% is export cargos sold to MEC under the SOA (2011). Such cargos are shipped by MEC to U.S. east coast markets such as Boston, New York City and in Europe, or farther abroad, when economics justify the increased shipping charge. During 2011, North Atlantic sold the majority of its distillates, gasoline products and HSFO to Vitol pursuant to the SOA and to MEC pursuant to the SOA (2011), with the remaining products sold in Newfoundland through the petroleum marketing division. North Atlantic's business and operating results are dependent on the SOA (2011) and the SOA partner.

The following table shows Downstream's sales by product for the years ended December 31:

*In accordance with IFRS*	Year Ended December 31,

($000's)	2011		2010
Gasoline products		1,055,020		985,737
Distillates		1,385,985		1,251,160
High sulphur fuel oil		628,518		744,628

Total sales		3,069,523		2,981,525

		Year Ended December 31, 2009

*In accordance with U.S. GAAP*
($000's)
Gasoline products			851,850
Distillates			972,872
High sulphur fuel oil			467,249

Total sales			2,291,971

The following table provides the total amount of Downstream's export sales for the years ended December 31:

	Year Ended December 31,

*In accordance with IFRS*	2011		2010
Total export sales($000's)⁽¹⁾		2,349,521		2,328,653
Export sales as a percentage of total Downstream sales		77%		78%

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

*In accordance with U.S. GAAP*		Year Ended December 31, 2009

Total export sales($000's)⁽¹⁾			1,869,686
Export sales as a percentage of total Downstream sales			82%

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

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

Retail Gasoline Business

North Atlantic's retail gasoline business operates 55 retail gasoline stations (including 39 locations branded as "North Atlantic" and 10 locations branded as "Home Town"; a secondary brand for small market areas and the remaining 6 locations unbranded) and 3 commercial cardlock locations. Most locations include a convenience store which is independently operated, except for 7 branded locations, which are fully operated by North Atlantic and 1 franchise location which is referred to as "Orange Store." In 2011, the volume of gasoline sold at these retail locations represented a market share of approximately 23% of the Newfoundland market. The major competitors in the Newfoundland market are Irving Oil, Imperial Oil and Ultramar.

Retail Heating Fuels Business

North Atlantic'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% 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

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. North Atlantic continuously evaluates the market and relative refinery values of several different crude oils and vacuum gas oils ("VGO") to determine the optimal feedstock mix. North Atlantic also analyzes the refining gross margin for its sales revenue relative to refined product benchmark prices and the WTI benchmark prices. With respect to feedstock costs, North Atlantic analyzes price discounts relative to the WTI benchmark prices and segregate crude oil sources by country of origin for reporting. See "Risk Factors—Risks Related to the Downstream Operations" 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 South America. North Atlantic purchases substantially all of its refinery feedstock from MEC pursuant to the SOA (2011). 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 "Risk Factors."

Environment, Health and Safety Policies and Practices

The Downstream operations have 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 ninth consecutive year. In 2011, 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, refined product specifications, emissions and marketing) 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.

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 are 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.

The Canadian Government has indicated its commitment to reduce GHG emissions and will be making changes to environmental legislation for criteria air contaminants 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 Harvests' 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 GHGs 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 GHG 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 GHG 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 GHG 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 GHG 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 GHGs 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.

Harvest's environmental compliance is governed by various statutes including: Alberta's Environmental Protection and Enhancement Act, British Columbia's Environmental Assessment Act, Saskatchewan's Environmental Assessment Act, and Newfoundland's Environmental Protection Act.

Alberta

In 2007, the Government of Alberta introduced the Climate Change and Emissions Management Amendment Act which intends to reduce GHG 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 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.

On April 5, 2011, the Government of Alberta released their draft of the Lower Athabasca Regional Plan ("LARP"), which was developed as part of the land-use framework under the Alberta Land Stewardship Act. The draft was subsequently updated on August 29, 2011 based on feedback and consultation received from stakeholders. The LARP outlines management frameworks for protecting, monitoring, evaluating and reporting air, surface water and groundwater quality by setting strict environmental limits. In addition, conservation areas will increase by approximately 16% to a total of 22% of the region's land base. Based on a preliminary assessment, the proposed new conservation areas do not appear to affect Harvest. The LARP is currently awaiting approval by the legislature.

British Columbia

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. Harvest has not incurred material compliance costs and does not expect such costs to increase significantly in the future unless the Province of British Columbia introduces new compliance requirements.

Saskatchewan

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.

On June 22, 2011, the government announced its new Upstream Petroleum Industry Associated Gas Conservation Standards, which are designed to reduce emissions from the flaring and venting of associated gas. The standards establish a specified limit for the amount of natural gas that can be flared and vented from an oil well or associated facility. If that limit is exceeded, the producer is required to conserve and store the associated gas for their own use or sale. The standards will come into effect July 1, 2012 for new wells and facilities licensed on or after that date, and July 1, 2015 for existing wells and facilities. Harvest does not anticipate material compliance costs as the Corporation currently has infrastructure in place to conserve gas in most of our operated areas in Saskatchewan.

Newfoundland

The Federal Renewable Fuel Regulations were published in the Canada Gazette, April 10, 2010. At that time an exemption was provided for the addition of ethanol to gasoline sold in Newfoundland and Labrador and on June 20, 2011 a further exemption was provided for the requirements for renewable content in diesel fuel and heating distillate oil sold in Newfoundland and Labrador. These exemptions benefit our Downstream operations by providing relief from the Federal Renewable Fuel Regulations.

In 2011, the Government of Newfoundland and Labrador published its Climate Change Action Plan. The Province, in collaboration with the Conference of New England Governors and Eastern Canadian Premiers, has committed to reduce regional GHG emissions to 1990 levels by 2010, to reduce regional GHG emissions to 10% below 1990 levels by 2020; and to reduce regional GHG emissions to 75-85% below 2001 levels by 2050.

Organizational Structure

The corporate structure including significant subsidiaries is set forth below. Harvest is a wholly owned subsidiary of KNOC. Each of the subsidiary entities identified below is a direct or indirect wholly owned subsidiary of Harvest Operations. 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, 2011:

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. Harvest Breeze Trust No. 1 has a 99% interest in each of the Breeze Resources Partnership and the Hay River Partnership.

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.

North Atlantic Refining Limited, a Canadian 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.

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 reserves addition through extending the economic life of these producing properties beyond the limits used by the Independent Reserves 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.

2011 Historical Production by Material Property

Material Property

Hay River	4,734	2,985	12	5,243
Red Earth	3,957	72	58	4,027
West Central Alberta	1,959	56,440	3,899	15,265
East Central Alberta	7,598	6,391	205	8,868
Deep Basin	22	18,562	550	3,666
Heavy Oil	7,803	2,196	42	8,211
Saskatchewan Light Oil	3,940	899	30	4,120
Other	3,359	24,815	266	7,761

TOTAL	33,372	112,360	5,062	57,161

Hay River

Hay River was acquired by Harvest on August 2, 2005 and is located approximately 125 miles north west of Grande Prairie in north-eastern British Columbia. In 2011, Hay River produced 5,243 boe/d (95% oil) of medium gravity 24° API crude oil and natural gas from the BlueSky Formation located at a depth of approximately 350 metres. 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 2011, Harvest drilled 44 gross wells, including 28 gross producing dual leg horizontal wells and 16 water source and water injection wells, and established new infrastructure with a total capital expenditure of $78 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. In 2011, Harvest drilled its first Gething Source well that will improve reservoir management practices.

Red Earth

Red Earth is located 300 miles north west of Edmonton, Alberta. Production in 2011 from Red Earth averaged 4,027 boe/d (99% oil) with an average oil quality of 37° to 39° API from the Slave Point, Granite Wash and Gilwood Formations. Harvest increased its working interest in this area to over 90% following the acquisition of the remaining 40% interest in the Redearth Partnership in the fall of 2010 and has been actively adding to its land base through Crown land sales. In 2011, Harvest drilled 38 gross wells with total capital expenditures, including roads and pipelines, of $110 million. A majority of the drilling was made up of horizontal wells in the Slave Point Formation using multi-staged fractured completions. Future development at Red Earth may include downspace drilling in the Slave Point Formation, 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 new Gilwood and Granite Wash oil pools in the area and placement of Slave Point horizontal wells.

West Central Alberta

West Central Alberta is comprised of properties west of Highway 2, south of Edmonton and north of Calgary. This is primarily a liquids rich natural gas producing area for the Corporation with some oil production. Properties for this area were added through acquisition over the last several years with the most recent being Hunt in 2011. Production for 2011 for the area is 15,265 boe/d (62% gas). Major properties in this area include Caroline (Beaverhill Lake liquids rich 50% H2S gas), Crossfield (Ellerslie oil and Basal Quartz), Markerville (Pekisko, Edmonton Sands, Cardium and Glauconite and Ellerslie) and Rimbey (Glauconite, Ostracod, Notikewin and Cardium). All new liquids rich gas production and oil production are from stage stimulated horizontal wells except for a highly prolific vertical gas play in the Glauconite. In 2011, Harvest participated in 43 gross wells for a total capital expenditure $107 million.

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East Central Alberta

This area mainly encompasses legacy oil properties from the Saskatchewan/Alberta border to Alberta Highway 2 and properties south of the city of Edmonton. Working interest in these properties is over 90%. In 2011, the average production was 8,868 boe/d (88% oil) and is primarily oil from 18° to 32° API. The Corporation's largest polymer flood in Wainwright is in this group along with large legacy properties such as Bellshill, Provost and Bashaw. This area is largely a focus of EOR and optimization of current wells and facilities. In 2011, the Corporation participated in 3 gross wells for a total capital expenditure of $3.5 million.

Deep Basin

The Deep Basin is a new area to the Corporation in 2011 and was acquired from Hunt. Deep Basin is located to the south of the city of Grande Prairie in northwest Alberta. Production for 2011 was 3,666 boe/d (84% gas). Legacy production is from vertical wells completed in multiple zones (Falher, Cardium, Cadotte, Cadomin, BlueSky, Dunvegan, and Gething) and comingled together. Recent activity has been focused on drilling high rate 5 to 15 mcf/d stage stimulated horizontal wells in the Falher Formation, which has liquids content between 50 and 100 barrels per mcf. In 2011, Harvest participated in 5 gross wells for a net cost of $27 million.

Heavy Oil

Harvest has various working interests in this area, which is located near the town of Lloydminster on both the Alberta and Saskatchewan side of the border and down into Southern Alberta near the city of Medicine Hat. Major properties in this group include Suffield (Glauconite), Maidstone (Sparky and Waseca), Lloyd (Lloydminster), and Hayter (Dina/Cummings and Sparky). Production is 12° to 15° API heavy crude oil from Cretaceous aged sandstone Formations within the Mannville group. Production averaged 8,211 boe/d (96% oil) in 2011. Harvest drilled 42 gross wells in 2011 with total net capital expenditures of $41.2 million. The majority of the wells drilled were horizontal in the Lloydminster Formation or the Glauconite. Production from the area's wells is processed at a central processing facility with solution gas conservation and then trucked to third party sales points, except for Hayter and Suffield which are pipeline connected. Future plans include downspacing pools with additional horizontal wells and assessing the potential impact of water injection for pressure maintenance and enhanced recovery. This area also contains EOR potential. By increasing injection and using chemical enhancements such as polymers, Harvest believes the ultimate recovery of oil will be increased. Pool optimization and EOR projects will target increased water injection into under-injected reservoirs that have not received adequate pressure maintenance as well as the expansion of the existing Suffield polymer flood to further enhance sweep efficiencies.

Saskatchewan Light Oil

This area includes Harvest's assets in south eastern Saskatchewan towards the Manitoba border as well as production near the City of Kindersley in western Saskatchewan, near the Alberta border. The Kindersley assets are produced from staged fractured horizontal wells in the Viking Formation. The SE Saskatchewan properties are located approximately 110 miles southeast of Regina with production from the non-stage stimulated horizontal wells in Tilston and Souris Valley Formations of Mississippian age. Both of these properties contain high netback light 34° to 39° API oil. Production in 2011 was 4,120 boe/d (96% oil). In 2011, Harvest participated in 43 gross wells with a total net capital expenditure of $64 million.

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BlackGold

BlackGold oil sands project is located in north-eastern Alberta near Conklin and is in close proximity to a number of major oil sands developments. The project will utilize SAGD, a proven production technology that uses horizontal drilling and thermal stimulation to maximize energy efficiency and minimize land disturbance. In 2011, Harvest completed the drilling of 12 observation wells and continued to progress on the construction of the central processing facility and well pads. Since the fourth quarter of 2011, the Corporation has been engaging in an active drilling program under which the drilling of 30 wells (15 SAGD well pairs) are expected to be completed by the end of 2012. During the first quarter of 2012, Harvest completed drilling surface holes for 20 wells and completed drilling 5 of the 30 SAGD wells. Engineering of the project is now more than 70% complete and the site has been cleared and graded. As at March 31, 2012, Harvest has invested a total of $153.7 million since project inception. Near-term activities include completion of detailed engineering work, progression of civil construction work at the project site and commencement of module fabrication. Other 2012 activities include module assembly and facility construction. Approval of phase 2 of the project, which is targeted to increase production capacity to 30,000 bbl/d, is underway and anticipated in 2012. The BlackGold project faces similar cost and schedule pressures as other oil sand projects, including shortage of skilled labor, rising costs, and logistics issues surrounding module transportation; phase 1 production is now expected to start in 2014. On May 30, 2012, Harvest executed an agreement with its engineering, procurement and construction (EPC) contractor to amend aspects of the EPC contract, including revising the compensation terms from a lump sum price to a cost reimbursable price and confirming greater Harvest control over project execution. The project pressures and resultant contract changes are expected to increase the net EPC costs to approximately $520 million, after allowing for certain costs which are not reimbursable to the EPC contractor.

2012 Capital Expenditures Plan

Harvest's expected total capital spending on its oil and natural gas properties for 2012 is expected to be approximately $650 million. Harvest plans to fund future capital expenditures through borrowings from the Credit Facility and cash from operating activities. The primary areas of focus for Harvest's Upstream capital program during 2012 are the following:

•: BlackGold—Expenditures of approximately $195 million to fund module assembly, facility construction and an active drilling program in which 30 gross wells (15 SAGD well pairs) are currently underway;
•: Hay River—Drill 27 gross producing multi-leg horizontal oil wells and water injection wells as well as upgrading the processing infrastructure and drilling and tying-in source water wells to facilitate better reservoir management for an expenditure of $74.8 million;
•: Red Earth—Drill 13 gross light oil wells and establish pipeline infrastructure for emulsion gathering and EOR upside for a net expenditure of $59.2 million with up to 11 gross multistage fractured horizontal wells for the Slave Point Formation;
•: West Central/Rimbey—Drill 12 gross wells targeting the Cardium oil/gas/NGL stage stimulated horizontal wells, Ellerslie light oil vertical wells and Glauconitic (liquids rich natural gas) stage stimulated horizontal wells for an expenditure of $41.2 million;
•: Kindersley, Saskatchewan—Drill 12 gross multistage fractured horizontal wells and build infrastructure for pressure maintenance into the Viking Formation for a total expenditure of $30 million;
•: Deep Basin Area—Drill 7 gross Falher horizontal stage fractured liquids rich natural gas wells plus install debottlenecking infrastructure for a total expenditure of $42.9 million;

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•: Southeast Saskatchewan Area—Drill 9 gross horizontal light oil wells into the Souris Valley and Tilston Formations for a total expenditure of $18.9 million;
•: Lloydminster Heavy Oil—Drill 25 gross wells (primarily horizontal wells) into the Lloydminster and Waseca Formations for a total expenditure of $26 million;
•: Suffield and Wainwright—Expand and continue to inject polymer into the two existing EOR floods for a total expenditure of $11.3 million; and
•: Various Areas—Expenditures of approximately $96.2 million to seismic and land purchases and other capital projects and $40.5 million to pursue production optimization including pump upsizing, facility debottlenecking and zonal recompletion.

Incremental Exploitation and Development Potential

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

•: Implementation or optimization of enhanced water floods beyond the two polymer floods previously mentioned in selected pools such as Suffield, Hay River, Red Earth, Cecil 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;
•: 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 3-D seismic;
•: Numerous exploratory opportunities defined by seismic from which value might be extracted by sale, Farmout or joint venture;
•: Management of dry gas portfolio to shut-in wells currently with low gas netbacks due to falling gas prices to preserve reserves to be produced at a time when gas prices improve; and
•: Utilizing multistage fractured technology in horizontal wells to increase oil recovery from tight oil and gas formations at Red Earth (Slave Point Formation), Crossfield (Basal Quartz and Ellerslie Formations), Kindersley (Viking Formation), Deep Basin (Falher Formation) and Rimbey/West Central Area (Cardium, Glauconite, Viking, Ostracod, Notikewin, Wilrich Formations).

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 66,417 bbl/d for the year ended December 31, 2011 due to planned maintenance of the refinery units. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations."

The Corporation has identified de-bottlenecking projects at the Refinery which are anticipated to 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 2015 with total estimated expenditures of approximately $245 million to complete all projects

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(Isomax unit, flare gas recovery unit, and crude storage). The debottlenecking projects began in 2009 and $115 million had been incurred as at December 31, 2011. The project will be funded through cash flows from operations as well as capital available to the Corporation through its capital resources. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources."

Other

The Corporation's Credit Facility is secured by a first floating charge over all of the assets (excluding BlackGold assets) of Harvest's Operating Subsidiaries plus a first mortgage security interest on the Downstream operation's refinery assets. See "Risk Factors" and "—Environmental Regulations" for further information on environmental issues that may affect the utilization of the Upstream and Downstream assets.

Legal Proceedings

There are no legal proceedings which the Corporation or any subsidiary of the Corporation is or was a party to, or that any of their property is or was the subject of during the year ended December 31, 2011, nor are there any proceedings known to Harvest to be contemplated, that involve a claim for damages exceeding ten per cent of Harvest's current assets.

During the year ended December 31, 2011, North Atlantic remained a party to a claim brought by the State of New Hampshire against numerous defendants for an unspecified amount of damages. This claim related to alleged contamination of ground water from the use of the gasoline additive methyl tertiary butyl ether ("MTBE"),The State of New Hampshire v. Amerada Hess Corp. et al, Docket No. 03-C-0550 (Merrimack County). The plaintiff also asserted collective and joint liability against all defendants. However, the State of New Hampshire Superior Court recently (March 2, 2012) rendered a favorable decision which granted summary judgment in favor of North Atlantic, dismissing all claims against it because of lack of personal jurisdiction over North Atlantic. The order of the Court became final on expiry of the appeal period since no appeal to the New Hampshire Supreme Court (the sole level of appeal) was filed by the plaintiff. As a result, the claim has been fully dismissed against North Atlantic based on the Superior Court order and judgment. No amounts had been accrued in the consolidated financial statements in respect of this matter and the Trust had received an indemnity from Vitol in respect of this contingent liability under the Purchase and Sale Agreement.

There were no penalties or sanctions imposed against the Corporation or any subsidiary of the Corporation by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2011 or any other penalties or sanctions imposed by a court or regulatory body against the Corporation or any subsidiary of the Corporation that would likely be considered important to a reasonable investor in making an investment decision. No settlement agreements were entered into by the Corporation or any subsidiary of the Corporation with a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2011.

Exchange Controls

There are no governmental laws, decrees, regulations or legislation of Canada or restrictions under the constating documents of Harvest that affect the import or export of capital or the remittance of dividends, interest or other payments to nonresident security holders.

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MANAGEMENT

Directors and Officers

The names, jurisdiction of residence and present positions and offices with Harvest as at the date hereof are set out in the table below.

Name and Jurisdiction of Residence	Position with Harvest Operations	Principal Occupation

Dr. Seong-Hoon Kim 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. 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 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.
Chang-Seok Jeong Seoul, South Korea	Director since January 2012.	Mr. Jeong became a Board Member of Harvest in January 2012. He is currently Executive Vice President of the America Group at KNOC. Mr. Jeong has 26 years of experience at KNOC and has worked in the Vietnam Office, Asia & Europe Production Department and the Overseas E&P Department as a General Manager & Managing Director. He earned a Bachelor's degree in Petroleum Engineering and Master's degree in Petroleum Engineering, both from Seoul National University.

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Name and Jurisdiction of Residence	Position with Harvest Operations	Principal Occupation

Chang-Koo Kang Seoul, South Korea	Chief Financial Officer since January 2012; Director since January 2010.	Mr. Kang is a corporate financial specialist and currently the Chief Financial Officer at Harvest. Prior thereto, he was the Vice President of KNOC's Finance Management Department. Prior to this, he held the position of Finance Team Senior Manager at KNOC. Mr. Kang has worked on financings for the merger and acquisition of PetroTech Peruana S.A., Peru, Harvest Operations Corp., and Sumble JSC, Kazakhstan. He holds a Bachelor's degree in accounting from Pusan National University and graduated with an MBA from Sogang Business School, Sogang University, Korea.
William D. Robertson 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 Argent Energy. 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 Alberta, Canada	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 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.

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Name and Jurisdiction of Residence	Position with Harvest Operations	Principal Occupation

Kyungluck Sohn Seoul, South Korea	Director since November 2010; Chief Financial Officer until January 2012.	Mr. Sohn is the Vice President, Finance Management Department at KNOC. He was the Chief Financial Officer of Harvest from February 16, 2010 to January 13, 2012. Mr. Sohn served as a Vice President of KNOC's Finance Management department in 2009, and in the Offshore Rig Operations department from May 2006 to December 2008. Mr. Sohn has also held positions as an Administration Manager with the Ulsan Gas Terminal, as a Financing Manager and Information Manager in the Petroleum Information department and a 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. He holds a Business Management degree from the Busan National University in South Korea.
Myunghuhn Yi Alberta, Canada	President & Chief Executive Officer since January 2012; Director since December 2010.	Mr. Yi became President and Chief Executive Officer of Harvest Operations in January 2012 and joined Harvest's Board in November 2010. Prior to joining Harvest, he was the Executive Vice President for the Americas Group, as well as President of ANKOR E&P Holdings Corporation in the USA. Mr. Yi has 23 years of experience at KNOC and has worked in Domestic Continental Shelf Development, the Overseas E&P Department, and the Ulsan Branch of the Petroleum Stockpile Department. He earned a bachelor's degree in Petroleum Engineering at Seoul National University and Master's degree of Petroleum Engineering in Hanyang University.
John E. Zahary Alberta, Canada	Director since 2008; President & Chief Executive Officer until January 2012.	John Zahary, a Professional Engineer with extensive senior management experience in the upstream and integrated oil and natural gas industry, is President and Chief Executive Officer of Sunshine Oil Sands Ltd. From February 3, 2006 to January 20, 2012, he was Harvest's President & Chief Executive Officer. Prior to the merger of Harvest and Viking Energy in February 2006, Mr. Zahary had been President & Chief Executive Officer of Viking since April 2004. Mr. Zahary is a past Director and past President of the Alberta Chamber of Resources, past Governor and Officer of the Canadian Association of Petroleum Producers, and Chairman of the western Canada Rhodes Scholarship Selection Committee as well as other business and volunteer involvements. Mr. Zahary holds a B.Sc. in Mechanical Engineering from the University of Calgary and a M.Phil. in Management from the University of Oxford.

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Name and Jurisdiction of Residence	Position with Harvest Operations	Principal Occupation

Robert A. Pearce Alberta, Canada	Chief Operating Officer since January 2012; Vice President, Corporate Development September 2011 to January 2012 and Treasurer since September 2011.	Mr. Pearce has over 25 years of varied technical and business experience in the areas of corporate development, general management, debt and equity finance, strategy and planning. Prior to joining Harvest he was the Chief Financial Officer of a junior company developing a new oil sands extraction technology. He was Chief Executive Officer and co-founder of North West Upgrading where he led a team developing an independent upgrader/refiner to service Alberta's growing oil sands sector. He served as Treasurer of PanCanadian Energy, was an energy investment banker for several years, and has held various for profit and not-for-profit director positions. Mr. Pearce has an undergraduate degree in Geological Engineering and an MBA in Finance.
Brian Kwak Alberta, Canada	Deputy Chief Operating Officer, Upstream and Vice President, Global Technology Research Centre	In December 2012, Mr. Kwak was appointed Deputy Chief Operating Officer, Upstream and Vice President, Global Technology Research Centre. From January 2010 until December 2011 Mr. Kwak was Deputy Chief Operating Officer, Upstream and Vice President, BlackGold 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.
Jongwoo Kim Alberta, Canada	Chief Strategy Officer & Corporate Secretary	Mr. Kim is the Chief Strategy Officer and Corporate Secretary of Harvest Operations. Prior to this, Mr. Kim was the Vice President, 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.
Patrick BH An Alberta, Canada	Vice President, BlackGold since December 2011.	Mr. An has over 20 years experience in project management, engineering execution of oil and gas facilities development projects and operations of the oil and gas production assets including interfacing with commercial, sub-surface, operations groups, liaisons with partner and third party operating companies, government regulators and legislative bodies. Prior to joining Harvest he was Senior Manager of Production Assets in the Middle East and CIS from 2009 to 2011 and BlackGold project from 2007 to 2008 in KNOC. He holds a B.Sc. in Mechanical Engineering.

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Name and Jurisdiction of Residence	Position with Harvest Operations	Principal Occupation

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.
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.
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.
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.

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Committees of the Board of Directors

Name of Director	Audit Committee	Upstream Reserves, Safety & Environment Committee	Downstream Operations, Safety & Environment Committee	Compensation and Corporate Governance Committee



Dr. Seong-Hoon				Chair

William A. Friley		×		×

J. Richard Harris	×	Chair

Chang-Seok Jeong				×

Chang-Koo Kang			×

William Robertson	Chair			×

Brant Sangster	×		Chair

Kang Hyun Shin			×

Kyungluck Sohn				×

Myunghuhn Yi		×	×

John E. Zahary

As of January 13, 2012, Mr. Myunghuhn Yi was appointed to the Upstream, Reserves, Safety and Environment Committee, replacing Mr. John Zahary.

As of January 13, 2012, Mr. Chang-Koo Kang and Mr. Myunghuhn Yi were appointed to the Downstream Operations, Safety and Environment Committee, replacing Mr. Kyungluck Sohn and Mr. John Zahary.

As of January 13, 2012, Mr. Chang-Seok Jeong and Mr. Kyungluck Sohn were appointed to the Compensation and Corporate Governance Committee, replacing Mr. Myunghuhn Yi and Mr. Chang-Koo Kang.

As of December 2, 2011, Mr. William Robertson was appointed to the Compensation and Corporate Governance Committee.

As of January 13, 2012, Chang-Seok Jeong was appointed to the Harvest Board.

As at December 31, 2011, 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 of Harvest Operations.

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 and $1,000 for each committee meeting attended. If an independent director attended two meetings on the same date, the independent director received $500 for the second meeting. The committee chairmen were paid $1,500 for each committee meeting attended. Each such director was entitled to reimbursement for expenses incurred in carrying out his duties as director.

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The following table sets forth all compensation provided to the independent directors of Harvest Operations for the most recently completed financial year ended December 31, 2011. The non-independent directors received no compensation for carrying out their duties as directors.

Name		Fees Earned ($)

William A. Friley			39,000
J. Richard Harris			46,000
William Robertson			42,500
Brant Sangster			45,000

Compensation of Officers and Management

The following table sets forth for the year ended December 31, 2011 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, 2011 are individually identified while the remainders of individuals listed above are shown in aggregate.

Name

John Zahary⁽¹⁾⁽⁴⁾	418,000	270,000	462,027	68,936	1,218,963
Kyungluck Sohn⁽⁴⁾⁽⁶⁾	154,004	37,440	Nil	113,856	305,299
Neil Sinclair	235,621	60,000	130,594	43,189	469,404
Phil Reist	235,043	60,000	120,253	31,522	446,818
Les Hogan	223,840	55,000	114,521	39,742	433,103
Other⁽⁷⁾	1,556,974	237,307	243,322	545,092	2,582,695

(1): Harvest Operations has entered into employment agreements with Mr. Zahary. 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): One third of the compensation for the 2011 long-term incentive plan was paid in 2012; one third will be paid in 2013, with the remainder to be paid in 2014.
(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 listed above.

Short-Term Incentive Program

The methodology for determining awards under the short term incentive program does not exclusively or directly use corporate performance goals and results in setting individual awards, but these (including the metrics applied to the long term incentives determination) are considered along with individual performance, and the determination also depends on the application of subjective judgment.

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Long-Term Incentive Program

All employees 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. In the Upstream business, Harvest uses the following metrics as part of the assessment of corporate performance for the purpose of determining long term incentive payments: 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 as part of the assessment of corporate performance for the purposes of determining long term incentive payments: sales volume, EBITDA, non-fuel operating costs on a per boe basis and safety (lost time injury frequency). Amounts were based on these measures being met and the degree to which they were met along with individual performance.

Highlights of the corporate achievement are noted below:

•: Delivery of a cash contribution⁽¹⁾ from Upstream operations of $661 million versus $532 million in 2010;
•: Investment of $733 million in Upstream capital asset additions plus $505 million in net property and business acquisitions, resulting in net overall additions of more than 214% over 2010;
•: Strong production performance despite challenges imposed by third-party pipeline failures;
•: Strong health and safety performance in both Upstream and Downstream parts of the business;
•: Maintenance and enhancement of Harvest's presence in capital markets including expansion of the Credit Facility; 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.

(1): This is a non-GAAP measure. Upstream cash contribution is Upstream cash from operating activities of $663 million (2010—$514 million) less changes in Upstream non-cash working capital of $24 million (2010—$2 million) and the addition of settlements of decommissioning liabilities of $22 million (2010—$20 million). Please also refer to "Non-GAAP Measures" section for further details.

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RELATED PARTY TRANSACTIONS

Harvest's has a Global Technology and Research Centre ("GTRC"), is used as a training facility for KNOC personnel. For the three months ended March 31, 2012, Harvest billed KNOC and certain subsidiaries for a total of $0.5 million (2011—$1.6 million, 2010—$0.2 million) primarily related to technical services provided by the GTRC. As at March 31, 2012, $0.3 million (2011—$1.1 million, 2010—$0.1 million) remained outstanding from KNOC in accounts receivable. KNOC billed Harvest $nil (2011—$0.6 million, 2010—$ nil) for reimbursement to KNOC for secondee salaries paid by KNOC on behalf of Harvest for the three months ended March 31, 2012. As at March 31, 2011, $0.6 million (2011—$0.6 million, 2010—$nil) remains outstanding in accounts payable.

As at September 30, 2011, North Atlantic had committed to purchase $322.5 million of crude feedstock from KNOC, which MEC has taken over under the SOA (2011).

On August 6, 2010, Harvest acquired the BlackGold oil sands project from KNOC for $374.2 million, representing the fair value of the oil and gas assets acquired. The acquisition was paid with the issuance of shares to KNOC. The following amounts were added to Harvest's statement of financial position at August 6, 2010 as a result of this transaction:


Current assets	$	500
Property, plant and equipment		374,182
Long-term liabilities		(10	)
Decommissioning liabilities		(503	)

Shareholder's capital	$	(374,169	)

Directors and Key Management Personnel Remuneration

Key management personnel includes the Corporation's officers and other members of the executive management team. Included in the following table is remuneration to 5 (2010—9) independent directors and 15 (2010—14) key management personnel for the year ended December 31, 2011.

	Year Ended December 31

	2011		2010
Salaries, wages and short-term employee benefits	$	4,630	$	5,248
Post-employment benefits		49		49
Other long-term benefits		961		989

	$	5,640	$	6,286

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PRINCIPAL STOCKHOLDER

KNOC owns 100% of the 386,078,649 issued and outstanding common shares of Harvest at March 31, 2012; this information remains unchanged as at the date of this prospectus. KNOC is a leading international oil and gas exploration and production company wholly owned by the Government of Korea. 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.

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DESCRIPTION OF OTHER INDEBTEDNESS

For a description of our other indebtedness see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and Notes 10 and 12 of the audited consolidated financial statements for the year ended December 31, 2011, which have been included elsewhere in this prospectus.

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THE EXCHANGE OFFER

Terms of the Exchange Offer

We are offering to exchange our exchange notes for a like aggregate principal amount of our initial notes.

The exchange notes that we propose to issue in this exchange offer will be substantially identical to our initial notes except that, unlike our initial notes, the exchange notes will have no transfer restrictions or registration rights. You should read the description of the exchange notes in the section in this prospectus entitled "Description of Notes."

We reserve the right in our sole discretion to purchase or make offers for any initial notes that remain outstanding following the expiration or termination of this exchange offer and, to the extent permitted by applicable law, to purchase initial notes in the open market or privately negotiated transactions, one or more additional tender or exchange offers or otherwise. The terms and prices of these purchases or offers could differ significantly from the terms of this exchange offer.

Expiration Date; Extensions; Amendments; Termination

This exchange offer will expire at 5:00 p.m., New York City time, on August 1, 2012, unless we extend it in our reasonable discretion. The expiration date of this exchange offer will be at least 20 business days after the commencement of the exchange offer in accordance with Rule 14e-1(a) under the Securities Exchange Act of 1934, as amended (the "Exchange Act").

We expressly reserve the right to delay acceptance of any initial notes, extend or terminate this exchange offer and not accept any initial notes that we have not previously accepted if any of the conditions described below under "—Conditions to the Exchange Offer" have not been satisfied or waived by us. We will notify the exchange agent of any extension by oral notice promptly confirmed in writing or by written notice. We will also notify the holders of the initial notes by a press release or other public announcement communicated before 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date unless applicable laws require us to do otherwise.

We also expressly reserve the right to amend the terms of this exchange offer in any manner. If we make any material change, we will promptly disclose this change in a manner reasonably calculated to inform the holders of our initial notes of the change, including providing public announcement or giving oral or written notice to these holders. A material change in the terms of this exchange offer could include a change in the timing of the exchange offer, a change in the exchange agent and other similar changes in the terms of this exchange offer. If we make any material change to this exchange offer, we will disclose this change by means of a post-effective amendment to the registration statement which includes this prospectus and will distribute an amended or supplemented prospectus to each registered holder of initial notes. In addition, we will extend this exchange offer for an additional five to ten business days as required by the Exchange Act, depending on the significance of the amendment, if the exchange offer would otherwise expire during that period. We will promptly notify the exchange agent by oral notice, promptly confirmed in writing, or written notice of any delay in acceptance, extension, termination or amendment of this exchange offer.

Procedures for Tendering Initial Notes

Proper Execution and Delivery of Letters of Transmittal

To tender your initial notes in this exchange offer, you must use one of the three alternative procedures described below:

(1): Regular delivery procedure: Complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal. Have the signatures on the letter of transmittal guaranteed if

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required by the letter of transmittal. Mail or otherwise deliver the letter of transmittal or the facsimile together with the certificates representing the initial notes being tendered and any other required documents to the exchange agent on or before 5:00 p.m., New York City time, on the expiration date.

(2): Book-entry delivery procedure: Send a timely confirmation of a book-entry transfer of your initial notes, if this procedure is available, into the exchange agent's account at DTC in accordance with the procedures for book-entry transfer described under "—Book-Entry, Delivery Procedure" below, on or before 5:00 p.m., New York City time, on the expiration date.
(3): Guaranteed delivery procedure: If time will not permit you to complete your tender by using the procedures described in (1) or (2) above before the expiration date and this procedure is available, comply with the guaranteed delivery procedures described under "—Guaranteed Delivery Procedure" below.

The method of delivery of the initial notes, the letter of transmittal and all other required documents is at your election and risk. Instead of delivery by mail, we recommend that you use an overnight or hand-delivery service. If you choose the mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. You should not send any letters of transmittal or initial notes to us. You must deliver all documents to the exchange agent at its address provided below. You may also request your broker, dealer, commercial bank, trust company or nominee to tender your initial notes on your behalf.

Only a holder of initial notes may tender initial notes in this exchange offer. A holder is any person in whose name initial notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder.

If you are the beneficial owner of initial notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your notes, you must contact that registered holder promptly and instruct that registered holder to tender your initial notes on your behalf. If you wish to tender your initial notes on your own behalf, you must, before completing and executing the letter of transmittal and delivering your initial notes, either make appropriate arrangements to register the ownership of these notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.

You must have any signatures on a letter of transmittal or a notice of withdrawal guaranteed by:

(1)

a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc.;

(2)

a commercial bank or trust company having an office or correspondent in the United States; or

(3)

an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act, unless the initial notes are tendered:

(a): by a registered holder or by a participant in DTC whose name appears on a security position listing as the owner, who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the letter of transmittal and only if the exchange notes are being issued directly to this registered holder or deposited into this participant's account at DTC; or
(b): for the account of a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc., a commercial bank or trust company having

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an office or correspondent in the United States or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act.

If the letter of transmittal or any bond powers are signed by:

(1): the recordholder(s) of the initial notes tendered: the signature must correspond with the name(s) written on the face of the initial notes without alteration, enlargement or any change whatsoever.
(2): a participant in DTC: the signature must correspond with the name as it appears on the security position listing as the holder of the initial notes.
(3): a person other than the registered holder of any initial notes: these initial notes must be endorsed or accompanied by bond powers and a proxy that authorize this person to tender the initial notes on behalf of the registered holder, in satisfactory form to us as determined in our sole discretion, in each case, as the name of the registered holder or holders appears on the initial notes.
(4): trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity: these persons should so indicate when signing. Unless waived by us, evidence satisfactory to us of their authority to so act must also be submitted with the letter of transmittal.

To tender your initial notes in this exchange offer, you must make the following representations:

(1): you are authorized to tender, sell, assign and transfer the initial notes tendered and to acquire exchange notes issuable upon the exchange of such tendered initial notes, and that we will acquire good and unencumbered title to those initial notes, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim when the same are accepted by us;
(2): any exchange notes acquired by you pursuant to the exchange offer are being acquired in the ordinary course of business, whether or not you are the holder;
(3): you or any other person who receives exchange notes, whether or not such person is the holder of the exchange notes, has no arrangement or understanding with any person to participate in a distribution of such exchange notes within the meaning of the Securities Act and is not participating in, and does not intend to participate in, the distribution of such exchange notes within the meaning of the Securities Act;
(4): you or such other person who receives exchange notes, whether or not such person is the holder of the exchange notes, is not an "affiliate," as defined in Rule 405 of the Securities Act, of ours, or if you or such other person is an affiliate, you or such other person will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;
(5): if you are not a broker-dealer, you represent that you are not engaging in, and do not intend to engage in, a distribution of exchange notes; and
(6): if you are a broker-dealer that will receive exchange notes for your own account in exchange for initial notes, you represent that the initial notes to be exchanged for the exchange notes were acquired by you as a result of market-making or other trading activities and acknowledge that you will deliver a prospectus in connection with any resale, offer to resell or other transfer of such exchange notes.

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You must also warrant that the acceptance of any tendered initial notes by Harvest and the issuance of exchange notes in exchange therefor shall constitute performance in full by Harvest of its obligations under the registration rights agreement relating to the initial notes.

To effectively tender notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automatic Tender Offer Program. DTC will then edit and verify the acceptance and send an agent's message to the exchange agent for its acceptance. An agent's message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant.

Book-Entry Delivery Procedure

Any financial institution that is a participant in DTC's systems may make book-entry deliveries of initial notes by causing DTC to transfer these initial notes into the exchange agent's account at DTC in accordance with DTC's procedures for transfer. To effectively tender notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automatic Tender Offer Program. DTC will then edit and verify the acceptance and send an agent's message to the exchange agent for its acceptance. An agent's message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the notes that this participation has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant. The exchange agent will make a request to establish an account for the initial notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus.

A delivery of initial notes through a book-entry transfer into the exchange agent's account at DTC will only be effective if an agent's message or the letter of transmittal or a facsimile of the letter of transmittal with any required signature guarantees and any other required documents is transmitted to and received by the exchange agent at the address indicated below under "—Exchange Agent" on or before the expiration date unless the guaranteed delivery procedures described below are complied with.Delivery of documents to DTC does not constitute delivery to the exchange agent.

Guaranteed Delivery Procedure

If you are a registered holder of initial notes and desire to tender your notes, and (1) these notes are not immediately available, (2) time will not permit your notes or other required documents to reach the exchange agent before the expiration date or (3) the procedures for book-entry transfer cannot be completed on a timely basis and an agent's message delivered, you may still tender in this exchange offer if:

(1): you tender through a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc., a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act;
(2): on or before the expiration date, the exchange agent receives a properly completed and duly executed letter of transmittal or facsimile of the letter of transmittal, and a notice of guaranteed delivery, substantially in the form provided by us, with your name and address as holder of the initial notes and the amount of notes tendered, stating that the tender is being made by that letter and notice and guaranteeing that within three New York Stock Exchange trading days after the expiration date the certificates for all the initial notes tendered, in proper form for transfer, or a book-entry confirmation with an agent's message, as the case

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may be, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

(3): the certificates for all your tendered initial notes in proper form for transfer or a book-entry confirmation as the case may be, and all other documents required by the letter of transmittal are received by the exchange agent within three New York Stock Exchange trading days after the expiration date.

Acceptance of Initial Notes for Exchange; Delivery of Exchange Notes

Your tender of initial notes will constitute an agreement between you and us governed by the terms and conditions provided in this prospectus and in the related letter of transmittal.

We will be deemed to have received your tender as of the date when your duly signed letter of transmittal accompanied by your initial notes tendered, or a timely confirmation of a book-entry transfer of these notes into the exchange agent's account at DTC with an agent's message, or a notice of guaranteed delivery from an eligible institution, is received by the exchange agent.

All questions as to the validity, form, eligibility, including time of receipt, acceptance and withdrawal of tenders will be determined by us in our sole discretion. Our determination will be final and binding.

We reserve the absolute right to reject any and all initial notes not properly tendered or any initial notes which, if accepted, would, in our opinion or our counsel's opinion, be unlawful. We also reserve the absolute right to waive any conditions of this exchange offer or irregularities or defects in tender as to particular notes with the exception of conditions to this exchange offer relating to the obligations of broker dealers, which we will not waive. If we waive a condition to this exchange offer, the waiver will be applied equally to all note holders. Our interpretation of the terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of initial notes must be cured within such time as we shall determine. We, the exchange agent or any other person will be under no duty to give notification of defects or irregularities with respect to tenders of initial notes. We and the exchange agent or any other person will incur no liability for any failure to give notification of these defects or irregularities. Tenders of initial notes will not be deemed to have been made until such irregularities have been cured or waived. The exchange agent will return without cost to their holders any initial notes that are not properly tendered and as to which the defects or irregularities have not been cured or waived promptly following the expiration date.

If all the conditions to the exchange offer are satisfied or waived on the expiration date, we will accept all initial notes properly tendered and will issue the exchange notes promptly thereafter. Please refer to the section of this prospectus entitled "—Conditions to the Exchange Offer" below. For purposes of this exchange offer, initial notes will be deemed to have been accepted as validly tendered for exchange when, as and if we give oral or written notice of acceptance to the exchange agent.

We will issue the exchange notes in exchange for the initial notes tendered pursuant to a notice of guaranteed delivery by an eligible institution only against delivery to the exchange agent of the letter of transmittal, the tendered initial notes and any other required documents, or the receipt by the exchange agent of a timely confirmation of a book-entry transfer of initial notes into the exchange agent's account at DTC with an agent's message, in each case, in form satisfactory to us and the exchange agent.

If any tendered initial notes are not accepted for any reason provided by the terms and conditions of this exchange offer or if initial notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged initial notes will be returned without expense to the tendering holder, or, in the case of initial notes tendered by book-entry transfer procedures

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described above, will be credited to an account maintained with the book-entry transfer facility, promptly after withdrawal, rejection of tender or the expiration or termination of the exchange offer.

By tendering into this exchange offer, you will irrevocably appoint our designees as your attorney-in-fact and proxy with full power of substitution and resubstitution to the full extent of your rights on the notes tendered. This proxy will be considered coupled with an interest in the tendered notes. This appointment will be effective only when, and to the extent that we accept your notes in this exchange offer. All prior proxies on these notes will then be revoked and you will not be entitled to give any subsequent proxy. Any proxy that you may give subsequently will not be deemed effective. Our designees will be empowered to exercise all voting and other rights of the holders as they may deem proper at any meeting of note holders or otherwise. The initial notes will be validly tendered only if we are able to exercise full voting rights on the notes, including voting at any meeting of the note holders, and full rights to consent to any action taken by the note holders.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw tenders of initial notes at any time before 5:00 p.m., New York City time, on the expiration date.

For a withdrawal to be effective, you must send a written or facsimile transmission notice of withdrawal to the exchange agent before 5:00 p.m., New York City time, on the expiration date at the address provided below under "—Exchange Agent" and before acceptance of your tendered notes for exchange by us.

Any notice of withdrawal must:

(1): specify the name of the person having tendered the initial notes to be withdrawn;
(2): identify the notes to be withdrawn, including, if applicable, the registration number or numbers and total principal amount of these notes;
(3): be signed by the person having tendered the initial notes to be withdrawn in the same manner as the original signature on the letter of transmittal by which these notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer sufficient to permit the trustee for the initial notes to register the transfer of these notes into the name of the person having made the original tender and withdrawing the tender;
(4): specify the name in which any of these initial notes are to be registered, if this name is different from that of the person having tendered the initial notes to be withdrawn; and
(5): if applicable because the initial notes have been tendered through the book-entry procedure, specify the name and number of the participant's account at DTC to be credited, if different than that of the person having tendered the initial notes to be withdrawn.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of all notices of withdrawal and our determination will be final and binding on all parties. Initial notes that are withdrawn will be deemed not to have been validly tendered for exchange in this exchange offer.

The exchange agent will return without cost to their holders all initial notes that have been tendered for exchange and are not exchanged for any reason, promptly after withdrawal, rejection of tender or expiration or termination of this exchange offer.

You may retender properly withdrawn initial notes in this exchange offer by following one of the procedures described under "—Procedures for Tendering Initial Notes" above at any time on or before the expiration date.

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Conditions to the Exchange Offer

We will complete this exchange offer only if:

(1): there is no change in the laws and regulations which would reasonably be expected to impair our ability to proceed with this exchange offer;
(2): there is no change in the current interpretation of the staff of the SEC which permits resales of the exchange notes; and
(3): there is no stop order issued by the SEC or any state securities authority suspending the effectiveness of the registration statement which includes this prospectus or the qualification of the Note Indenture for our exchange notes under the Trust Indenture Act of 1939 and there are no proceedings initiated or, to our knowledge, threatened for that purpose.

These conditions are for our sole benefit. We may assert any one of these conditions regardless of the circumstances giving rise to it and may also waive any one of them, in whole or in part, at any time and from time to time, if we determine in our reasonable discretion that it has not been satisfied, subject to applicable law. Notwithstanding the foregoing, all conditions to the exchange offer must be satisfied or waived before the expiration of this exchange offer. If we waive a condition to this exchange offer, the waiver will be applied equally to all note holders.

If we determine that we may terminate this exchange offer because any of these conditions is not satisfied, we may:

(1): refuse to accept and return to their holders any initial notes that have been tendered;
(2): extend the exchange offer and retain all notes tendered before the expiration date, subject to the rights of the holders of these notes to withdraw their tenders; or
(3): waive any condition that has not been satisfied and accept all properly tendered notes that have not been withdrawn or otherwise amend the terms of this exchange offer in any respect as provided under the section in this prospectus entitled "—Expiration Date; Extensions; Amendments; Termination."

Accounting Treatment

We will record the exchange notes at the same carrying value as the initial notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. We will amortize the costs of the initial note offering and the exchange offer over the term of the notes.

Exchange Agent

We have appointed U.S. Bank National Association as exchange agent for this exchange offer. You should direct all questions and requests for assistance on the procedures for tendering and all requests for additional copies of this prospectus or the letter of transmittal to the exchange agent as follows:

By mail or hand/overnight delivery:

U.S. Bank National Association, as Exchange Agent
60 Livingston Avenue
St Paul MN 55107
Attention: Specialized Finance
Facsimile Transmission: 651-466-7372
Confirm by Telephone: 800-934-6802

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Fees and Expenses

We and the guarantors will bear the expenses of soliciting tenders in this exchange offer, including fees and expenses of the exchange agent and trustee and accounting, legal, printing and related fees and expenses.

We will not make any payments to brokers, dealers or other persons soliciting acceptances of this exchange offer. However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse the exchange agent for its reasonable out-of-pocket expenses in connection with this exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries their reasonable out-of-pocket expenses for forwarding copies of the prospectus, letters of transmittal and related documents to the beneficial owners of the initial notes and for handling or forwarding tenders for exchange to their customers.

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

The initial notes were not registered under the Securities Act or under the securities laws of any state and you may not resell them, offer them for resale or otherwise transfer them unless they are subsequently registered or resold under an exemption from the registration requirements of the Securities Act and applicable state securities laws. If you do not exchange your initial notes for exchange notes in accordance with this exchange offer, or if you do not properly tender your initial notes in this exchange offer, you will not be able to resell, offer to resell or otherwise transfer the initial notes unless they are registered under the Securities Act or unless you resell them, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

In addition, except as set forth in this paragraph, you will not be able to obligate us to register the initial notes under the Securities Act. You will not be able to require us to register your initial notes under the Securities Act unless:

(1): you are prohibited by law or SEC policy from participating in the exchange offer;
(2): you may not resell the exchange notes you acquire in the exchange offer to the public without delivering a prospectus and that the prospectus contained in the exchange offer registration statement is not appropriate or available for such resales by you; or
(3): you are a broker-dealer and hold initial notes acquired directly from us or one of our affiliates,

in which case the registration rights agreement requires us to file a registration statement for a continuous offer in accordance with Rule 415 under the Securities Act for the benefit of the holders of the initial notes described in this sentence. We do not currently anticipate that we will register under the Securities Act any notes that remain outstanding after completion of the exchange offer.

Delivery of Prospectus

Each broker-dealer that receives exchange notes for its own account in exchange for initial notes, where such initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. See "Plan of Distribution."

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DESCRIPTION OF NOTES

Harvest Operations Corp. issued the initial notes and will issue the exchange notes under the existing indenture, dated as of October 4, 2010, among itself, the Initial Subsidiary Guarantors, as guarantors, and U.S. Bank National Association, as trustee. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended.

The following description is a summary of the material provisions of the indenture. It does not restate the indenture in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the notes. Copies of the indenture are available as set forth below under "—Additional Information." Certain defined terms used in this description but not defined below under "—Certain Definitions" have the meanings assigned to them in the indenture.

General

The registered Holder of a note will be treated as the owner of it for all purposes. Only registered Holders will have rights under the indenture.

An aggregate principal amount of initial notes equal to US$500 million was issued on October 4, 2010 which will be exchanged for an aggregate principal amount of exchange notes equal to US$500 million issued in this exchange offer. The notes are unsecured unsubordinated obligations of the Issuer, initially limited to US$500 million aggregate principal amount. The notes are guaranteed by each of the Issuer's subsidiaries that guarantees the Issuer's obligation under the Credit Facilities. The Guarantees are unsecured unsubordinated obligations of the Subsidiary Guarantors. The notes will mature on October 1, 2017. Subject to the covenants described below under "Certain Covenants," the Issuer may issue additional notes ("Additional Notes") under the indenture. The initial notes, exchange notes and any Additional Notes would be treated as a single class for all purposes under the indenture.

Each note bears interest at the rate per annum shown on the cover page of this Prospectus from the Closing Date or from the most recent interest payment date to which interest has been paid. Interest on the exchange notes will be payable semiannually on April 1 and October 1 of each year, commencing October 1, 2012. Interest will be paid to Holders of record at the close of business on the March 15 or September 15 immediately preceding the Interest Payment Date. Interest is computed on the basis of a 360-day year of twelve 30-day months on a U.S. corporate bond basis.

The notes will be issued only in fully registered form, without coupons, in denominations of US$2,000 and integral multiples of US$1,000 in excess thereof. See "—Book-Entry; Delivery and Form." No service charge will be made for any registration of transfer or exchange of notes, but the Issuer may require payment of a sum sufficient to cover any transfer tax or other similar governmental charge payable in connection therewith.

Optional Redemption

The notes are subject to redemption at the Issuer's option, in whole or in part, at any time or from time to time, upon not less than 30 nor more than 60 days' notice at a redemption price equal to the greater of (1) 100% of the principal amount of the notes to be redeemed and (2) the sum of the present values of the remaining principal and interest payments on the applicable notes (exclusive of interest accrued to the date of redemption) discounted to the redemption date, calculated on a semi-annual basis (assuming a 360-day year comprised of twelve 30-day months), at the Treasury Rate plus 50 basis points, together with accrued and unpaid interest, if any (including Additional Interest, if any), to the date of redemption, subject to the rights of Holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

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

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

However, no note of US$2,000 in principal amount or less shall be redeemed in part and no note may be redeemed in part if the remaining principal amount would be less than US$2,000. If any note is to be redeemed in part only, the notice of redemption relating to such note will state the portion of the principal amount to be redeemed. A new note in principal amount equal to the unredeemed portion will be issued upon cancellation of the original note.

Tax Redemption

The Issuer may redeem the notes, in whole but not in part, at a redemption price equal to the principal amount of the notes to be redeemed, plus accrued and unpaid interest on the principal amount of notes being redeemed to but excluding the date of redemption upon the giving of a notice as described below, if:

(1) as a result of any change (including any announced prospective change) in, repeal of, or amendment to the laws (or any regulations or rulings promulgated thereunder) of Canada or of any political subdivision or taxing authority thereof or therein affecting taxation, or any change in official position regarding the application or interpretation of such laws, regulations or rulings (including a holding, judgment or order by a court of competent jurisdiction), which change or amendment is announced or becomes effective on or after the date of this prospectus (or, in the case of a successor to the Issuer, after the date of succession), and which in the written opinion to the Issuer of legal counsel of recognized standing has resulted or will result (assuming, in the case of any announced prospective change, that such announced change will become effective as of the date specified in such announcement and in the form announced) in the Issuer becoming obligated to pay, on the next succeeding date on which interest is due, Additional Amounts with respect to the notes as described under "Additional Amounts for Canadian Withholding Taxes;" or

(2) on or after the date of this prospectus (or, in the case of a successor to the Issuer, after the date of succession), any action has been taken by any taxing authority of, or any decision has been rendered by a court of competent jurisdiction in, Canada or any political subdivision or taxing authority thereof or therein, including any of those actions specified in the paragraph immediately above, whether or not such action was taken or decision was rendered with respect to the Issuer (or its successor), or any change, amendment, application or interpretation shall be officially proposed, which, in any such case, in the written opinion to the Issuer of legal counsel of recognized standing, will result (assuming, in the case of any announced prospective change, that such announced change will become effective as of the date specified in such announcement and in the form announced) in the Issuer becoming obligated to pay, on the next succeeding date on which interest is due, Additional Amounts with respect to the notes;

and, in any such case, the Issuer (or its successor), in its business judgment, determines that such obligation cannot be avoided by the use of reasonable measures available to the Issuer (or its successor).

In the event the Issuer elects to redeem the notes pursuant to the provisions set forth in the preceding paragraph, the Issuer will deliver to the Trustee a certificate, signed by an authorized officer, stating that the Issuer is entitled to redeem such notes pursuant to their terms.

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Notice of intention to redeem such notes will be given to Holders of the notes not more than 45 nor less than 30 days prior to the date fixed for redemption and such notice will specify, among other things, the date fixed for redemption and the redemption price.

Guarantees

Payment of the principal of, premium, if any, and interest on the notes will be fully and unconditionally Guaranteed, jointly and severally, on an unsecured unsubordinated basis by all of the Restricted Subsidiaries that Guarantee the Issuer's obligations under the Credit Facilities.

Each Subsidiary Guarantor that makes a payment or distribution under its Note Guarantee will be entitled to contribution from any other Subsidiary Guarantor.

The obligations of each Subsidiary Guarantor under its Note Guarantee will be limited so as not to constitute a fraudulent conveyance under applicable federal, provincial or state laws. The Issuer cannot assure you that this limitation will protect the Note Guarantees from fraudulent transfer challenges or, if it does, that the remaining amount due and collectible under the Note Guarantees would suffice, if necessary, to pay the notes in full when due. In a recent Florida bankruptcy case, this kind of provision was found to be unenforceable and, as a result, the subsidiary guarantees in that case were found to be fraudulent conveyances. The Issuer does not know if that case will be followed if there is litigation on this point under the indenture. However, if it is followed, the risk that the Note Guarantees will be found to be fraudulent conveyances will be significantly increased.

The Note Guarantee issued by any Subsidiary Guarantor will be automatically and unconditionally released and discharged:

(1) any sale, exchange or transfer, to any Person not an Affiliate of the Issuer, of the Capital Stock in such Restricted Subsidiary such that such Subsidiary Guarantor ceases to constitute a Restricted Subsidiary or upon the designation of such Restricted Subsidiary as an Unrestricted Subsidiary in accordance with the terms of the indenture;

(2) if such Subsidiary Guarantor is designated as an Unrestricted Subsidiary or otherwise ceases to be a Subsidiary Guarantor, in each case in accordance with the provisions of the indenture, upon effectiveness of such designation or when it first ceases to be a Restricted Subsidiary, respectively;

(3) the release or discharge of the Guarantee which resulted in the creation of such Note Guarantee (including the Credit Agreement), except a discharge or release by or as a result of payment under such Guarantee;

(4) upon the legal defeasance or covenant defeasance or satisfaction and discharge of the indenture; or

(5) upon payment in full of the aggregate principal amount of all notes then outstanding and all other obligations under the indenture and the notes then due and owing.

Ranking

The notes will be equal in right of payment with all existing and future unsubordinated indebtedness of the Issuer and senior in right of payment to all future subordinated indebtedness of the Issuer, The Note Guarantees will be equal in right of payment with all existing and future unsubordinated indebtedness of the Subsidiary Guarantors and senior in right of payment to all future subordinated indebtedness of the Subsidiary Guarantors.

Claims of creditors of Subsidiaries of the Issuer that are not Subsidiary Guarantors, including trade creditors and creditors holding Indebtedness or guarantees issued by such Subsidiaries, and claims of

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holders of preferred stock (if any) of such Subsidiaries generally, will have priority with respect to the assets and earnings of such Subsidiaries over the claims of our creditors, including Holders. Accordingly, the notes will be effectively subordinated to creditors (including trade creditors) and holders of Preferred Stock, if any, of the Issuer's Subsidiaries that are not Subsidiary Guarantors. In the future, the Issuer may have additional Subsidiaries that are not Subsidiary Guarantors.

As at March 31, 2012, (1) the Issuer had $1,767 million of Indebtedness, $534.7 million of which is secured indebtedness under the Credit Agreement; (2) the Initial Subsidiary Guarantors have Guaranteed our Indebtedness under the Credit Agreement but had no additional Indebtedness; and (3) the Issuer's Subsidiaries that are not guaranteeing the notes had approximately $13.9 million of liabilities (including trade payables). For the twelve-month period ended March 31, 2012, the non-guarantor Subsidiaries generated 2% of the Issuer's consolidated revenues and 0% of the Issuer's consolidated EBITDA. The Credit Agreement is secured by substantially all of the assets of the Issuer and its subsidiaries. The notes and the Note Guarantees of the Subsidiary Guarantors are effectively subordinated to such indebtedness to the extent of such security interests.

Additional Amounts for Canadian Withholding Taxes

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

The Issuer will furnish the Holders of the notes, within 30 days after the date the payment of any Taxes is due pursuant to applicable law, certified copies of tax receipts evidencing such payment by the Issuer or such Subsidiary Guarantor, or if receipts are not available, obtain other evidence of payment and of any other information returns applicable in Canada that are required to be filed with the proper taxing authorities. The Issuer or such Subsidiary Guarantor will, upon written request of each Holder (other than an Excluded Holder), reimburse each such Holder for the amount of (x) any Taxes so levied or imposed and paid by such Holder as a result of payments made under or with respect to the

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notes, and (y) any Taxes so levied or imposed with respect to any reimbursement under the foregoing clause (x) but excluding any such Taxes on such Holder's net income so that the net amount received by such Holder (net of payments made under or with respect to the notes) after such reimbursement will not be less than the net amount the Holder would have received if Taxes on such reimbursement had not been imposed.

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

The obligation to pay Additional Amounts and any indemnification payments under the terms and conditions described above will survive any termination or discharge of the indenture.

Mandatory Redemption; Sinking Fund; Open Market Purchases

The Issuer is not required to make any mandatory redemption or sinking fund payments with respect to the notes. The Issuer and its Affiliates may at any time and from time to time purchase notes in the open market or otherwise.

Certain Covenants

Covenant Suspension

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

(1) the provisions of the indenture described under:

•: "—Limitation on Indebtedness;"
•: "—Limitation on Restricted Payments" (except to the extent applicable under the definition of "Unrestricted Subsidiary");
•: "—Limitation on Transactions with Affiliates;"
•: "Repurchase of Notes upon a Change of Control;" and
•: clause (3) of "Consolidation, Amalgamation, Merger and Sale of Assets;" or

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

If the Issuer and its Restricted Subsidiaries are not subject to these covenants for any period of time as a result of the previous sentence (a "Fall-Away Period") and, subsequently, the ratings assigned to the notes are withdrawn or downgraded so the notes no longer have Investment Grade Ratings or an Event of Default (other than with respect to a suspended covenant) occurs and is continuing, then the Issuer and its Restricted Subsidiaries will thereafter again be subject to these covenants. The ability of the Issuer and its Restricted Subsidiaries to make Restricted Payments after the time of such withdrawal, downgrade or Event of Default will be calculated as if the covenant governing Restricted

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Payments had been in effect during the entire period of time from the Closing Date. Notwithstanding the foregoing, the continued existence after the end of the Fall-Away Period of facts and circumstances or obligations arising from transactions which occurred during a Fall-Away Period shall not constitute a breach of any covenant set forth in the indenture or cause an Event of Default thereunder. All Indebtedness Incurred during the Fall-Away Period will be classified to have been Incurred pursuant to clause (a) of the covenant described under "—Limitation on Indebtedness" or one of the clauses set forth in clause (b) of the covenant described under "—Limitation on Indebtedness" (to the extent such Indebtedness would be permitted to be Incurred thereunder as of the end of the Fall-Away Period and after giving effect to Indebtedness Incurred prior to the beginning of the Fall-Away Period). To the extent such Indebtedness would not be so permitted to be Incurred pursuant to clause (a) or (b) of the covenant described under "—Limitation on Indebtedness," such Indebtedness will be deemed to have been outstanding on the Closing Date, so that it is classified as permitted under clause (b)(10) of the covenant described under "—Limitation on Indebtedness."

Limitation on Indebtedness

(a) The Issuer will not, and will not permit any of its Restricted Subsidiaries to, Incur any additional Indebtedness;provided that the Issuer or any Subsidiary Guarantor may Incur additional Indebtedness, if, after giving effect to the Incurrence of such additional Indebtedness the Interest Coverage Ratio would be greater than 2.0:1.

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

(1) Indebtedness under Credit Facilities of the Issuer or any Restricted Subsidiary outstanding at any time in an aggregate principal amount (together with refinancings thereof) not to exceed the greater of (a) $1.0 billion, and (b) 15.0% of Total Assets;

(2) Indebtedness owed (A) to the Issuer or any Subsidiary Guarantor or (B) to any other Restricted Subsidiary;provided in the case of clauses (A) and (B) that (x) any event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any subsequent transfer of such Indebtedness (other than to the Issuer or another Restricted Subsidiary) shall be deemed, in each case, to constitute an Incurrence of such Indebtedness not permitted by this clause (2) and (y) if the Issuer or any Subsidiary Guarantor is the obligor on such Indebtedness and such debt is owed to a non-Subsidiary Guarantor, such Indebtedness must be subordinate in right of payment to the notes, in the case of the Issuer, or the Note Guarantee, in the case of a Subsidiary Guarantor;

(3) the notes (excluding Additional Notes) and the Note Guarantees and related Note Guarantees;

(4) Indebtedness issued in exchange for, or the net proceeds of which are used (or will be used within 90 days) to refinance, repay, redeem, repurchase or refund then outstanding Indebtedness (other than Indebtedness outstanding under clause (2), (6), (9), (11) and (12)) and any refinancings thereof in an amount not to exceed the amount so refinanced or repaid (plus premiums, accrued interest, fees and expenses);provided that (a) Indebtedness the proceeds of which are used to refinance or repay the notes or Indebtedness that ispari passu with, or subordinated in right of payment to, the notes or a Note Guarantee shall only be permitted under this clause (3) if (x) in case the notes are refinanced in part or the Indebtedness to be refinanced ispari passu with the notes or a Note Guarantee, such new Indebtedness, by its terms or by the terms of any agreement or instrument pursuant to which such new Indebtedness is outstanding, ispari passu with, or subordinate in right of payment to, the remaining notes or the Note Guarantee, or (y) in case the Indebtedness to be refinanced is subordinated in right of payment to the notes or a Note Guarantee, such new Indebtedness, by its terms or by the terms of any agreement or

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instrument pursuant to which such new Indebtedness is issued or remains outstanding, is subordinate in right of payment to the notes or the Note Guarantee at least to the extent that the Indebtedness to be refinanced is subordinated to the notes or the Note Guarantee, (b) such new Indebtedness, determined as of the date of Incurrence of such new Indebtedness, does not mature prior to the Stated Maturity of the Indebtedness to be refinanced or repaid, and the Average Life of such new Indebtedness is at least equal to the remaining Average Life of the Indebtedness to be refinanced or repaid and (c) such new Indebtedness may not refinance Indebtedness of the Issuer or a Subsidiary Guarantor if it is incurred by a Restricted Subsidiary that is not a Subsidiary Guarantor;

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

(6) Guarantees of Indebtedness of the Issuer or any Subsidiary Guarantor by any Restricted Subsidiary provided the Guarantee of such Indebtedness is permitted by and made in accordance with the covenant described under "—Limitation on Issuance of Guarantees by Restricted Subsidiaries;"

(7) Indebtedness of the Issuer or any Restricted Subsidiary (in addition to Indebtedness permitted under clauses (1) through (6) above and (8) through (13) below) in an aggregate principal amount outstanding at any time (together with refinancings thereof) not to exceed $250.0 million;

(8) Indebtedness (including capitalized Lease Obligations) incurred by the Issuer or any Restricted Subsidiary to finance or reimburse the cost of the acquisition, development, construction, purchase, lease, repair, addition or improvement of property (real or personal), equipment or other fixed or capital assets that are used or useful in the Oil and Gas Business, whether through the direct purchase of assets or the Capital Stock of any Person owning such assets (incurred within 365 days of such acquisition, development, construction, purchase, lease, repair, addition or improvement), in an aggregate principal amount outstanding at any time (together with refinancings thereof) not to exceed the greater of (a) $100.0 million and (b) 2.0% of Total Assets;

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

(10) any Indebtedness existing on the Closing Date (other than Indebtedness under the Credit Agreement);

(11) Indebtedness incurred by the Issuer or any Restricted Subsidiary constituting reimbursement obligations with respect to letters of credit issued in the ordinary course of business, including letters of credit in respect of workers' compensation claims, or other Indebtedness with respect to reimbursement type obligations regarding workers' compensation claims, self-insurance obligations and bankers' acceptances in the ordinary course of business;provided that upon the drawing of such letters of credit or the incurrence of such Indebtedness, such obligations are reimbursed within 30 days following such drawing or incurrence;

(12) Acquired Debt of the Issuer or any of its Restricted Subsidiaries;provided that after giving effect to such acquisition or merger ona pro forma basis, either (A) the Issuer would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Interest Coverage Ratio test set forth in clause (a) of this covenant; or (B) the Interest Coverage Ratio of the Issuer

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and the Restricted Subsidiaries on a consolidated basis would be greater than the Interest Coverage Ratio immediately prior to such acquisition or merger; and

(13) Indebtedness Incurred to finance the purchase of oil and gas inventory and other feedstocks used to produce oil and gas refined products at the Refinery.

(c) Notwithstanding any other provision of this "Limitation on Indebtedness" covenant, the maximum amount of Indebtedness that may be Incurred pursuant to this "Limitation on Indebtedness" covenant will not be deemed to be exceeded, with respect to any outstanding Indebtedness due solely to the result of fluctuations in the exchange rates of currencies.

(d) For purposes of determining any particular amount of Indebtedness under this "Limitation on Indebtedness" covenant, (x) Indebtedness Incurred under the Credit Agreement on or prior to the Closing Date shall be treated as Incurred pursuant to clause (b)(1) of this "Limitation on Indebtedness" covenant, (y) Guarantees, Liens or obligations with respect to letters of credit supporting Indebtedness otherwise included in the determination of such particular amount shall not be included as Indebtedness and (z) any Liens granted pursuant to the equal and ratable provisions referred to in the covenant described under "—Limitation on Liens" shall not be treated as Indebtedness. For purposes of determining compliance with this "Limitation on Indebtedness" covenant, in the event that an item of Indebtedness meets the criteria of more than one of the types of Indebtedness described above (other than Indebtedness referred to in clause (x) of the preceding sentence), including under clause (a), the Issuer, in its sole discretion, shall classify, and from time to time may divide and reclassify (based on circumstances existing at the time of such division or reclassification), all or any portion of such item of Indebtedness and will only be required to include such Indebtedness in one of the above clauses (a) or (b).

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

Limitation on Restricted Payments

(a) The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly:

(1) declare or pay any dividend or make any distribution on or with respect to its Capital Stock (other than (x) dividends or distributions payable solely in its Capital Stock (other than Disqualified Stock) or in options, warrants or other rights to acquire such Capital Stock and (y) pro rata dividends or distributions on Common Stock of Restricted Subsidiaries held by minority equityholders) held by Persons other than the Issuer or any of its Restricted Subsidiaries;

(2) purchase, call for redemption or redeem, retire or otherwise acquire for value any Capital Stock of the Issuer or any Subsidiary Guarantor (including options, warrants or other rights to acquire such Capital Stock) held by any Person (other than the Issuer or a Subsidiary Guarantor);

(3) make any voluntary or optional principal payment, or voluntary or optional redemption, repurchase, defeasance, or other voluntary or optional acquisition or retirement for value, of any Indebtedness of (i) the Issuer that is subordinated in right of payment to the notes, or (ii) a Subsidiary Guarantor that is subordinated in right of payment to a Note Guarantee except (x) the

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purchase, repurchase or other acquisition of subordinated Indebtedness of the Issuer or any Restricted Subsidiary purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase or acquisition or (y) intercompany Indebtedness Incurred pursuant to clause (b)(2) under the caption "—Limitation on Indebtedness;" or

(4) make any Investment, other than a Permitted Investment, in any Person (such payments or any other actions described in clauses (1) through (4) above being collectively "Restricted Payments")

unless, at the time of, and after giving effect to, the proposed Restricted Payment:

(1) no Default or Event of Default shall have occurred and be continuing, and

(2) the Issuer could Incur at least $1.00 of additional Indebtedness pursuant to the Interest Coverage Ratio test set forth under clause (a) of the covenant described under "—Limitation on Indebtedness;" and

(3) such Restricted Payment, together with the aggregate of all other Restricted Payments made by the Issuer and the Restricted Subsidiaries after the Closing Date, is less than the sum, without duplication, of:

(A) 50% of the Adjusted Consolidated Net Income on a cumulative basis during the period (taken as one accounting period) beginning on the first day of the first fiscal quarter during which the Closing Date occurs and ending on the last day of the Issuer's last fiscal quarter ending prior to the date of such proposed Restricted Payment for which internal financial statements are available (or, if such Adjusted Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

(B) the aggregate Net Cash Proceeds or fair market value of any property (other than cash) received by the Issuer since the Closing Date as a contribution to its common equity capital or from the issue or sale of Capital Stock (other than Disqualified Stock) of the Issuer and the amount of reduction of Indebtedness of the Issuer or its Restricted Subsidiaries that has been converted into or exchanged for such Capital Stock (other than Disqualified Stock or Capital Stock sold to, or Indebtedness held by, a Subsidiary of the Issuer), plus

(C) with respect to Investments (other than Permitted Investments) made by the Issuer and its Restricted Subsidiaries after the Closing Date, an amount equal to the cash return, and the fair market value of property received as a result of the repayment to the Issuer or any Restricted Subsidiary of loans or advances or from the sale of any such Investment, from the release of any Guarantee (except to the extent any amounts are paid under such Guarantee) or from redesignations of Unrestricted Subsidiaries as Restricted Subsidiaries (except, in each case, to the extent any such amount is included in the calculation of Consolidated Net Income).

(b) The preceding provisions will not prohibit:

(1) the payment of any dividend, distribution on or redemption of any Capital Stock within 60 days after the related date of declaration of a dividend or distribution or call for redemption if, at said date of declaration of a dividend or distribution or call for redemption, such payment or redemption would comply with the provisions of the indenture;

(2) the redemption, repurchase, defeasance or other acquisition or retirement for value of Indebtedness that is subordinated in right of payment to the notes or any Note Guarantee including premium, if any, and accrued interest, with the proceeds of, or in exchange for,

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Indebtedness Incurred under clause (b)(4) of the covenant described under "—Limitation on Indebtedness;"

(3) any Restricted Payment in exchange for, or out of the proceeds of a capital contribution or a substantially concurrent offering of, Capital Stock (other than Disqualified Stock) of the Issuer (or options, warrants or other rights to acquire such Capital Stock) (occurring within 60 days of such repurchase, redemption, retirement or other acquisition); provided that (a) such options, warrants or other rights are not redeemable at the option of the holder, or required to be redeemed, prior to the Stated Maturity of the notes; and (b) the amount of any such Net Cash Proceeds or the fair market value of any property (other than cash) received that are utilized for any such Restricted Payment will be excluded from clause (3)(B) of the second paragraph of clause (a) of this "—Limitation on Restricted Payments" covenant;

(4) the purchase, repayment or redemption at any time of the Issuer's Convertible Debentures.

(5) payments or distributions to dissenting stockholders pursuant to applicable law, pursuant to or in connection with a consolidation, amalgamation, merger or transfer of assets of the Issuer that complies with the provisions of the indenture applicable to mergers, consolidations, amalgamations and transfers of all or substantially all of the property and assets of the Issuer;

(6) the repurchase of Capital Stock deemed to occur upon the exercise of options or warrants if such Capital Stock represents all or a portion of the exercise price thereof;

(7) the repurchase, redemption, repayment or other defeasance of Disqualified Stock when due pursuant to its terms;

(8) the declaration and payment of dividends on Disqualified Stock issued pursuant to the covenant described under "—Limitation on Indebtedness;" to the extent such dividends constitute Consolidated Interest Expense;

(9) other Restricted Payments; provided that after giving effect to such Restricted Payment and any Indebtedness Incurred to fund such Restricted Payment, the Consolidated Leverage Ratio is less than 2.5:1;

(10) other Restricted Payments in an aggregate amount not to exceed $100.0 million;

(11) the repurchase, redemption or other acquisition or retirement for value of any subordinated Indebtedness pursuant to provisions in documentation governing such subordinated Indebtedness similar to those described under "—Repurchase of Notes Upon a Change of Control;" provided that, prior to such repurchase, redemption or other acquisition, the Issuer (or a third party to the extent permitted by the indenture) shall have made a Change of Control Offer with respect to the notes and shall have repurchased all notes validly tendered and not withdrawn in connection with such Change of Control Offer; and

(12) payments made to Korea National Oil Corporation or any other direct or indirect parent of the Issuer of (a) amounts relating to taxes, in an amount not to exceed the amount of taxes the Issuer and its Subsidiaries would pay on a stand-alone basis plus (b) corporate overhead expenses and customary salary, bonus and other benefits payable to officers and employees of any such direct or indirect parent company of the Issuer, to the extent such expenses, salaries, bonuses and other benefits are attributable to or reasonably allocated to the ownership or operation of the Issuer and the Restricted Subsidiaries;

provided that, in the case of clauses (9), (10) and (11) no Default or Event of Default shall have occurred and be continuing or occur as a consequence of the actions or payments set forth therein.

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Only Restricted Payment permitted pursuant to clauses (1), (5) and (9) shall be included in calculating whether the conditions of clause (3) of the first paragraph of this "—Limitation on Restricted Payments" covenant have been met with respect to any subsequent Restricted Payments.

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

Limitation on Issuances of Guarantees by Restricted Subsidiaries

The Issuer will not permit any Restricted Subsidiary (other than a Subsidiary Guarantor), directly or indirectly, to Guarantee any Indebtedness ("Guaranteed Indebtedness") of the Issuer or any other Subsidiary Guarantor, unless (a) such Restricted Subsidiary simultaneously executes and delivers a supplemental indenture to the indenture providing for a Guarantee of payment of the notes by such Restricted Subsidiary and (b) such Restricted Subsidiary waives and will not in any manner whatsoever claim or take the benefit or advantage of, any rights of reimbursement, indemnity or subrogation or any other rights against the Issuer or any other Restricted Subsidiary as a result of any payment by such Restricted Subsidiary under its Note Guarantee until the notes have been paid in full; provided that all such Restricted Subsidiaries that are not Subsidiary Guarantors shall not be required to provide Note Guarantees if the aggregate principal amount of all Indebtedness (other than the notes) of the Issuer and such Subsidiary Guarantors Guaranteed by such Restricted Subsidiaries shall not exceed $150.0 million.

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

Limitation on Transactions with Affiliates

The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, enter into, make, renew or extend any transaction (including, without limitation, the purchase, sale, lease or exchange of property or assets, or the rendering of any service) with any Affiliate of the Issuer or any Restricted Subsidiary in excess of $5.0 million in value, unless such transaction is made upon fair and reasonable terms no less favorable to the Issuer or such Restricted Subsidiary than could be obtained, at the time of such transaction or, if such transaction is pursuant to a written agreement, at the time of the execution of the agreement providing therefor, in a comparable arm's-length transaction with a Person that is not an Affiliate.

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

(1) transactions for which the Issuer or a Restricted Subsidiary delivers to the Trustee a written opinion of a nationally recognized investment banking, accounting, valuation or appraisal firm in Canada or the United States stating that the transaction is fair to the Issuer or such Restricted Subsidiary from a financial point of view;

(2) any transaction solely between the Issuer and any of its Restricted Subsidiaries or solely among Restricted Subsidiaries;

(3) the payment of reasonable and customary fees and other compensation paid to, and indemnities provided on behalf of, officers, directors, managers, employees or consultants of the Issuer, any of its direct or indirect parent companies or any Restricted Subsidiary;

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(4) any sale of Capital Stock (other than Disqualified Stock) of the Issuer;

(5) any transaction pursuant to any agreement in existence on the Closing Date, or any amendment, replacement or refinancing thereof that, taken in its entirety, is no less favorable to the Issuer and its Restricted Subsidiaries than such agreement in effect on the Closing Date;

(6) any sale of securities (other than Capital Stock but including Disqualified Stock) made on substantially the same terms as available to the public;

(7) Permitted Investments (other than pursuant to clause (1) or (7) of the definition thereof) and Restricted Payments not prohibited by the covenant described under "—Limitation on Restricted Payments;"

(8) transactions entered into in good faith with any of the Issuer's or a Restricted Subsidiary's Affiliates which provide for shared services, facilities and/or employee arrangements and which provide cost savings and/or other operational efficiencies to the Issuer and the Restricted Subsidiaries, taken as a whole;

(9) any transaction with an Affiliate in which the consideration paid by the Issuer or any Restricted Subsidiary consists only of Capital Sock (other than Disqualified Stock) of the Issuer;

(10) (a) the formation and maintenance of any consolidated group or subgroup for tax, accounting or cash pooling or management purposes in the ordinary course of business;provided that the Board of Directors of the Issuer determines in good faith that the formation and maintenance of such group or subgroup is in the best interests of the Issuer and will not materially adversely affect the Issuer's ability to perform its obligations under the indenture and (b) the entering into of any tax sharing agreement with Korea National Oil Corporation or any of its consolidated Subsidiaries; and

(11) transactions between the Issuer or any of its Restricted Subsidiaries and any Person that is an Affiliate solely because one or more of its directors is also a director of the Issuer or any direct or indirect parent of the Issuer;provided that such director abstains from voting as a director of the Issuer or such direct or indirect parent, as the case may be, on any matter involving such other Person.

Notwithstanding the foregoing, the determination set forth in the first paragraph of this "Limitation on Transactions with Affiliates" covenant, and not covered by clauses (1) through (11) of this paragraph, with respect to any transaction or series of related transactions (a) the aggregate amount of which exceeds $30.0 million in value, shall be made by an officer's certificate delivered to the Trustee; and (b) the aggregate amount of which exceeds $65.0 million in value, shall be made by a majority of the Board of Directors of the Issuer.

Limitation on Liens

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

The foregoing limitation does not apply to:

(1) Liens existing on the Closing Date (other than Liens securing Indebtedness under the Credit Agreement);

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(2) Liens granted after the Closing Date on any assets or Capital Stock of the Issuer or its Restricted Subsidiaries created in favor of the Holders;

(3) Liens securing Indebtedness which is Incurred to refinance secured Indebtedness which is permitted to be Incurred under clause (b)(4) of the covenant described under "—Limitation on Indebtedness;" provided that such Liens do not extend to or cover any property or assets of the Issuer or any Restricted Subsidiary other than the property or assets securing the Indebtedness being refinanced;

(4) Liens to secure (a) Indebtedness which is permitted to be Incurred under clause (b)(1) of the covenant described under "—Limitation on Indebtedness" or (b) any Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor;

(5) Liens (including the interest of a lessor under a Capital Lease) on property that secures Indebtedness Incurred pursuant to clause (b)(8) of the covenant described under "—Limitation on Indebtedness" for the purpose of financing all or any part of the purchase price or cost of acquisition, construction or improvement of such property; provided that (a) such Lien attaches within 12 months of the date of such purchase or the completion of acquisition, construction or improvement; (b) the principal amount of the Indebtedness secured by such Lien does not exceed 100% of such purchase price or cost; and (c) any such Lien shall not extend to or cover any property or assets other than such item of property or assets and any improvements on such item;

(6) Liens on cash set aside at the time of the Incurrence of any Indebtedness, or government securities purchased with such cash, in either case to the extent that such cash or government securities pre-fund the payment of interest on such Indebtedness and are held in a collateral or escrow account or similar arrangement to be applied for such purpose;

(7) other Liens;provided that the aggregate Indebtedness outstanding and secured under this paragraph (7) does not (calculated at the time of the giving of the Liens on the Indebtedness and not at the time of any extension, renewal or replacement thereof) exceed an amount equal to 5.0% of the Issuer's Total Assets;

(8) Liens on oil and gas inventory and other feedstocks used to produce refined products at the Refinery and Liens on oil and gas refined products produced by the Refinery and related accounts receivable, in each case to secure Indebtedness under working capital facilities of the Issuer or a Restricted Subsidiary related to financing the purchase of such oil and gas inventory; or

(9) Permitted Liens.

Limitation on Sale—Leaseback Transactions

The Issuer will not, and will not permit any Restricted Subsidiary to, enter into any Sale and Leaseback Transaction; provided that the Issuer or any Restricted Subsidiary may enter into a Sale and Leaseback Transaction if:

(1) the Issuer or such Restricted Subsidiary, as applicable, could have (a) Incurred any Indebtedness associated with such Sale and Leaseback Transaction and (b) Incurred a Lien to secure such Indebtedness pursuant to the covenant described above under "—Limitation on Liens;" and

(2) the gross cash proceeds of that Sale and Leaseback Transaction are at least equal to the fair market value of the property that is the subject of that Sale and Leaseback Transaction.

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Repurchase of Notes upon a Change of Control

Unless the Issuer has previously or concurrently mailed a redemption notice with respect to all outstanding notes, the Issuer must commence, within 30 days of the occurrence of a Change of Control, and thereafter complete an Offer to Purchase for all notes then outstanding, at a purchase price equal to 101% of their principal amount, plus accrued interest (if any) to the Payment Date and Additional Interest, if any, thereon, to the date of repurchase, subject to the rights of Holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

The Issuer will not be required to make an Offer to Purchase upon a Change of Control if a third party makes the Offer to Purchase in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to an Offer to Purchase made by the Issuer and purchases all notes validly tendered and not withdrawn under such Offer to Purchase. Notwithstanding anything to the contrary herein, an Offer to Purchase may be made in advance of a Change of Control, conditional on a Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Offer to Purchase.

The provisions under the indenture relative to the Issuer's obligation to make an Offer to Purchase upon a Change of Control Offer may be waived or modified with the written consent of the holders of a majority in principal amount of the notes.

Any credit agreements or other similar agreements to which the Issuer is or becomes a party may contain similar restrictions and provisions and may also prohibit the Issuer from purchasing any notes. In the event a Change of Control occurs at a time when the Issuer is prohibited from purchasing notes, the Issuer could seek the consent of its lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If the Issuer does not obtain such consent or repay such borrowings, the Issuer will remain prohibited from purchasing notes. In such case, the Issuer's failure to purchase tendered notes would constitute an Event of Default under the indenture which would, in turn, constitute a default under such other agreements. In addition, the exercise by the Holders of notes of their right to require the Issuer to repurchase notes upon a Change of Control could cause a default under these other agreements, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Issuer. Finally, the Issuer's ability to pay cash to the Holders of notes upon a repurchase may be limited by the Issuer's then existing financial resources. Sufficient funds may not be available when necessary to make any required repurchases.

The Change of Control purchase feature of the notes may in certain circumstances make more difficult or discourage a sale or takeover of the Issuer and, thus, the removal of incumbent management. The Change of Control purchase feature is a result of negotiations between the Initial Purchasers and the Issuer. As of the Closing Date, the Issuer has no present intention to engage in a transaction involving a Change of Control, although it is possible that the Issuer could decide to do so in the future. Subject to the limitations discussed below, the Issuer could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the indenture, but that could increase the amount of Indebtedness outstanding at such time or otherwise affect the Issuer's capital structure or credit ratings. Restrictions on the Issuer's ability to Incur additional Indebtedness are contained in the covenants described under "Certain Covenants—Limitation on Indebtedness" and "Certain Covenants—Limitation on Liens." Except for the limitations contained in such covenants, however, the indenture does not contain any covenants or provisions that may afford Holders of the notes protection in the event of a highly leveraged transaction.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, transfer, conveyance or other disposition of "all or substantially all" of the properties or assets of the Issuer and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable

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law. Accordingly, the ability of a Holder of notes to require the Issuer to repurchase such notes as a result of a sale, transfer, conveyance or other disposition of less than all of the assets of the Issuer and its Subsidiaries taken as a whole to another Person or group may be uncertain. In addition, Holders of notes may not be entitled to require the Issuer to repurchase their notes in certain circumstances involving a significant change in the composition of the Board of Directors of the Issuer, including in connection with a proxy contest, where the Issuer's Board of Directors does not endorse a dissident slate of directors but approves them as continuing directors for purposes of the indenture.

SEC Reports and Reports to Holders

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

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

(b) for the first three quarters of each year, all quarterly financial information that would be required to be contained in quarterly reports under the laws of Canada or any province thereof or provided to securityholders of a company with securities listed on the Toronto Stock Exchange, whether or not the Issuer has any of its securities so listed, in each case including a "Management's Discussion and Analysis of Financial Condition and Results of Operations;" and

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

The Issuer will comply with the periodic reporting requirements of the Exchange Act and will file the reports specified in the preceding paragraph with the SEC within the time periods specified above unless the SEC will not accept such a filing. The Issuer will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept the Issuer's filings for any reason, the Issuer will post the reports referred to in the preceding paragraph on its website within the time periods that would apply if the Issuer were required to file those reports with the SEC.

The Issuer will hold a quarterly conference call to discuss the information contained in the annual and quarterly reports required under this covenant not later than five business days from the time the Issuer files or is required to file such reports with the SEC. No fewer than three business days prior to the date of each such conference call, the Issuer will issue a press release to the appropriate wire services announcing the time, date and information to access such conference call.

In addition, the Issuer and the Subsidiary Guarantors have agreed that, for so long as any initial notes remain outstanding, they will furnish to the Holders and to prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default

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

(a) default in the payment of principal of (or premium, if any, on) any note when the same becomes due and payable at maturity, upon acceleration, redemption or otherwise;

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(b) default in the payment of interest on, or Additional Interest with respect to, any note when the same becomes due and payable, and such default continues for a period of 30 days;

(c) default in the performance or breach of the provisions of the indenture applicable to mergers, consolidations, amalgamations and transfers of all or substantially all of the assets of the Issuer or the failure by the Issuer to make or consummate an Offer to Purchase in accordance with the covenant described under "Repurchase of notes upon a Change of Control;"

(d) the Issuer or any Subsidiary Guarantor defaults in the performance of or breaches any other covenant or agreement in the indenture or under the notes (other than a default specified in clause (a), (b) or (c) above) and such default or breach continues for a period of 60 consecutive days after written notice by the Trustee or the Holders of 25% or more in aggregate outstanding principal amount of the notes;

(e) there occurs with respect to any issue or issues of Indebtedness of the Issuer, any Subsidiary Guarantor or any Significant Subsidiary having an outstanding principal amount of $65.0 million or more in the aggregate for all such issues of all such Persons, whether such Indebtedness now exists or shall hereafter be created, (1) an event of default that has caused the holders thereof to declare such Indebtedness to be due and payable prior to its Stated Maturity and such Indebtedness has not been discharged in full or such acceleration has not been rescinded or annulled within 30 days of such acceleration and/or (2) the failure to make a principal payment at the final (but not any interim) fixed maturity and such defaulted payment shall not have been made, waived or extended within 30 days of such payment default;

(f) any final judgment or order (not covered by insurance) for the payment of money in excess of $65.0 million in the aggregate for all such final judgments or orders against all such Persons (treating any deductibles, self-insurance or retention as not so covered) shall be rendered against the Issuer, any Subsidiary Guarantor or any Significant Subsidiary and shall not be paid, bonded or discharged, and there shall be any period of 60 consecutive days following entry of the final judgment or order that causes the aggregate amount for all such final judgments or orders outstanding and not paid, bonded or discharged against all such Persons to exceed $65.0 million during which a stay of enforcement of such final judgment or order, by reason of a pending appeal or otherwise, shall not be in effect;

(g) a court having jurisdiction in the premises enters a decree or order for (1) relief in respect of the Issuer, any Subsidiary Guarantor or any Significant Subsidiary in an involuntary case under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect, (2) appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official of the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or for all or substantially all of the property and assets of the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or (3) the winding up or liquidation of the affairs of the Issuer, any Subsidiary Guarantor or any Significant Subsidiary and, in each case, such decree or order shall remain unstayed and in effect for a period of 30 consecutive days;

(h) the Issuer, any Subsidiary Guarantor or any Significant Subsidiary (1) commences a voluntary case under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect, or consents to the entry of an order for relief in an involuntary case under any such law, (2) consents to the appointment of or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official of the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or for all or substantially all of the property and assets of the Issuer, any Subsidiary Guarantor or any Significant Subsidiary or (3) effects any general assignment for the benefit of creditors; or

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(i) any Subsidiary Guarantor repudiates its obligations under its Note Guarantee or, except as permitted by the indenture, any Note Guarantee is determined to be unenforceable or invalid or shall for any reason cease to be in full force and effect and, with respect to a Subsidiary Guarantor that is not, or a group of Restricted Subsidiaries that are not Subsidiary Guarantors that together would constitute, a Significant Subsidiary, such default continues for a period of 60 days.

If an Event of Default (other than an Event of Default specified in clause (g) or (h) above that occurs with respect to the Issuer) occurs and is continuing under the indenture, the Trustee or the Holders of at least 25% in aggregate principal amount of the notes, then outstanding, by written notice to the Issuer (and to the Trustee if such notice is given by the Holders), may, and the Trustee at the request of such Holders shall, declare the principal of, premium, if any, and accrued interest on the notes to be immediately due and payable. Upon a declaration of acceleration, such principal of, premium, if any, and accrued interest shall be immediately due and payable. In the event of a declaration of acceleration because an Event of Default set forth in clause (e) or (f) above has occurred and is continuing, such declaration of acceleration shall be automatically rescinded and annulled if the event of default triggering such Event of Default pursuant to clause (e) or (f) shall be remedied or cured by the Issuer, the relevant Subsidiary Guarantor or the relevant Significant Subsidiary or waived by the applicable holders of the relevant Indebtedness within 60 days after the declaration of acceleration with respect thereto. If an Event of Default specified in clause (g) or (h) above occurs with respect to the Issuer, the principal of, premium, if any, and accrued interest on the notes then outstanding shall automatically become and be immediately due and payable without any declaration or other act on the part of the Trustee or any Holder. The Holders of at least a majority in principal amount of the outstanding notes by written notice to the Issuer and to the Trustee, may waive all past Defaults and rescind and annul a declaration of acceleration and its consequences if (x) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the notes that have become due solely by such declaration of acceleration, have been cured or waived and (y) the rescission would not conflict with any judgment or decree of a court of competent jurisdiction. For information as to the waiver of defaults, see "—Modification and Waiver."

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

(1) the Holder gives the Trustee written notice of a continuing Event of Default;

(2) the Holders of at least 25% in aggregate principal amount of outstanding notes make a written request to the Trustee to pursue the remedy;

(3) such Holder or Holders offer the Trustee indemnity satisfactory to the Trustee against any costs, liability or expense;

(4) the Trustee does not comply with the request within 60 days after receipt of the request and the offer of indemnity; and

(5) during such 60-day period, the Holders of a majority in aggregate principal amount of the outstanding notes do not give the Trustee a direction that is inconsistent with the request.

However, such limitations do not apply to the right of any Holder of a note to receive payment of the principal of, premium, if any, or interest on, such note or to bring suit for the enforcement of any

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such payment, on or after the due date expressed in the notes, which right shall not be impaired or affected without the consent of the Holder.

Officers of the Issuer must certify, on or before a date not more than 120 days after the end of each fiscal year, that a review has been conducted of the activities of the Issuer and its Restricted Subsidiaries and the Issue's and its Restricted Subsidiaries' performance under the indenture and that the Issuer has fulfilled all obligations thereunder, or, if there has been a default in the fulfillment of any such obligation, specifying each such default and the nature and status thereof. Within five business days of becoming aware of any Default or Event of Default, the Issuer will be obligated to notify the Trustee.

Consolidation, Amalgamation, Merger and Sale of Assets

The Issuer will not, directly or indirectly, consolidate with, amalgamate with, merge with or into, or sell, convey, assign, transfer, lease or otherwise dispose of all or substantially all of its property and assets (as an entirety or substantially an entirety in one transaction or a series of related transactions) to, any Person or permit any Person to merge with or into it unless:

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

(2) immediately after giving effect to such transaction, no Default or Event of Default shall have occurred and be continuing;

(3) immediately after giving effect to such transaction on apro forma basis the Issuer, or the Surviving Person, as the case may be, could (a) Incur at least $1.00 of Indebtedness under clause (a) of the covenant described under "Certain Covenants—Limitation on Indebtedness" or (b) the Interest Coverage Ratio of the Issuer or the Surviving Entity is equal to or greater than the Issuer's Interest Coverage Ratio immediately prior to such transaction;provided that this clause (3) shall not apply to a consolidation, amalgamation, merger or sale of all (but not less than all) of the assets of the Issuer if all Liens and Indebtedness of the Issuer or the Surviving Person, as the case may be, and its Restricted Subsidiaries outstanding immediately after such transaction would have been permitted (and all such Liens and Indebtedness, other than Liens and Indebtedness of the Issuer and its Restricted Subsidiaries outstanding immediately prior to the transaction, shall be deemed to have been Incurred) for all purposes of the indenture;

(4) it delivers to the Trustee an officers' certificate and opinion of counsel, in each case stating that such consolidation, amalgamation, merger or transfer and such supplemental indenture complies with this provision and that all conditions precedent provided for herein relating to such transaction have been complied with; and

(5) each Subsidiary Guarantor, unless such Subsidiary Guarantor is the Person with which the Issuer has entered into a transaction under this "Consolidation, Amalgamation, Merger and Sale of Assets" covenant, shall have by amendment to its Note Guarantee confirmed that its Guarantee shall apply to the obligations of the Issuer or the Surviving Person in accordance with the notes and the indenture;

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

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

Defeasance

Legal Defeasance. The indenture provides that the Issuer will be deemed to have paid and will be discharged from any and all obligations in respect of the notes, and the provisions of the indenture will no longer be in effect with respect to the notes (except for, among other matters, certain obligations to register the transfer or exchange of the notes, to replace stolen, lost or mutilated notes, to maintain paying agencies and to hold monies for payment in trust) if, among other things:

(A) the Issuer has irrevocably deposited with the Trustee, in trust, for the benefit of the Holders of notes, cash and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide an amount sufficient to pay the principal of, premium, if any, and accrued interest on the notes on the Stated Maturity of such payments in accordance with the terms of the indenture and the notes;

(B) the Issuer has delivered to the Trustee either (x) an opinion of counsel to the effect that Holders will not recognize income, gain or loss for U.S. federal income tax purposes as a result of the Issuer's exercise of its option under this "Defeasance" provision and will be subject to U.S. federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred, which opinion of counsel must be based upon (and accompanied by a copy of) a ruling of the Internal Revenue Service to the same effect unless there has been a change in applicable federal income tax law after the Closing Date such that a ruling is no longer required or (y) a ruling directed to the Trustee received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel;

(C) the Issuer has delivered to the Trustee an opinion of counsel in Canada to the effect that Holders will not recognize income, gain or loss for Canadian federal or provincial income tax or other tax purposes as a result of such deposit, defeasance and discharge, and will be subject to Canadian federal or provincial income tax and other tax on the same amounts, in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred (which condition may not be waived by any Holder or the Trustee); and

(D) immediately after giving effect to such deposit on apro forma basis, no Default or Event of Default (other than a Default or Event of Default resulting from the borrowing of funds to be applied to the trust in accordance with clause (A) above), shall have occurred and be continuing on the date of such deposit, and such deposit shall not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which the Issuer or any of its Subsidiaries is a party or by which the Issuer or any of its Subsidiaries is bound.

Defeasance of Certain Covenants and Certain Events of Default. The indenture further provides that the provisions of the indenture will no longer be in effect with respect to the covenant described

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under "Repurchase of Notes upon a Change of Control," clause (3) under the first paragraph of the covenant described under "Consolidation, Amalgamation, Merger and Sale of Assets" and all the covenants described herein under "Certain Covenants," clause (c) under "Events of Default" with respect to such clause (3) under the first paragraph of "Consolidation, Amalgamation, Merger and Sale of Assets," clause (d) under "Events of Default" with respect to such other covenants and clauses (e) and (f) under "Events of Default" shall be deemed not to be Events of Default upon, among other things, the deposit with the Trustee, in trust, of cash and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide an amount sufficient to pay the principal of, premium, if any, and accrued interest on the notes on the Stated Maturity of such payments in accordance with the terms of the indenture and the notes, the satisfaction of the provisions described in clauses (C) and (D) of the preceding paragraph and the delivery by the Issuer to the Trustee of an opinion of counsel reasonably acceptable to the Trustee to the effect that, among other things, the Holders will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance of certain covenants and Events of Default and will be subject to U.S. federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred.

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

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when:

(1) either:

(a) all notes that have been authenticated (except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has theretofore been deposited in trust and thereafter repaid to the Issuer) have been delivered to the Trustee for cancellation; or

(b) all notes that have not been delivered to the Trustee for cancellation (x) have become due and payable (by reason of the mailing of a notice of redemption or otherwise), (y) will become due and payable at Stated Maturity within one year, or (z) are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the Issuer's name and at the Issuer's expense, and in each such case the Issuer has irrevocably deposited or caused to be deposited with the Trustee as trust funds in trust solely for the benefit of the Holders, cash in U.S. dollars, U.S. Government Obligations, or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the notes not delivered to the Trustee for cancellation for principal, premium and Additional Interest, if any, and accrued interest to the Stated Maturity or redemption date, as the case may be;

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(2) no Default or Event of Default (other than a Default or Event of Default that results from the borrowing of funds to be applied to the deposit in accordance with clause (1)(b) above) will have occurred and be continuing on the date of such deposit or will occur as a result of such deposit and such deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which the Issuer or any Subsidiary Guarantor is a party or by which the Issuer or any Subsidiary Guarantor is bound;

(3) the Issuer or any Subsidiary Guarantor has paid or caused to be paid all sums payable by it under the indenture; and

(4) the Issuer has delivered irrevocable instructions to the Trustee under the indenture to apply the deposited money toward the payment of the notes at Stated Maturity or the redemption date, as the case may be.

In addition, the Issuer must deliver an officers' certificate and an opinion of counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Modification and Waiver

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

(1) cure any ambiguity, defect or inconsistency in the indenture;

(2) comply with the provisions described under "Consolidation, Amalgamation, Merger and Sale of Assets" or "Limitation on Issuances of Guarantees by Restricted Subsidiaries" or to release a Subsidiary Guarantor from its Note Guarantee in accordance with the terms of the indenture;

(3) comply with any requirements of the SEC in connection with the qualification of the indenture under the Trust Indenture Act;

(4) evidence and provide for the acceptance of appointment by a successor Trustee;

(5) to provide for the issuance of exchange notes and Additional Notes in accordance with the indenture;

(6) make any change that, in the good faith opinion of the Board of Directors of the Issuer, does not materially and adversely affect the rights of any Holder;

(7) to conform the indenture or the notes to any provision of this "Description of Notes;"

(8) to comply with the rules of any applicable securities depositary; or

(9) to provide security to the Holders with respect to the notes.

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

(1) change the Stated Maturity of the principal of, or any installment of interest on, any note;

(2) reduce the principal amount of, or premium, if any, or interest on, any note;

(3) change the optional redemption dates or optional redemption prices of the notes from that stated under the caption "Optional Redemption;"

(4) change the place or currency of payment of principal of, or premium, if any, or interest on, any note;

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(5) impair the right to institute suit for the enforcement of any payment on or after the Stated Maturity (or, in the case of a redemption, on or after the redemption date) of any note;

(6) waive a default in the payment of principal of, premium, if any, or interest on the notes;

(7) release any Subsidiary Guarantor from its Note Guarantee, except as provided in the indenture;

(8) reduce the percentage or aggregate principal amount of outstanding notes the consent of whose Holders is necessary for waiver of compliance with certain provisions of the indenture or for waiver of certain defaults; or

(9) make any change in the modification and waiver provisions of the indenture.

No Personal Liability of Directors, Officers, Employees and Stockholders

No recourse for the payment of the principal of, premium, if any, or interest on any of the notes or for any claim based thereon or otherwise in respect thereof; and no recourse under or upon any obligation, covenant or agreement of the Issuer or any Subsidiary Guarantor in the indenture, or in any of the notes or the Note Guarantees or because of the creation of any Indebtedness represented thereby, shall be had against any incorporator, officer, director, employee or controlling person of the Issuer, any Subsidiary Guarantor or of any successor Person thereof. Each Holder, by accepting the notes, waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the notes. Such waiver may not be effective to waive liabilities under the federal securities laws.

Concerning the Trustee

Except during the continuance of a Default, the Trustee will not be liable, except for the performance of such duties as are specifically set forth in the indenture. If an Event of Default has occurred and is continuing, the Trustee will use the same degree of care and skill in its exercise of the rights and powers vested in it under the indenture as a prudent person would exercise under the circumstances in the conduct of such person's own affairs.

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

Governing Law

The indenture and the notes will be governed by and construed in accordance with the laws of the State of New York.

Enforceability of Judgments

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

The Issuer has been informed by its Alberta counsel, Bennett Jones LLP, that the laws of the Province of Alberta and the federal laws of Canada applicable therein permit an action to be brought against the Issuer or a Subsidiary Guarantors in a court of competent jurisdiction in such Province on

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

Consent to Jurisdictions and Service

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

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BOOK-ENTRY, DELIVERY AND FORM

Except as described below, we will initially issue the exchange notes in the form of one or more registered exchange notes in global form without coupons. We will deposit each global note on the date of the closing of this exchange offer with, or on behalf of, The Depository Trust Company ("DTC") in New York, New York, and register the exchange notes in the name of DTC or its nominee, or will leave these notes in the custody of the trustee.

DTC Procedures

The following description of the operations and procedures of DTC, the Euroclear System ("Euroclear") and Clearstream Banking, S.A. ("Clearstream") is provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them from time to time. The Issuer takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that, in accordance with its procedures, upon deposit of the global notes, it will credit the accounts of the direct participants with an interest in the global notes, and it will maintain records of the ownership interests of these direct participants in the global notes and the transfer of ownership interests by and between direct participants.

As long as DTC, or its nominee, is the registered Holder of a global note, DTC or such nominee, as the case may be, will be considered the sole owner and Holder of the notes represented by such global note for all purposes under the indenture and the notes. Except in the limited circumstances described below owners of beneficial interests in a global note will not be entitled to have portions of such Global Note registered in their names, will not receive or be entitled to receive physical delivery of notes in definitive form and will not be considered the owners or Holders of the global note (or any notes represented thereby) under the indenture or the notes. In addition, no beneficial owner of an interest in a global note will be able to transfer that interest except in accordance with DTC's applicable procedures (in addition to those under the indenture and, if applicable, those of Euroclear and Clearstream). In the event that owners of beneficial interests in a global note become entitled to receive notes in definitive form, such notes will be issued only in registered form in denominations of US$2,000 and integral multiples of US$1,000 in excess thereof.

Investors in the global notes may hold their interests in the notes directly through DTC if they are direct participants in DTC or indirectly through organizations that are direct participants in DTC. Investors in the global notes may also hold their interests in the notes through Euroclear and Clearstream if they are direct participants in those systems or indirectly through organizations that are participants in those systems. Euroclear and Clearstream will hold omnibus positions in the global notes on behalf of the Euroclear participants and the Clearstream participants, respectively, through customers' securities accounts in Euroclear's and Clearstream's names on the books of their respective depositories. These depositories, in turn, will hold these positions in their names on the books of DTC. All interests in a global note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of those systems.

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

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

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

Cross-market transfers between DTC participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected by DTC in accordance with DTC rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant global note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a global note from a DTC participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the DTC settlement date. Cash received on Euroclear or Clearstream as a result of sales of interests in a global note by or through a Euroclear or Clearstream participants to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following the DTC settlement date. DTC has advised the Issuer that it will take any action permitted to be taken by a Holder of notes (including the presentation of notes for exchange as described below) only at the direction of one or more participants to whose account with DTC interests in the global notes are credited and only in respect of such portion of the aggregate principal amount of the notes as to which such participant or participants has or have given such direction. However, if there is an event of default with respect to the notes, DTC reserves the right to exchange the global notes for legended notes in certificated form, and to distribute such notes to its participants.

DTC has advised the issuer as follows: DTC is

•: a limited purpose trust company organized under the laws of the State of New York,
•: a "banking organization" within the meaning of New York Banking law,
•: a member of the Federal Reserve System,
•: a "clearing corporation" within the meaning of the Uniform Commercial Code, as amended, and
•: a "Clearing Agency" registered pursuant to the provisions of Section 17A of the Exchange Act.

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DTC was created to hold securities for its participants and facilitate the clearance and settlement of securities transactions between participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical transfer and delivery of certificates. Participants include securities brokers and dealers, banks, trust companies and clearing corporations and may include certain other organizations. Indirect access to the DTC system is available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly ("indirect participants").

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

Exchanges of Book Entry Notes for Certificated Notes

A beneficial interest in a global note may not be exchanged for a note in certificated form unless (i) DTC (x) notifies the Issuer that it is unwilling or unable to continue as depository for such global note or (y) has ceased to be a clearing agency registered under the Exchange Act, and in each case, the Issuer fail to appoint a successor depository, (ii) in the case of a global note held for an account of Euroclear or Clearstream, Euroclear or Clearstream, as the case may be, (x) is closed for business for a continuous period of 14 days (other than by reason of statutory or other holidays) or (y) announces an intention permanently to cease business or does in fact do so, and in each case, the Issuer fail to appoint a successor depository, (iii) there shall have occurred and be continuing and Event of Default with respect to the notes or (iv) a request for certificates has been made upon 60 days' prior written notice given to the Trustee in accordance with DTC's customary procedures and a copy of such notice has been received by the Issuer from the Trustee. In all cases, certificated notes delivered in exchange for any global note or beneficial interests therein will be registered in the names, and issued in approved denominations, requested by or on behalf of DTC (in accordance with its customary procedures).

Definitions

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

"Acquired Debt" means, with respect to any specified Person, (1) Indebtedness of any other Person existing at the time such Person is merged with or into or became a Subsidiary of such specified Person and (2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person, in each case provided that such Indebtedness is not incurred in contemplation of, or in connection with, such other Person merging with or into, or becoming a Subsidiary of, such specified Person.

"Additional Interest" means all additional interest owing on the notes pursuant to the Registration Rights Agreement.

"Adjusted Consolidated Net Income" means, for any period, the aggregate net income (or loss) of the Issuer and its Restricted Subsidiaries for such period determined on a consolidated basis in

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conformity with GAAP;provided that the following items shall be excluded in computing Adjusted Consolidated Net Income (without duplication):

(1) the net income (or loss) of any Person that is not a Restricted Subsidiary except to the extent of the dividends or other distributions actually paid in cash (or to the extent converted into cash) to the Issuer or any of its Restricted Subsidiaries (subject to clause (3) below) by such Person during such period;

(2) the net income (or loss) of any Person accrued prior to the date it becomes a Restricted Subsidiary or is merged into or consolidated with the Issuer or any of its Restricted Subsidiaries or all or substantially all of the property and assets of such Person are acquired by the Issuer or any of its Restricted Subsidiaries;

(3) for purposes of "—Limitation on Restricted Payments," the net income of any Restricted Subsidiary to the extent that the declaration or payment of dividends or similar distributions by such Restricted Subsidiary of such net income is not at the time permitted by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to such Restricted Subsidiary;

(4) any gains or losses (on an after-tax basis) attributable to sales of assets outside the ordinary course of business or the extinguishment of Indebtedness of the Issuer and its Restricted Subsidiaries, including all fees and expenses related to such sales;

(5) all extraordinary gains and extraordinary losses;

(6) any currency translation gains and losses related to currency remeasurements of Indebtedness, and any net loss or gain resulting from Currency Agreements hedging currency exchange risk, until such gains or losses are actually realized (at which time they should be included); and

(7) to the extent covered by insurance and actually reimbursed, or, so long as a determination has been made that there exists reasonable evidence that such amount will in fact be reimbursed by the insurer and only to the extent that such amount is (a) not denied by the applicable carrier in writing within 180 days and (b) in fact reimbursed within 365 days of the date of such evidence (with a deduction for any amount so added back to the extent not so reimbursed within 365 days), expenses with respect to liability or casualty events or business interruption;provided that (x) if net income is increased as a result of any amounts received from an insurer in respect of such a liability, casualty event or business interruption and the right to be so reimbursed was used in a prior period to increase Adjusted Consolidated Net Income pursuant to this clause (7), such amounts received shall be excluded from Adjusted Consolidated Net Income and (y) to the extent the actual reimbursement received is less than the expected reimbursement amount excluded in a prior period pursuant to this clause (7), Adjusted Consolidated Net Income shall be reduced by the difference in the period in which such lower actual reimbursement amounts are received or in which a final judgment of a court of competent jurisdiction is made that the Corporation is entitled to no reimbursement.

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

"Asset Acquisition" means (1) an investment by the Issuer or any of its Restricted Subsidiaries in any other Person pursuant to which such Person shall become a Restricted Subsidiary or shall be

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merged into or consolidated with the Issuer or any of its Restricted Subsidiaries;provided that such Person's primary business is the Oil and Gas Business or (2) an acquisition by the Issuer or any of its Restricted Subsidiaries of the property and assets of any Person other than the Issuer or any of its Restricted Subsidiaries;provided that the property and assets acquired are in the Oil and Gas Business.

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

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

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

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

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

"Capitalized Lease Obligations" means the amount of the liability in respect of a Capital Lease that would at the time of determination be required to be reflected as a liability on the balance sheet in accordance with GAAP.

"Change of Control" means such time as:

(1) a "person" or "group" (within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act), other than Korea National Oil Corporation or a Subsidiary of Korea National Oil Corporation, becomes the ultimate "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act) of more than 50% of the total voting power of the Voting Stock of the Issuer on a fully diluted basis;

(2) individuals who on the Closing Date constitute the Board of Directors (together with any new directors whose election by the Board of Directors or whose nomination by the Board of Directors for election by the Issuer's stockholders was approved by a vote of more than 50% of the members of the Board of Directors then in office who either were members of the Board of Directors on the Closing Date or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the members of the Board of Directors then in office;

(3) the Issuer ceases to be a Subsidiary of Korea National Oil Corporation; or

(4) the adoption of a plan relating to the liquidation or dissolution of the Issuer.

"Closing Date" means the date on which the Notes are originally issued under the indenture.

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

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

"Comparable Treasury Issue" means U.S. Treasury security or securities selected by the Independent Investment Banker as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of those notes.

"Comparable Treasury Price" means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for that redemption date after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (2) if the Trustee obtains fewer than four such Reference Treasury Dealer Quotations, then the average of the available Reference Treasury Dealer Quotations for the redemption date, or (3) if only one is available on that date, then that Reference Treasury Dealer Quotation.

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

(1) Consolidated Interest Expense;

(2) income taxes and, to the extent such payments reduce Adjusted Consolidated Net Income, any payments to Korea National Oil Corporation pursuant to clause (12)(a) of the covenant described under "—Limitation on Restricted Payments;"

(3) depletion, depreciation, accretion and amortization expense; and

(4) all other non-cash items reducing Adjusted Consolidated Net Income (other than items that will require cash payments and for which an accrual or reserve is, or is required by GAAP to be, made), less all non-cash items increasing Adjusted Consolidated Net Income (other than items that will result in cash payments in a future period), all as determined on a consolidated basis for the Issuer and its Restricted Subsidiaries in conformity with GAAP;

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

"Consolidated Interest Expense" means, for any period, the aggregate amount of interest in respect of Indebtedness (including, without limitation, amortization of original issue discount on any Indebtedness and the interest portion of any deferred payment obligation, calculated in accordance with the effective interest method of accounting; all commissions, discounts and other fees and charges owed with respect to letters of credit and bankers' acceptance financing; the net costs associated with Interest Rate Agreements (excluding non-cash interest expense attributable to the movement in the mark-to-market valuation of Interest Rate Agreements); and Indebtedness that is Guaranteed or secured by the Issuer or any of its Restricted Subsidiaries, net of amortization of bond premium) and the interest component of Capitalized Lease Obligations and the amount charged to shareholders'

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(or unitholders') equity in respect of interest on Indebtedness, in each case paid, accrued or scheduled to be paid or to be accrued by the Issuer and its Restricted Subsidiaries during such period and the product of dividend payments of the Issuer with respect to Disqualified Stock and of any Restricted Subsidiary with respect to Preferred Stock (except in either case dividends paid solely in shares of Capital Stock, other than Disqualified Stock, of the Issuer) times a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, provincial, state and local tax rate of such Person, expressed as a decimal;excluding, however,(1) any amount of such interest of any Restricted Subsidiary if the net income of such Restricted Subsidiary is excluded in the calculation of Adjusted Consolidated Net Income pursuant to clause (3) of the definition thereof (but only in the same proportion as the net income of such Restricted Subsidiary is excluded from the calculation of Adjusted Consolidated Net Income pursuant to clause (3) of the definition thereof) and (2) any premiums, fees and expenses (and any amortization thereof) payable in connection with the offering of the notes, all as determined on a consolidated basis (without taking into account Unrestricted Subsidiaries) in conformity with GAAP.

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

"Convertible Debentures" means the convertible debentures issued and outstanding as at the date hereof pursuant to the Debenture Trust Indenture dated January 29, 2004 with Valiant Trust Company and the Issuer, as supplemented, being the Series 3 6,50% convertible extendible unsecured subordinated debentures due December 31, 2010 issued pursuant to the Second Supplemental Indenture dated August 2, 2005, the Series 4 7.25% convertible unsecured subordinated debentures due September 30, 2013 issued pursuant to the Third Supplemental Indenture dated November 22, 2006, the Series 5 7.25% convertible unsecured subordinated debentures due February 28, 2014 issued pursuant to the Fourth Supplemental Indenture dated February 1, 2007, and the Series 6 7.50% convertible unsecured subordinated debentures due May 31, 2015 issued pursuant to the Fifth Supplemental Indenture dated April 25, 2008.

"Credit Agreement" means the credit agreement in effect on the Closing Date among the Issuer, as borrower, the Subsidiaries of the Issuer named therein, the lenders named therein, Canadian Imperial Bank of Commerce, as administrative agent, and the other agents named therein including any related notes, debentures, pledges, Guarantees, security documents, instruments and agreements executed from time to time in connection therewith, and in each case as amended, restated, renewed, replaced, refinanced, extended, substituted, assigned by the agent or any lender, restructured, supplemented or otherwise modified from time to time, including, without limitation, any successive amendments, renewals, extensions, substitutions, assignments, restatements, refinancings, restructuring, supplements or other modifications of the foregoing (including increasing the amount of available borrowings thereunder, provided that such increase in borrowings is permitted by the covenant described under "Certain Covenants—Limitation on Indebtedness," or adding Subsidiaries as additional borrowers or guarantors thereunder) of all or any portion of the Indebtedness under such agreement or agreements or any successor or replacement agreement or any agreements, and whether by the same or any other agent, lender or group of lenders, including into one or more debt facilities, commercial paper facilities or other debt instruments, indentures or agreements (including by means of sales of debt securities (including Additional Notes) to institutional investors), providing for revolving credit loans, term loans, letters of credit or other debt obligations, whether any such extension, replacement or refinancing (1) occurs simultaneously or not with the termination or repayment of a prior Credit Agreement or (2) occurs on one or more separate occasions.

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"Credit Facilities" means, one or more credit or debt facilities (including the Credit Agreement) or commercial paper facilities, in each case, with banks or other institutional or other lenders providing for, among other things, revolving credit loans, term loans, debt securities, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as such Credit Facility, in whole or in part, in one or more instances, may be amended, renewed, extended, substituted, refinanced, restructured, replaced, supplemented or otherwise modified from time to time (including any successive renewals, extensions, substitutions, refinancings, restructurings, replacements, supplementations or other modifications of the foregoing and including any amendment increasing the amount of Indebtedness incurred or available to be borrowed thereunder, extending the maturity of any Indebtedness incurred thereunder or contemplated thereby or deleting, adding or substituting one or more parties thereto (whether or not such added or substituted parties are banks or other institutional lenders)), including into one or more debt facilities, commercial paper facilities or other debt instruments, indentures or agreements (including by means of sales of debt securities (including Additional Notes) to institutional investors), providing for revolving credit loans, term loans, letters of credit or other debt obligations, whether any such extension, replacement or refinancing (1) occurs simultaneously or not with the termination or repayment of a prior Credit Facility or (2) occurs on one or more separate occasions.

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

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

"Disqualified Stock" means any class or series of Capital Stock of any Person that by its terms or otherwise is (1) required to be redeemed prior to the Stated Maturity of the notes, (2) redeemable at the option of the holder of such class or series of Capital Stock at any time prior to the Stated Maturity of the notes or (3) convertible into or exchangeable for Capital Stock referred to in clause (1) or (2) above or Indebtedness having a scheduled maturity prior to the Stated Maturity of the notes;provided that (i) any Capital Stock that would not constitute Disqualified Stock but for provisions thereof giving holders thereof the right to require such Person to repurchase or redeem such Capital Stock upon the occurrence of a "change of control" occurring prior to the Stated Maturity of the notes shall not constitute Disqualified Stock if the "change of control" provision applicable to such Capital Stock is no more favorable to the holders of such Capital Stock than the provisions contained in the covenant described under "Repurchase of Notes upon a Change of Control" and such Capital Stock specifically provides that such Person will not repurchase or redeem any such stock pursuant to such provision prior to the Issuer's repurchase of such notes as are required to be repurchased pursuant to the covenant described under "Repurchase of Notes upon a Change of Control," (ii) only the portion of the Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to the Stated Maturity of the notes shall be deemed to be Disqualified Stock, and (iii) any class of Capital Stock of such Person that by its terms authorizes such Person to satisfy its obligations thereunder by delivery of Capital Stock that is not Disqualified Stock shall not be deemed to be Disqualified Stock.

"Exchange Act" means the Securities Exchange Act of 1934 and any statute successor thereto, in each case as amended from time to time.

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

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"GAAP" mean (1) generally accepted accounting principles which are in effect on the Closing Date in Canada or (2) beginning January 1, 2011, International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS"), as in effect on such date, unless the Person's most recent audited or quarterly financial statements are not prepared in accordance with generally accepted accounting principles in Canada or IFRS, as applicable, in which case GAAP shall mean generally accepted accounting principles in effect in the United States at the time of preparation of such financial statements. All ratios and computations contained or required to in the indenture shall be computed in conformity with GAAP applied on a consistent basis, except that calculations made for purposes of determining compliance with the terms of the covenants and with other provisions of the indenture shall be made without giving effect to the amortization of any expenses incurred in connection with the offering of the notes.

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

"Holder" means a Person in whose name a Note is registered.

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

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

(1) all indebtedness of such Person for borrowed money;

(2) all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) all obligations of such Person in respect of letters of credit or other similar instruments (including reimbursement obligations with respect thereto, but excluding obligations with respect to letters of credit (including trade letters of credit) securing obligations (other than obligations described in (1) or (2) above or (5), (6) or (7) below) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if drawn upon, to the extent such drawing is reimbursed no later than the tenth business day following receipt by such Person of a demand for reimbursement);

(4) all obligations of such Person to pay the deferred and unpaid purchase price of property or services which are recorded on the Person's balance sheet as liabilities in accordance with

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GAAP, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto or the completion of such services, except Trade Payables;

(5) all Capitalized Lease Obligations;

(6) all Disqualified Stock issued by such Person or its Restricted Subsidiaries or Preferred Stock of a Restricted Subsidiary of such Person valued at the greater of its voluntary or involuntary maximum fixed repurchase price plus accrued and unpaid dividends;

(7) all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person;provided that the amount of such Indebtedness shall be the lesser of (A) the fair market value of such asset at such date of determination and (B) the amount of such Indebtedness:

(8) all indebtedness of other Persons to the extent such Indebtedness is Guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, obligations under Commodity Agreements, Currency Agreements and Interest Rate Agreements (other than Commodity Agreements, Currency Agreements and Interest Rate Agreements designed solely to manage fluctuations in commodity prices (including electricity prices), foreign currency exchange rates or interest rates and that do not increase the Indebtedness of the obligor outstanding at any time other than as a result of fluctuations in commodity prices, foreign currency exchange rates or interest rates or by reason of fees, indemnities and compensation payable thereunder).

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

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

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

(x) any liability for federal, state, local or other taxes;

(y) performance, bid, surety or appeal bonds and completion guarantees and other similar arrangements provided in the ordinary course of business; or

(z) agreements providing for indemnification, adjustment of purchase price, earn-out or similar obligations, or Guarantees or letters of credit, surety bonds or performance bonds securing any obligations of the Issuer or any of its Restricted Subsidiaries pursuant to such agreements, in any case Incurred in connection with the disposition of any business, assets or Restricted Subsidiary (other than Guarantees of Indebtedness Incurred by any Person acquiring all or any portion of such business, assets or Restricted Subsidiary for the purpose of financing such acquisition), so long as the principal amount does not to exceed the gross proceeds actually received by the Issuer or any Restricted Subsidiary in connection with such disposition.

For purposes hereof, the "maximum fixed repurchase price" of any Disqualified Stock which does not have a fixed repurchase price shall be calculated in accordance with the terms of the Disqualified

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Stock as if such Disqualified Stock were purchased on any date which Indebtedness shall be required to be determined pursuant to the indenture, and if such price is based upon, or measured by, the fair market value of such Disqualified Stock, such fair market value shall be determined in good faith by the Board of Directors of the Issuer.

"Independent Investment Banker" means one of the Reference Treasury Dealers appointed by the Issuer.

"Initial Subsidiary Guarantors" means each Restricted Subsidiary of the Issuer that Guarantees the Credit Agreement on the Closing Date.

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

(A) pro forma effect shall be given to any Indebtedness Incurred or repaid during the period (the "Reference Period") commencing on the first day of the Four Quarter Period and ending on the Transaction Date (other than Indebtedness Incurred or repaid under a revolving credit or similar arrangement to the extent of the commitment thereunder (or under any predecessor revolving credit or similar arrangement) in effect on the last day of such Four Quarter Period unless any portion of such Indebtedness is projected, in the reasonable judgment of the senior management of the Issuer, to remain outstanding for a period in excess of 12 months from the date of the Incurrence thereof), in each case as if such Indebtedness had been Incurred or repaid on the first day of such Reference Period

(B) Consolidated Interest Expense attributable to interest on any Indebtedness (whether existing or being Incurred) computed ona pro forma basis and bearing a floating interest rate shall be computed as if the rate in effect on the Transaction Date (taking into account any Interest Rate Agreement applicable to such Indebtedness if such Interest Rate Agreement has a remaining term in excess of 12 months or, if shorter, at least equal to the remaining term of such Indebtedness) had been the applicable rate for the entire period;

(C) pro forma effect shall be given to Asset Dispositions and Asset Acquisitions (including givingpro forma effect to the application of proceeds of any Asset Disposition) that occur during such Reference Period as if they had occurred and such proceeds had been applied on the first day of such Reference Period; and

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

In addition, for purposes of calculating the Interest Coverage Ratio: (1) acquisitions that have been made by the Issuer or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related financing transactions, during the Reference Period or

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subsequent to such Reference Period and on or prior to the calculation date will be givenpro forma effect as if they had occurred on the first day of the Four Quarter Period; and (2) wheneverpro forma effect is to be given to a transaction, the calculations shall be based on the reasonable good faith judgment of a responsible financial or accounting officer of the Issuer and may include, for the avoidance of doubt, cost savings and operating expense reductions resulting from such transaction (which are being givenpro forma effect) that have been realized or are reasonably expected to be realized in the 12 month period immediately subsequent to such transaction.

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

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

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

"Lien" means any mortgage, pledge, security interest, encumbrance, lien or charge of any kind (including, without limitation, any conditional sale or other title retention agreement or lease in the nature thereof or any agreement to give any security interest);provided that in no event shall an operating lease be deemed a Lien.

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

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

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

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"Oil and Gas Business" means:

(1) the acquisition, exploration, development, operation and disposition of interests in oil, gas and other hydrocarbon properties;

(2) the gathering, marketing, treating, refining, processing, storage, selling and transporting of oil, gas and other minerals and products;

(3) the exploration for or development, production, treatment, refinery processing, storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith;

(4) evaluating, participating in or pursuing any other activity or opportunity that is primarily related to clauses (1) through (3) above; and

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

"Oil and Gas Investments" means any Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, refining, marketing or transporting oil and gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including, without limitation:

(1) ownership interests in oil and gas properties, processing facilities or gathering systems or ancillary real property interests; and

(2) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements with third parties.

"Offer to Purchase" means an offer to purchase notes by the Issuer from the Holders commenced by mailing a notice to the Trustee and each Holder stating:

(1) the covenant pursuant to which the offer is being made and that all notes validly tendered will be accepted for payment on a pro rata basis;

(2) the purchase price and the date of purchase (which shall be a business day no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the "Payment Date");

(3) that any Note not tendered will continue to accrue interest pursuant to its terms;

(4) that, unless the Issuer defaults in the payment of the purchase price, any Note accepted for payment pursuant to the Offer to Purchase shall cease to accrue interest on and after the Payment Date;

(5) that Holders electing to have a Note purchased pursuant to the Offer to Purchase will be required to surrender the Note to the Paying Agent at the address specified in the notice prior to the close of business on the business day immediately preceding the Payment Date;

(6) that Holders will be entitled to withdraw their election if the Paying Agent receives, not later than the close of business on the third business day immediately preceding the Payment Date, a telegram, facsimile transmission or letter setting forth the name of such Holder, the principal

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amount of notes delivered for purchase and a statement that such Holder is withdrawing his election to have such notes purchased; and

(7) that Holders whose notes are being purchased only in part will be issued new notes equal in principal amount to the unpurchased portion of the notes surrendered;provided that each Note purchased and each new Note issued shall be in a principal amount of US$2,000 or an integral multiple of US$1,000 in excess thereof.

On the Payment Date, the Issuer shall (a) accept for payment on a pro rata basis notes or portions thereof tendered pursuant to an Offer to Purchase; (b) deposit with the Paying Agent money sufficient to pay the purchase price of all notes or portions thereof so accepted; and (c) deliver, or cause to be delivered, to the Trustee all notes or portions thereof so accepted together with an officers' certificate specifying the notes or portions thereof accepted for payment by the Issuer. The Paying Agent shall promptly mail to the Holders of notes so accepted payment in an amount equal to the purchase price, and the Trustee shall promptly authenticate and mail to such Holders a new Note equal in principal amount to any unpurchased portion of the Note surrendered;provided that each Note purchased and each new Note issued shall be in a principal amount of US$2,000 or an integral multiple of US$1,000 in excess thereof. The Issuer will publicly announce the results of an Offer to Purchase as soon as practicable after the Payment Date. The Trustee shall act as the Paying Agent for an Offer to Purchase. The Issuer will comply with Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable, in the event that the Issuer is required to repurchase notes pursuant to an Offer to Purchase. If securities law prohibits the Issuer from making an Offer to Purchase, the Issuer shall not be required to make an Offer to Purchase and the failure to make such an Offer will not constitute an Event of Default under the indenture.

"Permitted Investment" means:

(1) an Investment in the Issuer or a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary or be merged, consolidated or amalgamated with or into or transfer or convey all or substantially all its assets to, the Issuer or a Restricted Subsidiary;provided that such person's primary business is the Oil and Gas Business;

(2) Temporary Cash Investments;

(3) payroll, travel, moving and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses in accordance with GAAP;

(4) stock, obligations or securities received in satisfaction of judgments;

(5) an Investment in an Unrestricted Subsidiary consisting solely of an Investment in another Unrestricted Subsidiary;

(6) Commodity Agreements, Interest Rate Agreements and Currency Agreements designed solely to manage fluctuations in commodity prices, interest rates or foreign currency exchange rates;

(7) any Oil and Gas Investment;provided that if an Affiliate of the Issuer (other than a Restricted Subsidiary thereof) owns or holds any direct or indirect interest in the Person in which the Investment is made, such Investment is made upon fair and reasonable terms in an arm's-length transaction as determined by the Board of Directors of the Issuer;

(8) any Investments received in compromise of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer;

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(9) other Investments having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other investments made pursuant to this clause (9) since the Closing Date, not to exceed $75.0 million;

(10) Guarantees of Indebtedness of the Issuer and its Restricted Subsidiaries permitted by the covenant described under "Certain Covenants—Limitation on Indebtedness;" and

(11) Investments in existence on the Closing Date.

"Permitted Liens" means:

(1) Liens for taxes, assessments, governmental charges or claims that are not delinquent or that are being contested in good faith by appropriate legal proceedings promptly instituted and diligently conducted and for which a reserve or other appropriate provision, if any, as shall be required in conformity with GAAP shall have been made;

(2) statutory and common law Liens of landlords and carriers, warehousemen, mechanics, suppliers, materialmen, repairmen or other similar Liens arising in the ordinary course of business and with respect to amounts not yet delinquent or being contested in good faith by appropriate legal proceedings promptly instituted and diligently conducted and for which a reserve or other appropriate provision, if any, as shall be required in conformity with GAAP shall have been made;

(3) Liens incurred or deposits made in the ordinary course of business in connection with workers' compensation, unemployment insurance and other types of social security;

(4) Liens incurred or deposits made to secure the performance of tenders, bids, leases, statutory or regulatory obligations, bankers' acceptances, surety and appeal bonds, government contracts, performance and return-of-money bonds and other obligations of a similar nature incurred in the ordinary course of business (exclusive of obligations for the payment of borrowed money);

(5) easements, rights-of-way, municipal and zoning ordinances and similar charges, encumbrances, title defects, minor survey exceptions or other irregularities that do not materially interfere with the ordinary course of business of the Issuer or any of its Restricted Subsidiaries;

(6) licenses, sublicenses, leases or subleases granted to others that do not materially interfere with the ordinary course of business of the Issuer and its Restricted Subsidiaries, taken as a whole;

(7) Liens encumbering property or assets under construction arising from progress or partial payments by a customer of the Issuer or its Restricted Subsidiaries relating to such property or assets;

(8) any interest or title of a lessor in the property subject to any operating lease;

(9) Liens arising from filing Uniform Commercial Code or Personal Property Security Act financing statements regarding leases;

(10) Liens on property of, or Capital Stock or Indebtedness of, any Person existing at the time such Person becomes, or becomes a part of the Issuer or any of its Restricted Subsidiaries;provided that such Liens do not extend to or cover any property or assets of the Issuer or any Restricted Subsidiary other than the property or assets acquired;

(11) Liens in favor of the Issuer or any Restricted Subsidiary;

(12) Liens arising from the rendering of a final judgment or order against the rust or any Restricted Subsidiary that does net give rise to an Event of Default;

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(13) Liens securing reimbursement obligations with respect to letters of credit that encumber documents and other property relating to such letters of credit and the products and proceeds thereof;

(14) Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods;

(15) Liens encumbering customary initial deposits and margin deposits, and other Liens that are within the general parameters customary in the industry and incurred in the ordinary course of business, in each case, under Commodity Agreements, Interest Rate Agreements and Currency Agreements designed solely to manage fluctuations in interest rates, currencies or the price of commodities;

(16) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into by the Issuer or any of its Restricted Subsidiaries in the ordinary course of business in accordance with the past practices of the Issuer and its Restricted Subsidiaries prior to the Closing Date;

(17) Liens on Capital Stock of any Unrestricted Subsidiary to secure Indebtedness of such Unrestricted Subsidiary;

(18) Liens en or sales of receivables;

(19) Liens on property existing at the time of acquisition of the property by the Issuer or any of its Restricted Subsidiaries,provided that such Liens were in existence prior to the contemplation of such acquisition and do not extend to any property of the Issuer or any Restricted Subsidiary other than the property so acquired by the Issuer or such Restricted Subsidiary;

(20) Liens incurred in the ordinary course of business of the Issuer or any Restricted Subsidiary of the Issuer with respect to obligations that do not in the aggregate exceed $40.0 million at any one time outstanding;

(21) Liens in pipelines or pipeline facilities that arise by operation of law;

(22) Liens under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements, including in each case Liens for penalties arising under such agreements area of mutual interest agreements and other agreements, or arising by operation of law, that are customary in the Oil and Gas Business;provided that such Liens are not created or incurred in connection with any Indebtedness;

(23) Liens to secure payment of royalties, revenue interests, net profits interests and preferential rights of purchase incurred in the ordinary course of business to the extent of the security interest in those underlying assets;provided that such Liens are not created or incurred in connection with any Indebtedness;

(24) Liens in oil, gas or other mineral property or products derived from such property to secure obligations incurred or Guarantees of obligations incurred in connection with or necessarily incidental to commitments of purchase or sale of, or the transportation, storage or distribution of, such property or the products derived from such property;provided that such Liens are not created or incurred in connection with any Indebtedness;

(25) any right of first refusal in favor of any Person granted in the ordinary course of business with respect to the interests of the Issuer or any Restricted Subsidiary in any oil, gas or other hydrocarbon properties;provided that such Liens are not created or incurred in connection with any Indebtedness; and

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(26) Liens in favor of the Trustee.

"Person" means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

"Preferred Stock" of a Person means any Capital Stock of such Person that has preferential rights to any other Capital Stock of such Person with respect to distributions, dividends or redemptions upon liquidation.

"Reference Treasury Dealer Quotation" means, with respect to the Reference Treasury Dealer and any redemption date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Trustee by that Reference Treasury Dealer at 3:30 p.m. (New York time) on the third business day preceding that redemption date.

"Reference Treasury Dealer" means Banc of America Securities LLC and HSBC Securities (USA) Inc., or their affiliates, plus one other Primary Treasury Dealer (as defined below) appointed by the Issuer, and their respective successors;provided,however, that if any of the foregoing ceases to be a primary U.S. Government securities dealer in The City of New York (a "Primary Treasury Dealer"), the Issuer will substitute therefore another Primary Treasury Dealer, if available.

"Refinery" means the medium gravity sour crude oil hydrocracking refinery owned by the Issuer and its Restricted Subsidiaries on the Closing Date.

"Registration Rights Agreement" means (1) with respect to the notes issued on the Closing Date, the Registration Rights Agreement, to be dated the Closing Date, among the Issuer, the Initial Subsidiary Guarantors, and the Initial Purchasers and (2) with respect to any Additional Notes, any registration rights agreement between the Issuer and the other parties thereto relating to the registration by the Issuer of such Additional Notes under the Securities Act.

"Restricted Subsidiary" means any Subsidiary of the Issuer other than an Unrestricted Subsidiary.

"Sale and Leaseback Transaction" means, with respect to any Person, any transaction involving any of the assets or properties of such Person whether now owned or hereafter acquired, whereby such Person sells or otherwise transfers such assets or properties and then or thereafter leases such assets or properties or any part thereof or any other assets or properties which such Person intends to use for substantially the same purpose or purposes as the assets or properties sold or transferred.

"SEC" means the United States Securities and Exchange Commission.

"Securities Act" means the Securities Act of 1933 and any successor statute thereto, in each case as amended from time to time.

"S&P" means Standard & Poor's Ratings Group, a division of The McGraw-Hill Companies, and its successors.

"Significant Subsidiary" means, at any date of determination, any Restricted Subsidiary that, together with its Subsidiaries, (1) for the most recent fiscal year of the Issuer, accounted for more than 10% of the consolidated revenues of the Issuer and its Restricted Subsidiaries or (2) as of the end of such fiscal year, was the owner of more than 10% of the consolidated assets of the Issuer and its Restricted Subsidiaries, all as set forth on the most recently available consolidated financial statements of the Issuer for such fiscal year.

"Stated Maturity" means, (1) with respect to any debt security, the date specified in such debt security as the fixed date on which the final installment of principal of such debt security is due and payable and (2) with respect to any scheduled installment of principal of or interest on any debt

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security, the date specified in such debt security as the fixed date on which such installment is due and payable.

"Subsidiary" means, with respect to any Person, any corporation, association or other business entity of which more than 50% of the voting power of the outstanding Voting Stock is owned, directly or indirectly, by such Person and one or more other Subsidiaries of such Person.

"Subsidiary Guarantor" means any initial Subsidiary Guarantor and any other Restricted Subsidiary which provides a Note Guarantee until such Subsidiary is released from its Note Guarantee in accordance with the terms of the indenture.

"Temporary Cash investment" means any of the following:

(1) direct obligations of the United States of America or Canada or any agency thereof or obligations fully and unconditionally guaranteed by the United States of America or Canada or any agency thereof, in each case maturing within one year unless such obligations are deposited by the Issuer (x) to defease any Indebtedness or (y) in a collateral or escrow account or similar arrangement to prefund the payment of interest on any indebtedness;

(2) time deposit accounts, certificates of deposit and money market deposits maturing within 180 days of the date of acquisition thereof issued by a bank or trust company which is organized under the laws of the United States of America or Canada, any state or province thereof or any foreign country recognized by the United States of America or Canada, and which bank or trust company has capital, surplus and undivided profits aggregating in excess of $100.0 million (or the foreign currency equivalent thereof) and has outstanding debt which is rated "A" (or such similar equivalent rating) or higher by at least one nationally recognized statistical rating organization (as defined in Rule 436 under the Securities Act) or any money market fund sponsored by a registered broker dealer or mutual fund distributor;

(3) repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clause (1) above entered into with a bank or trust company meeting the qualifications described in clause (2) above;

(4) commercial paper, maturing not more than one year after the date of acquisition, issued by a corporation (other than an Affiliate of the Issuer) organized and in existence under the laws of the United States of America or Canada, any state or province thereof or any foreign country recognized by the United States of America or Canada with a rating at the time as of which any investment therein is made of "P-1" (or higher) according to Moody's or "A-1" (or higher) according to S&P;

(5) securities with maturities of six months or less from the date of acquisition issued or fully and unconditionally guaranteed by any state, commonwealth or territory of the United States of America, any province of Canada, or by any political subdivision or taxing authority thereof, and rated at least "A" by S&P or Moody's; and

(6) any mutual fund that has at least 95% of its assets continuously invested in investments of the types described in clauses (1) through (5) above.

"Total Assets" means the total assets of a Person and its Restricted Subsidiaries on a consolidated basis as set forth in such Person's most recent balance sheet prepared in accordance with GAAP calculated giving pro forma effect to any Asset Acquisitions or Asset Dispositions made after such balance sheet date and on or prior to the date of the action giving rise to the calculation thereof;provided that in calculating the Total Assets of the Issuer or any Restricted Subsidiary, such amount shall not include any oil and gas inventory or accounts receivable pledged to Secure Liens pursuant to clause (8) of the covenant described under "Certain Covenants—Limitation on Liens."

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"Trade Payables" means, with respect to any Person, any accounts payable or any other indebtedness or monetary obligation to trade creditors created, assumed or Guaranteed by such Person or any of its Subsidiaries arising in the ordinary course of business in connection with the acquisition of goods or services.

"Transaction Date" means, with respect to the Incurrence of any Indebtedness, the date such Indebtedness is to be incurred and, with respect to any Restricted Payment, the date such Restricted Payment is to be made.

"Treasury Rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

"Unrestricted Subsidiary" means (1) any Subsidiary of the Issuer that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Issuer in the manner provided below; and (2) any Subsidiary of an Unrestricted Subsidiary. The Board of Directors may designate any Restricted Subsidiary (including any newly acquired or newly formed Subsidiary of the Issuer) to be an Unrestricted Subsidiary unless such Subsidiary owns any Capital Stock of, or owns or holds any Lien on any property of, the Issuer or any Restricted Subsidiary;provided that (A) any Guarantee by the Issuer or any Restricted Subsidiary of any Indebtedness of the Subsidiary being so designated shall be deemed an "Incurrence" of such Indebtedness and an "Investment" by the Issuer or such Restricted Subsidiary (or both, if applicable) at the time of such designation; (B) either (I) the Subsidiary to be so designated has total assets of $1,000 or less or (II) if such Subsidiary has assets greater than $1,000, such designation would be permitted by the covenant described under "Certain Covenants—Limitation on Restricted Payments" and (C) if applicable, the Incurrence of Indebtedness and the Investment referred to in clause (A) of this proviso would be permitted by the covenants described under "Certain Covenants—Limitation on Indebtedness" and "Certain Covenants—Limitation on Restricted Payments." The Board of Directors may designate any Unrestricted Subsidiary to be a Restricted Subsidiary;provided that (a) no Default or Event of Default shall have occurred and be continuing at the time of or after giving effect to such designation, (b) all Liens and Indebtedness of such Unrestricted Subsidiary outstanding immediately after such designation would, if Incurred at such time, have been permitted to be Incurred (and shall be deemed to have been Incurred) for all purposes of the indenture and (c) all outstanding Investments owned by such Unrestricted Subsidiary will be deemed to be made as of the time of such designation and such Investments shall only be permitted if such Investments would be permitted by the covenant described under "Certain Covenants—Limitation on Restricted Payments." Any such designation by the Board of Directors shall be evidenced to the Trustee by promptly filing with the Trustee a copy of the resolution of the Board of Directors of the Issuer giving effect to such designation and an officers' certificate certifying that such designation complied with the foregoing provisions.

"U.S. Government Obligations" means securities that are (1) direct obligations of the United States of America for the payment of which its full faith and credit is pledged or (2) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof at any time prior to the Stated Maturity of the notes, and shall also include a depository receipt issued by a bank or trust company as custodian with respect to any such U.S. Government Obligation or a specific payment of interest on or principal of any such U.S. Government Obligation held by such custodian for the account of the holder of a depository receipt;provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the

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U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depository receipt.

"Voting Stock" means with respect to any Person, Capital Stock of any class or kind ordinarily having the power to vote for the election of directors, managers or other voting members of the governing body of such Person.

"Wholly Owned" means, with respect to any Subsidiary of any Person, the ownership of all of the outstanding Capital Stock of such Subsidiary (other than any director's qualifying shares or Investments by foreign nationals mandated by applicable law) by such Person or one or more Wholly Owned Subsidiaries of such Person.

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FEDERAL INCOME TAX CONSIDERATIONS

U.S. Federal Income Tax Considerations

The following discussion of the material U.S. federal income tax consequences to U.S. Holders (as defined below) of the exchange of initial notes for exchange notes pursuant to the exchange offer and the ownership and disposition of the exchange notes, to the extent it constitutes discussion of law and legal conclusions and subject to the limitations and qualifications set forth herein and in Exhibit 8.1, is the opinion of Paul, Weiss, Rifkind, Wharton & Garrison LLP, our U.S. federal income tax counsel. This discussion is not a complete analysis or description of all of the possible tax consequences of such transactions and does not address all tax considerations that might be relevant to particular U.S. Holders in light of their personal circumstances or to persons that are subject to special tax rules, such as:

•: dealers in securities or currencies,
•: traders in securities that elect to use a mark-to-market method of accounting for their securities holdings,
•: banks,
•: financial institutions,
•: insurance companies,
•: tax-exempt organizations,
•: partnerships or other pass-through entities (or persons that hold the initial notes or the exchange notes through partnerships or other pass-through entities),
•: persons subject to alternative minimum tax,
•: persons that own the initial notes or the exchange notes as part of a hedge or that are hedged against interest rate risks,
•: persons that own the initial notes or the exchange notes as part of a straddle, conversion, constructive sale or other integrated transaction for tax purposes,
•: holders whose functional currency for tax purposes is not the U.S. dollar, or
•: U.S. expatriates.

The information set forth below deals only with U.S. Holders that hold the initial notes and exchange notes as capital assets within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended (the "Code").

This discussion is based on the Code, its legislative history, existing and proposed Treasury regulations, published rulings and court decisions, all as currently in effect. These laws are subject to change, possibly on a retroactive basis. Any of the authorities on which this discussion is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis, which could affect the U.S. federal income tax considerations described in this section. This discussion does not address the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive or prospective basis. We have not sought and will not seek any rulings from the IRS with respect to the matters discussed below. There can be no assurance that the IRS will not take a different position concerning the tax consequences of the exchange of initial notes for exchange notes pursuant to the exchange offer and ownership or disposition of the exchange notes acquired by U.S. Holders pursuant to the exchange offer or that any such position would not be sustained. This section does not discuss any tax

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consequences arising under the U.S. federal estate and gift tax laws or the laws of any state, local or other taxing jurisdiction.

Holders of our notes are encouraged to consult their own tax advisors concerning the tax consequences discussed below in light of their particular circumstances, including the application of any state, local, foreign or other tax laws, including gift and estate tax laws.

A U.S. Holder is a beneficial owner of an initial note or an exchange note that is: (1) a citizen or resident alien of the United States as determined for U.S. federal income tax purposes, (2) a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia, (3) an estate the income of which is subject to U.S. federal income tax regardless of its source, or (4) a trust (A) if a court within the United States is able to exercise primary supervision over its administration and one or more U.S. persons have authority to control all substantial decisions of the trust, or (B) that has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person for U.S. federal income tax purposes.

If an entity taxable as a partnership (or other "pass-through" entity) for U.S. federal income tax purposes holds the exchange notes, the U.S. federal income tax treatment of a partner (or other owner) will depend on the status of the partner (or other owner) and the activities of the entity. Such partner (or other owner) that acquires or holds the exchange notes is encouraged to consult its own tax advisors.

Exchange Offer

The exchange of the initial notes for exchange notes in this exchange offer will not constitute a taxable event for U.S. Holders. Consequently, an exchanging U.S. Holder will not recognize gain or loss on the exchange. The holding period of the exchange note will include the holding period of the initial note and the basis of the exchange note will be the same as the basis of the initial note immediately before the exchange.

Interest

Stated interest paid on an exchange note will be taxable to a U.S. Holder as ordinary interest income at the time it is received or accrued, depending on the U.S. Holder's method of accounting for U.S. federal income tax purposes. Stated interest received by a U.S. Holder will be treated as foreign source income for purposes of calculating the U.S. Holder's U.S. foreign tax credit limitation, and will be "passive category income" or, in the case of certain U.S. Holders, "general category income." The rules governing U.S. foreign tax credits are complex and U.S. Holders are encouraged to consult their own tax advisors regarding the availability of U.S. foreign tax credits in their particular circumstances.

Market Discount

If a U.S. Holder purchased an initial note for an amount that is less than its stated redemption price at maturity, the amount of the difference will be treated as market discount for United States federal income tax purposes. The amount of any market discount will be treated asde minimis and disregarded if it is less than¹/4 of 1 percent of the revised issue price of the initial note, multiplied by the number of remaining complete years to maturity. The rules described below do not apply to U.S. Holders that own an initial note that hasde minimis market discount.

Under the market discount rules, a U.S. Holder is required to treat any principal payment on, or any gain on the sale, exchange, redemption or other disposition of, an exchange note as ordinary income to the extent of any market discount that has not previously been included in income. If a U.S. Holder disposes of an exchange note in a nontaxable transaction (other than certain specified

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nonrecognition transactions), such Holder will be required to include any accrued market discount as ordinary income as if it had sold the exchange note at its then fair market value. In addition, U.S. Holders may be required to defer, until the maturity of the exchange note or its earlier disposition in a taxable transaction, the deduction of a portion of the interest expense on any indebtedness incurred or continued to purchase or carry the initial note or the exchange note received in exchange therefor.

Market discount accrues ratably during the period from the date on which a U.S. Holder acquired the initial note through the maturity date of the exchange note (for which the initial note was exchanged), unless such Holder makes an irrevocable election to accrue market discount under a constant yield method. A U.S. Holder may elect to include market discount in income currently as it accrues (either ratably or under the constant-yield method), in which case the rule described above regarding deferral of interest deductions will not apply. If a U.S. Holder makes an election to include market discount in income currently, its adjusted basis in an exchange note will be increased by any market discount included in income with respect to such note. An election to include market discount currently will apply to all market discount obligations acquired during or after the first taxable year in which the election is made, and may not be revoked without the consent of the IRS.

Bond Premium

If a U.S. Holder purchased an initial note for an amount in excess of its principal amount, such Holder may treat the excess as amortizable bond premium. If a U.S. Holder makes this election, it will reduce the amount required to be included in its income each year with respect to interest on an exchange note by the amount of amortizable bond premium allocable to that year. The election, once made, will apply to all taxable bonds held during the taxable year for which the election is made or subsequently acquired, and cannot be revoked without the consent of the IRS. If a U.S. Holder does not make this election, such Holder will be required to include in gross income the full amount of interest on the exchange note in accordance with its regular method of tax accounting, and will include the premium in its tax basis for the exchange note for purposes of computing the amount of its gain or loss recognized on the taxable disposition of the exchange note. U.S. Holders are encouraged to consult their own tax advisors concerning the computation and amortization of any bond premium on an exchange note under their individual circumstances.

Sale, Exchange or Other Disposition of a Note

Except to the extent discussed above under "—Market Discount," upon the sale, exchange, or other taxable disposition of an exchange note, a U.S. Holder will recognize taxable gain or loss equal to the difference, if any, between the amount realized on such disposition (except to the extent any amount realized is attributable to accrued but unpaid stated interest, which will be taxable as described under "—Interest" above) and the U.S. Holder's tax basis in the note. Except to the extent discussed above under "—Market Discount and—Bond Premium," a U.S. Holder's initial tax basis in a note will equal the amount such holder paid for the note. Except to the extent discussed above under "—Market Discount," such gain or loss will be capital gain or loss and will be treated as long-term capital gain or loss if the note has been held for more than one year at the time of the disposition of the note. Net long-term capital gains of non-corporate U.S. Holders, including individuals, currently are eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations. Such capital gain or loss will constitute U.S. source income or loss for U.S. Federal income tax purposes if the U.S. Holder is a "United States resident" as determined for the purposes of the rules regarding the source of income. Market discount, if any, will likely constitute foreign source income or loss for U.S. federal income tax purposes.

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Additional Tax on Passive Income

For tax years beginning after December 31, 2012, certain individuals, estates and trusts whose income exceeds certain thresholds will be required to pay a 3.8% tax on "net investment income" including, among other things, interest and net gain from disposition of property (other than property held in a trade or business). U.S. Holders are encouraged to consult with their own tax advisors regarding the effect, if any, of this tax on their ownership and disposition of exchange notes.

Information Reporting and Backup Withholding

Information reporting requirements and backup withholding may apply to certain payments to U.S. Holders of interest on the exchange notes and to the proceeds of a sale, exchange or other disposition (including a redemption) of an exchange note. Backup withholding may be required if the U.S. Holder fails (i) to furnish the U.S. Holder's correct taxpayer identification number, (ii) to certify that such U.S. Holder is not subject to backup withholding or (iii) to otherwise comply with the applicable requirements of the backup withholding rules. Certain U.S. Holders are not subject to the information reporting and backup withholding requirements. Backup withholding is not an additional tax. A U.S. Holder may be entitled to a refund or a credit with respect to any amounts withheld under the backup withholding rules, provided that the required information is furnished to the Internal Revenue Service in a timely manner.

Investor Reporting Requirements

Certain U.S. Holders are required to report investments in "specified foreign financial assets," which may include the exchange notes if they are not held through a custodial account with a U.S. financial institution. Holders that fail to report this information, if required, could become subject to substantial penalties. U.S. Holders are encouraged to consult with their own tax advisors regarding this reporting requirement.

Canadian Federal Income Tax Considerations

The following is a general discussion of the principal Canadian federal income tax considerations generally applicable to a person who acquires exchange notes in exchange for initial notes and who, for the purposes of theIncome Tax Act (Canada) (the "Canadian Tax Act") and at all relevant times, is not resident in Canada, deals at arm's length with us, holds the initial notes as capital property, will hold the exchange notes as capital property, does not use or hold and is not deemed or considered to use or hold the initial notes in carrying on business in Canada, and will not use or hold and will not be deemed or considered to use or hold the exchange notes in carrying on business in Canada (an "Unconnected Holder"). For the purposes of the Canadian Tax Act, related persons (as therein defined) are deemed not to deal at arm's length. Special rules which are not discussed below may apply to an Unconnected Holder that is an insurer that carries on an insurance business in Canada and elsewhere.

This discussion is based on the current provisions of the Canadian Tax Act and the regulations thereunder (the "Regulations") in force on the date hereof, all specific proposals to amend the Canadian Tax Act and the Regulations publicly announced by the Minister of Finance (Canada) prior to the date hereof and our understanding of the published administrative practices of the Canada Revenue Agency. This summary does not take into account or anticipate any other changes in law or administrative practice, whether by legislative, government or judicial decision or action and does not take into account provincial, territorial or foreign income tax legislation or considerations.

This discussion is of a general nature only, and is not intended to be, nor should it be interpreted as, legal or tax advice to any particular Unconnected Holder and no representation is made with respect to the Canadian income tax consequences to any particular person exchanging initial notes for

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exchange notes.We recommend that Unconnected Holders consult their own tax advisors with respect to their particular circumstances.

The exchange by an Unconnected Holder of initial notes for exchange notes will not be subject to Canadian income tax.

Under the Canadian Tax Act, payments by us to an Unconnected Holder of principal and interest on the exchange notes will be exempt from Canadian withholding tax.

No other Canadian taxes on income, including taxable capital gains, will be payable by an Unconnected Holder under the Canadian Tax Act solely as a consequence of the ownership, acquisition or disposition of exchange notes.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for initial notes where such initial notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the effective date of this registration statement, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until December 30, 2012, all dealers effecting transactions in the exchange notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. The exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of 180 days after the effective date of this registration statement, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the Corporation in connection with the exchange offer and will indemnify the holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS

Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York, will pass on the validity of the exchange notes and guarantees offered hereby under United States law. Bennett Jones LLP, Calgary, Alberta, will pass on certain matters of Canadian federal law and the laws of the Province of Alberta relating to the exchange notes and guarantees by Harvest Breeze Trust No. 1, Harvest Breeze Trust No. 2, Breeze Resources Partnership, Hay River Partnership and 1496965 Alberta Ltd. offered hereby. Stewart McKelvey, Newfoundland and Labrador, will pass on certain matters of the laws of the Province of Newfoundland and Labrador relating to the guarantees by North Atlantic Refining Limited offered hereby.

INDEPENDENT QUALIFIED RESERVES EVALUATORS

Information relating to our reserves set forth herein was calculated by McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd. as independent petroleum consultants and such information is included herein on the authority of such firms as experts.

EXPERTS

The audited financial statements of Harvest Operations Corp. as of December 31, 2011 and for the year then ended have been included herein in reliance upon the report of Ernst & Young LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing. The audited financial statements of Harvest Operations Corp. as of December 31, 2010 and for the year then ended have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

AVAILABLE INFORMATION

We are not subject to the information requirements of Sections 13(a) or 15(d) of the Exchange Act. You should rely only upon the information provided in this prospectus. We have not authorized anyone to provide you with different information. You should not assume that the information in this prospectus is accurate as of any date other than the date of this prospectus.

This prospectus contains summaries of certain agreements that we have entered into in connection with the offering of the initial notes, such as the indenture for the notes. The descriptions contained in this prospectus of these agreements do not purport to be complete and are subject to, or qualified in their entirety by reference to, the definitive agreements.

Anyone who receives this prospectus may obtain a copy of the indenture without charge by writing to Harvest Operations Corp., 2100, 330 5^th Avenue S.W., Calgary, Alberta, Canada T2P 0L4, Attention: Investor Relations.

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INDEX TO FINANCIAL STATEMENTS

		Page

HARVEST OPERATIONS CORP.—CONSOLIDATED FINANCIAL STATEMENTS
Management's Report		F-2
Independent Auditors' Reports		F-3
Consolidated Statements of Financial Position		F-7
Consolidated Statements of Comprehensive Loss		F-8
Consolidated Statements of Changes in Shareholder's Equity		F-9
Consolidated Statements of Cash Flows		F-10
Notes to the Consolidated Financial Statements		F-11
HARVEST OPERATIONS CORP.—CONSOLIDATED INTERIM FINANCIAL STATEMENTS (UNAUDITED)
Consolidated Statements of Financial Position (Unaudited)		F-68
Consolidated Statements of Comprehensive Loss (Unaudited)		F-69
Consolidated Statements of Changes in Shareholder's Equity (Unaudited)		F-70
Consolidated Statements of Cash Flows (Unaudited)		F-71
Notes to the Consolidated Financial Statements (Unaudited)		F-72
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)		F-91

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 International Financial Reporting Standards as issued by the International Accounting Standards Board. 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 14, 2012. 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, 2011.

To meet our responsibility for reliable and accurate financial statements, management has established and monitors internal controls, 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 theInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have concluded that as of December 31, 2011, 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, Ernst & Young LLP. Their responsibility is to express a professional opinion on the fair presentation of the consolidated financial statements prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. 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 auditors and has recommended their approval to the Board of Directors. The Board of Directors has approved the consolidated financial statements of the Company.



Myunghuhn Yi President and Chief Executive Officer Harvest Operations Corp.		Chang-Koo Kang Chief Financial Officer Harvest Operations Corp.

Calgary, Alberta
June 14, 2012

F-2


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

INDEPENDENT AUDITORS' REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the Directors of Harvest Operations Corp.

We have audited the accompanying comparative information of Harvest Operations Corp., which comprise the consolidated statements of financial position as at December 31, 2010 and January 1, 2010, the consolidated statements of comprehensive loss, changes in shareholders' equity and cash flows for the year ended December 31, 2010, and notes, comprising a summary of significant accounting policies and other explanatory information, including Note 27, which explains how the transition from pre-changeover Canadian generally accepted accounting principles to International Financial Reporting Standards as issued by the International Accounting Standards Board affected the entity's reported consolidated financial position, financial performance and cash flows.

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 International Financial Reporting Standards as issued by the International Accounting Standards Board, 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

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, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. 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 is sufficient and appropriate to provide a basis for our audit opinion.

F-3

Opinion

In our opinion, the comparative information in these consolidated financial statements present fairly, in all material respects, the consolidated financial position of Harvest Operations Corp. as at December 31, 2010 and January 1, 2010, and its consolidated financial performance and its consolidated cash flows for the year ended December 31, 2010 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other matter

The consolidated statement of financial position as at December 31, 2011, the consolidated statements of comprehensive loss, changes in shareholders' equity and cash flows for the year ended December 31, 2011 and notes, comprising a summary of significant accounting policies and other explanatory information, are audited by another auditor who expressed an unmodified opinion on June 14, 2012.

Chartered Accountants
Calgary, Canada
June 14, 2012

F-4

INDEPENDENT AUDITORS' REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated financial statements of Harvest Operations Corp., which comprise the consolidated statement of financial position as at December 31, 2011, and the consolidated statements of comprehensive loss, changes in shareholder's equity and cash flows for the year then ended, and a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Auditors' responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). 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. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, 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 audit 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 financial position of Harvest Operations Corp. as at December 31, 2011, and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Comparative Information

Without modifying our opinion, we draw attention to Note 27 to the consolidated financial statements which describes that Harvest Operations Corp. adopted International Financial Reporting Standards on January 1, 2011 with a transition date of January 1, 2010. These standards were applied retrospectively by management to the comparative information in these financial statements, including

F-5

the consolidated statements of financial position as at December 31, 2010 and January 1, 2010, and the consolidated statements of comprehensive loss, changes in shareholder's equity and cash flows for the year ended December 31, 2010, and related disclosures. The financial statements of Harvest Operations Corp. for these periods were audited by another auditor who expressed an unmodified opinion on those statements on June 14, 2012.



Calgary, Canada June 14, 2012		Chartered accountants

F-6

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(thousands of Canadian dollars)	Notes	December 31, 2011			December 31, 2010			January 1, 2010

Assets
Current assets
Cash and cash equivalents	4	$	6,607		$	18,906		$	—
Accounts receivable and other	23, 26		212,252			213,931			178,662
Inventories	5		60,952			75,517			86,819
Prepaid expenses			18,526			55,071			15,551
Risk management contracts	23		20,162			1,007			—

			318,499			364,432			281,032
Non-current assets
Long-term deposit	25		24,925			30,603			—
Investment tax credits and other			53,994			44,339			2,177
Deferred income tax asset	20		—			1,633			—
Exploration and evaluation assets	6		74,517			59,554			36,034
Property, plant and equipment	7		5,400,387			4,483,236			4,054,619
Other long-term asset			7,105			—			—
Goodwill	8		404,943			404,943			404,943

			5,965,871			5,024,308			4,497,773

Total assets		$	6,284,370		$	5,388,740		$	4,778,805

Liabilities
Current liabilities
Bank loan	10, 23	$	—		$	—		$	428,017
Accounts payable and accrued liabilities	26		464,148			360,487			205,378
Current portion of convertible debentures	12		107,146			—			182,806
Current portion of senior notes	11		—			—			42,921
Current portion of decommissioning liabilities	9		12,782			16,672			11,710
Risk management contracts	23		—			7,553			2,052

			584,076			384,712			872,884
Non-current liabilities
Bank loan	10, 23		355,575			11,379			—
Convertible debentures	12		634,921			745,257			748,261
Senior notes	11, 23		495,674			482,389			222,456
Decommissioning liabilities	9		674,522			646,347			555,776
Post-employment benefit obligations	21		25,958			20,365			17,453
Deferred credits and other			5,093			293			357
Deferred income tax liability	20		54,907			81,143			142,105

			2,246,650			1,987,173			1,686,408

Total liabilities			2,830,726			2,371,885			2,559,292

Shareholder's equity
Shareholder's capital	13		3,860,786			3,355,350			2,422,688
Deficit			(388,995	)		(284,338	)		(203,175	)
Accumulated other comprehensive loss	22		(18,147	)		(54,157	)		—

Total shareholder's equity			3,453,644			3,016,855			2,219,513

Total liabilities and shareholder's equity		$	6,284,370		$	5,388,740		$	4,778,805

Commitments and contingencies[Note 25]

The accompanying notes are an integral part of these consolidated financial statements.

On behalf of the Board of Directors:



William D. Roberson, Director		J. Richard Harris, Director

F-7

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

			For the years ended December 31,

(thousands of Canadian dollars)	Notes		2011			2010
Petroleum, natural gas, and refined products sales			$	4,526,321		$	4,112,961
Royalties				(195,452	)		(154,757	)

Revenues		15		4,330,869			3,958,204
Expenses
Purchased products for processing and resale				3,055,236			2,893,805
Operating		16		576,131			481,233
Transportation and marketing				35,919			15,760
General and administrative		16		62,568			47,067
Depletion, depreciation and amortization				626,698			553,732
Exploration and evaluation		6		18,289			3,300
Gains on disposition of property, plant and equipment				(7,883	)		(741	)
Finance costs		17		109,127			100,808
Risk management contracts gains		23		(6,746	)		(550	)
Foreign exchange gains		18		(3,986	)		(3,399	)
Impairment on property, plant and equipment		7		—			13,661

Loss before income tax				(134,484	)		(146,472	)
Income tax recovery		20		(29,827	)		(65,309	)

Net loss				(104,657	)		(81,163	)

Other comprehensive income (loss)
Gains (losses) on derivatives designated as cash flow hedges, net of tax		22, 23		19,421			(5,020	)
Gains (losses) on foreign currency translation		22		21,480			(45,920	)
Actuarial loss, net of tax		21, 22		(4,891	)		(3,217	)

Comprehensive loss			$	(68,647	)	$	(135,320	)

The accompanying notes are an integral part of these consolidated financial statements.

F-8

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(thousands of Canadian dollars)	Notes	Shareholder's Capital		Deficit			Accumulated Other Comprehensive Loss			Total Shareholder's Equity

Balance at December 31, 2010		$	3,355,350	$	(284,338	)	$	(54,157	)	$	3,016,855
Issue of share capital for cash	3, 13		505,436		—			—			505,436
Gains on derivatives designated as cash flow hedges, net of tax	22		—		—			19,421			19,421
Gains on foreign currency translation	22		—		—			21,480			21,480
Actuarial loss, net of tax	21, 22		—		—			(4,891	)		(4,891	)
Net loss			—		(104,657	)		—			(104,657	)

Balance at December 31, 2011		$	3,860,786	$	(388,995	)	$	(18,147	)	$	3,453,644

Balance at January 1, 2010		$	2,422,688	$	(203,175	)	$	—		$	2,219,513
Issue of share capital for cash	13		932,662		—			—			932,662
Losses on derivatives designated as cash flow hedges, net of tax	22		—		—			(5,020	)		(5,020	)
Losses on foreign currency translation	22		—		—			(45,920	)		(45,920	)
Actuarial loss, net of tax	21, 22		—		—			(3,217	)		(3,217	)
Net loss			—		(81,163	)		—			(81,163	)

Balance at December 31, 2010		$	3,355,350	$	(284,338	)	$	(54,157	)	$	3,016,855

The accompanying notes are an integral part of these consolidated financial statements.

F-9

CONSOLIDATED STATEMENTS OF CASH FLOWS

		For the years ended December 31,

(thousands of Canadian dollars)	Notes	2011			2010
Cash provided by (used in)
Operating Activities
Net loss for the period		$	(104,657	)	$	(81,163	)
Items not requiring cash
Depletion, depreciation and amortization			626,698			553,732
Accretion of decommissioning liabilities	9, 17		23,551			22,685
Unrealized gains on risk management contracts	23		(746	)		(2,358	)
Unrealized (gains) losses on foreign exchange	18		2,555			(1,875	)
Non-cash interest income			(652	)		(7,029	)
Unsuccessful exploration and evaluation costs	6		17,757			2,858
Impairment of property, plant and equipment	7		—			13,661
Gains on disposition of property, plant and equipment			(7,883	)		(741	)
Deferred income tax recovery	20		(29,880	)		(65,097	)
Other non-cash items			4,795			(1,093	)
Realized foreign exchange gain on senior note redemptions			—			(6,438	)
Settlement of decommissioning liabilities	9		(22,110	)		(20,257	)
Change in non-cash working capital	19		51,061			32,299

			560,489			439,184

Financing Activities
Issue of common shares, net of issue costs	3,13		505,436			558,493
Bank borrowing (repayments), net			343,315			(416,743	)
Issue of seniors notes, net of issue costs	11		—			495,935
Redemptions of senior notes	11		—			(256,931	)
Redemptions of convertible debentures	12		—			(180,193	)
Change in non-cash working capital	19		—			1,952

			848,751			202,513

Investing Activities
Business acquisitions	3		(509,829	)		(145,144	)
Additions to property, plant and equipment	7		(966,741	)		(428,085	)
Additions to exploration and evaluation	6		(50,883	)		(46,997	)
Additions to other long term assets			(7,413	)		—
Property dispositions (acquisitions), net			4,474			(30,513	)
Change in non-cash working capital	19		108,747			22,503

			(1,421,645	)		(628,236	)

Change in cash and cash equivalents			(12,405	)		13,461
Effect of exchange rate changes on cash and cash equivalents			106			5,445
Cash and cash equivalents, beginning of year			18,906			—
Cash and cash equivalents, end of year		$	6,607		$	18,906

Interest paid		$	75,858		$	66,917
Income tax paid (received), net		$	53		$	(212	)

The accompanying notes are an integral part of these consolidated financial statements.

F-10

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

1. Nature of Operations and Structure of the Company

Harvest Operations Corp. ("Harvest" or the "Company") is an integrated energy company with petroleum and natural gas operations focused on the operation and further development of assets in western Canada ("Upstream") and a medium gravity sour crude hydrocracking refinery and retail and wholesale petroleum marketing business both located in the Province of Newfoundland and Labrador ("Downstream"). Harvest's Downstream business operates under its wholly owned subsidiary, North Atlantic Refining Limited ("North Atlantic").

Harvest is a wholly owned subsidiary of Korea National Oil Corporation ("KNOC"). The Company is incorporated and domiciled in Canada.

These consolidated financial statements were approved and authorized for issue by the Board of Directors on June 14, 2012.

Harvest's principal place of business is located at 2100, 330 - 5^th Avenue SW, Calgary, Alberta, Canada T2P 0L4.

2. Basis of Presentation and Significant Accounting Policies

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").

Prior to January 1, 2011, Harvest reported its consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") as set out in the Handbook of the Canadian Institute of Chartered Accountants. Effective January 1, 2011, the Company commenced reporting under IFRS. In these consolidated financial statements, the term "Canadian GAAP" refers to Canadian GAAP before the adoption of IFRS.

Subject to certain transition elections disclosed in note 27, Harvest has consistently applied the same accounting policies in its opening IFRS statement of financial position at January 1, 2010 and throughout all periods presented. Note 27 discloses the impact of the transition to IFRS on the Company's reported financial position, operating results and cash flows, including the nature and effect of significant changes in accounting policies from those used in the Company's consolidated financial statements for the year ended December 31, 2010 reported under Canadian GAAP. Comparative figures for 2010 in these consolidated financial statements have been restated to give effect to these changes.

(a): Basis of Measurement

The consolidated financial statements have been prepared on the historical cost basis except for held for trading financial assets and derivative financial instruments, which are measured at fair value.

(b): Functional and Presentation Currency

In these consolidated financial statements, unless otherwise indicated, all dollar amounts are expressed in Canadian dollars, which is the Company's functional currency. All references to U.S. $ are to United States dollars.

F-11

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

(c): Use of Estimates and Judgments

The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are outlined below:

(i): Reserves

The provision for depletion and depreciation of Upstream assets is calculated on the unit-of-production method based on proved developed reserves. As well, reserve estimates impact net income through the application of impairment tests. Revisions or changes in the reserve estimates can have either a positive or a negative impact on net income and property, plant and equipment ("PP&E").

The process of estimating reserves is complex and requires significant judgments based on available geological, geophysical, engineering and economic data. In the process of estimating the recoverable oil and natural gas reserves and related future net cash flows, Harvest incorporates many factors and assumptions, such as:

•: expected reservoir characteristics based on geological, geophysical and engineering assessments;
•: future production rates based on historical performance and expected future operating and investment activities;
•: future commodity prices and quality differentials;
•: discount rates; and
•: future development costs.

On an annual basis, the Company engages qualified, independent reserve evaluators to evaluate Harvest's reserve data.

(ii): Impairment of long-lived assets

Long-lived assets (goodwill, PP&E and exploration and evaluation assets) are aggregated into cash-generating units ("CGUs") based on their ability to generate largely independent cash flows and are used for impairment testing. The determination of the Company's CGUs is subject to significant judgment; product type, internal operational teams, geology and geography were key factors considered when grouping Harvest's oil and gas assets into the CGUs.

PP&E is tested for impairment when indications of impairment exist. PP&E impairment indicators include decreases in commodity prices, production, reserves and operating

F-12

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

results, cost overruns and construction delays. E&E impairment indicators include expiration of the right to explore and cessation of exploration in specific areas, lack of potential for commercial viability and technical feasibility and when E&E costs are not expected to be recovered from successful development of an area. The determination of whether such indicators exist requires significant judgment.

The recoverable amounts of CGUs and individual assets are determined based on the higher of value-in-use calculations and estimated fair values less costs to sell. To determine the recoverable amounts, Harvest uses reserve estimates and future commodity prices for the Upstream operations and expected future refining margins and capital spending plans for the Downstream operations. The estimates of future commodity prices, refining margins and discount rates require significant judgments.

(iii): Exploration and evaluation ("E&E") assets

The decision to transfer assets from E&E to PP&E is dependent on the technical feasibility and commercial viability of the related E&E projects. Such decision is subject to management's judgment and use of estimates such as reserves, future commodity prices and discount rates.

(iv): Decommissioning liabilities

In the determination of decommissioning liabilities, management is required to make a significant number of estimates and assumptions with respect to activities that will occur in the future including the ultimate settlement amounts, inflation factors, risk-free discount rates, timing of settlement, emergence of new restoration techniques and expected changes in legal, regulatory, environmental and political environments. The decommissioning liabilities also result in an increase to the carrying cost of the related PP&E. The obligation accretes to a higher amount with the passage of time as it is determined using present values. A change in any one of the assumptions could impact the estimated future obligation and in return, net income and PP&E.

(v): Employee benefits

Harvest's Downstream operations maintains a defined benefit pension plan and provides certain post-retirement health care benefits, which cover the majority of its Downstream employees and their surviving spouses. An independent actuary determines the costs of the Company's employee future benefit programs using certain management assumptions and estimates such as, the expected plan investment performance, salary escalation, retirement ages of employees, expected health care costs, employee turnover, discount rates and return on plan assets. The obligation and expense recorded related to Harvest's employee future benefit plans could increase or decrease if there were to be a change in these estimates.

The Company also maintains a long-term incentive plan which is a performance-based program. As a result, the compensation costs accrued for the plan are subject to the

F-13

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

estimation of what the ultimate payout will be and are subject to management's judgment as to whether or not the performance criteria will be met.

(vi): Consideration transferred

Business acquisitions are accounted for using the acquisition method. Under this method, the consideration transferred is allocated to the assets acquired and the liabilities assumed based on the fair values at the time of the acquisition. In determining the fair value of the assets and liabilities, Harvest is often required to make assumptions and estimates, such as reserves, future commodity prices, future refining margins, fair value of undeveloped land, discount rates, decommissioning liabilities and possible outcome of any assumed contingencies. Changes in any of these assumptions would impact amounts assigned to assets and liabilities and goodwill in the consideration transferred allocation and as a result, future net income.

(vii): Risk management contracts

Derivative risk management contracts are valued using valuation techniques with market observable inputs. 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. Changes in any of these assumptions would impact fair value of the risk management contracts and as a result, future net income and other comprehensive income. For risk management contracts designated as hedges, changes in the above mentioned assumptions may impact hedge effectiveness assessment and Harvest's ability to continue applying hedge accounting.

(viii): Income taxes

Tax interpretations, regulations and legislation in the various jurisdictions in which Harvest and its subsidiaries operate are subject to change. The Company is also subject to income tax audits and reassessments which may change its provision for income taxes. Therefore, the determination of income taxes is by nature complex, and requires making certain estimates and assumptions.

Harvest recognizes the net deferred tax benefit related to deferred tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred tax assets requires the Company to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the net deferred tax assets recorded at the reporting date could be impacted.

F-14

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

(ix): Contingencies

Contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events.

Significant Accounting Policies

(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. Subsidiaries are fully consolidated from the date of acquisition, being the date on which Harvest obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of the subsidiaries are prepared for the same reporting period as Harvest, using consistent accounting policies.

Harvest conducts substantially all of its Upstream petroleum and natural gas production activities through jointly controlled assets. The consolidated financial statements reflect only Harvest's proportionate interest in such activities.

(b): 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. Revenues for retail services are recorded when the services are provided. Revenues are measured at the fair value of the consideration received or receivable.

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.

(c): 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-15

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

(d)

Property, Plant, and Equipment ("PP&E") and Exploration and Evaluation ("E&E") Assets

(i): Upstream

Exploration and evaluation expenditures

Prior to acquiring the legal rights to explore an area, all costs are charged directly to the statement of comprehensive loss as E&E expense.

Once the legal rights to explore are acquired, all costs directly associated with the E&E are capitalized. E&E costs are those expenditures incurred for identifying, exploring and evaluating new pools in an area where technical feasibility and commercial viability has not yet been determined. These costs include acquisition of land and mineral leases, geological and geophysical costs, decommissioning costs, E&E drilling, sampling, appraisals and directly attributable general and administrative costs. All such costs are subject to technical, commercial and management review to confirm the continued intent to develop. When this is no longer the case, the costs are charged to net income as E&E expense. When technical feasibility and commercial viability are established, the relevant expenditure is transferred to PP&E after impairment is assessed and any resulting impairment loss is recognized.

E&E assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, E&E assets are allocated to CGUs. The impairment of E&E assets, and any eventual reversal thereof, is recognized as E&E expense in the statement of comprehensive loss.

Development and production costs

The Upstream PP&E generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or an area basis (major components). Development costs include property acquisitions, development drilling, completion, gathering and infrastructure, decommissioning costs and transfers of E&E assets.

Major capital maintenance projects are capitalized but general maintenance and repair costs are charged against income. All other expenditures are recognized in net income as incurred. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of PP&E are recognized in net income as incurred.

Depletion, Depreciation and Amortization

Costs accumulated within each major component of PP&E are depleted using the unit-of-production method by reference to the ratio of production in the period to the related proved developed reserves. Costs of major development projects are excluded from the costs subject to depletion until they are available for use.

F-16

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

Corporate and administrative assets are depreciated on a straight-line basis over the individual assets' useful lives.

Disposal of assets

Gains and losses on disposal of an item of PP&E are determined by comparing the proceeds from disposal with the carrying amount of PP&E and are recognized in the period of disposal.

For exchanges that involve only unproven properties, the exchange is accounted for at cost. Exchanges of development and production assets are measured at fair value unless the exchange transaction lacks commercial substance if neither the fair value of the assets given up nor the assets received can be reliably estimated.

(ii): Downstream

PP&E related to the refining assets are recorded at cost. General maintenance and repair costs 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. Any gains or losses on disposal of individual assets are recognized in the year of disposal.

Depreciation

When significant parts of an item of PP&E have different useful lives, they are accounted for as separate items (major components). Depreciation of recorded cost less the residual value is provided on a straight-line basis over the estimated useful life of the major components as set out below.

	Asset		Period

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

(iii): Impairment of Property, Plant and Equipment and Exploration and Evaluation Assets

Harvest assesses, at each reporting date, whether there is an indication that an asset may be impaired. If any indication exists, Harvest estimates the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's fair value less costs to sell and its value-in-use. The recoverable amount is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. In such case, an impairment test is performed at the CGU

F-17

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

level. A CGU is a group of assets that Harvest aggregates based on their ability to generate largely independent cash flows.

Where the carrying amount of an asset or CGU exceeds its recoverable amount, the asset is considered impaired and is written down to its recoverable amount. To determine value-in-use, the Company estimates the present value of the future net cash flows expected to derive from the continued use of the asset or CGU. Discount rates that reflect the market assessments of the time value of money and the risks specific to the asset or CGU are used. In determining fair value less costs to sell, discounted cash flows and recent market transactions are taken into account, if available. These calculations are corroborated by valuation multiples or other available fair value indicators.

Impairment losses are recognized in those expense categories consistent with the function of the impaired asset. Impairment losses recognized in respect of a CGU are allocated to reduce the carrying amount of the assets in the unit on a pro rata basis.

For assets excluding goodwill, an assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Company estimates the asset's or CGU's recoverable amount. A previously recognized impairment loss is reversed only if there has been an improvement in the assumptions used to determine the asset's recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior periods. Such reversal is recognized in the net income.

(e): Capitalized interest

Interest on major development projects is capitalized until the project is complete using the weighted-average interest rate on all of Harvest's borrowings. Capitalized interest is limited to the actual interest incurred.

(f): Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method. The cost of an acquisition including any contingent consideration, is measured as the aggregate of the consideration transferred at acquisition date fair value. The acquired identifiable net assets are measured at their fair value at the date of acquisition. Any excess of the consideration transferred over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the consideration transferred below the fair value of the net assets acquired is recorded as a gain in net income. Associated transaction costs are expensed when incurred.

Those petroleum reserves and resources that are able to be reliably valued are recognized in the assessment of fair values on acquisition. The fair value of oil and natural gas interests is estimated with reference to the discounted cash flows expected to be derived from oil and

F-18

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

natural gas production based on reserve estimates. The risk-adjusted discount rate is specific to the asset with reference to general market conditions.

For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to groups of CGUs that are expected to benefit from the combination. Goodwill is carried at cost less impairment and is not amortized.

An impairment loss in respect of goodwill is not reversed. Goodwill is assessed for impairment annually at year-end or more frequently if events occur that could result in impairment. The recoverable amount is determined by calculating the recoverable amount of the group of CGUs goodwill has been allocated to. The excess of the carrying value of goodwill over the recoverable amount is then recognized as impairment and charged to income in the period in which it occurs.

(g)

Provisions

(i): General

Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Company expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current discount rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as a finance cost.

(ii): Decommissioning Liabilities

Harvest recognizes the present value of any decommissioning liabilities 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 risk-free rate to estimate the present value of the expenditure required to settle the present obligation at the reporting date. The associated decommissioning costs are capitalized as part of the carrying amount of the related asset and the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligation are charged against the decommissioning liabilities.

F-19

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

(iii): Contingencies

A contingency is disclosed where the existence of an obligation will only be confirmed by future events, or where the amount of a present obligation cannot be measured reliably or will likely not result in an economic outflow. Contingent assets are only disclosed when the inflow of economic benefits is probable.

(h): Income Taxes

Income tax expense comprises current and deferred tax. Income tax expense is recognized in net income except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred income tax liabilities and assets are generally not recognized for temporary differences arising on:

•: investments in subsidiaries and associates and interests in joint ventures;
•: the initial recognition of goodwill; or
•: the initial recognition of an asset or liability in a transaction which is not a business combination.

Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, and Harvest intends to settle current tax liabilities and assets on a net basis.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(i): Post-Employment Benefits

Harvest's Downstream operations 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 pension benefits and other post-retirement benefits is actuarially determined using the projected unit credit method reflecting 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.

F-20

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

Post-employment benefit expense includes the cost of benefits earned during the current year, the interest cost on the obligations and the expected return on plan assets.

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. Actuarial gains or losses are recognized in other comprehensive income immediately.

(j): Currency Translation

Foreign currency-denominated transactions are translated to the respective functional currencies of Harvest's entities at exchange rates at the date of the transactions. Non-monetary items measured at historical cost are not subsequently re-translated. Monetary assets and liabilities denominated in foreign currencies are converted into Harvest's functional currencies at the exchange rate at the reporting date. Conversion gains and losses on monetary items are included in net income in the period in which they arise.

Harvest's Downstream operations' functional currency is the U.S. dollar, while Harvest's presentation currency is the Canadian dollar. Therefore, the Downstream operations' assets and liabilities are translated at the period-end exchange rates, while revenues and expenses are translated using monthly average rates. Translation gains and losses relating to the foreign operations are included in accumulated other comprehensive income as a separate component of shareholder's equity.

(k): Financial Instruments

Harvest recognizes financial assets and financial liabilities, including derivatives, on the consolidated statements of financial position 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. Financial assets are derecognised when (1) the rights to receive cash flows from the assets have expired or (2) the Company has transferred its rights to receive cash flows from the assets or has assumed an obligation to pay the received cash flows in full without material delay to a third party under a 'pass-through' arrangement; and either (a) the Company has transferred substantially all the risks and rewards of the assets, or (b) the Company has neither transferred nor retained substantially all the risks and rewards of the assets, but has transferred control of the asset.

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

F-21

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

as available-for-sale are measured at fair values with changes in those fair values recognized in other comprehensive income.

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.

(l): 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 or cash flows 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.

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 statement of comprehensive loss 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 in 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,

F-22

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

or if its designation as a hedge is revoked, any cumulative gains or losses previously recognized in other comprehensive income remain in other comprehensive income until the forecast transaction affects net income.

(m): 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.

(n): Investment Tax Credits

Harvest is entitled to certain investment tax credits on qualifying manufacturing capital expenditures relating to its Downstream operations. These credits are recorded 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.

(o): Leases

Leases or other arrangements entered into for the use of an asset are classified as either finance or operating leases. Finance leases transfer to the Company substantially all of the risks and benefits incidental to ownership of the leased item. Finance leases are capitalized at the commencement of the lease term at the lower of the fair value of the leased asset or the present value of the minimum lease payments. Capitalized leased assets are amortized over the shorter of the estimated useful life of the assets and the lease term. Operating lease payments are recognized as an expense in the income statement on a straight line basis over the lease term.

(p): Recent Pronouncements

The Company has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the Company.

•: On January 1, 2015, Harvest will be required to adopt IFRS 9, "Financial Instruments", which is the result of the first phase of the IASB's project to replace IAS 39, "Financial Instruments: Recognition and Measurement". The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. Restatement of comparative period financial statements is not required upon initial application; however, modified disclosures on transition from the classification and measurement requirements of IAS 39 to IFRS 9 are required. Harvest is in the process of determining the potential impact of the adoption of this new standard.

F-23

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

•

In May 2011, the IASB issued the following new standards, which are effective for annual periods beginning on or after January 1, 2013:

•: IFRS 10, "Consolidated Financial Statements", replaces the consolidation requirements in SIC-12, "Consolidation—Special Purpose Entities" and a portion of IAS 27. IFRS 10 builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company and provides additional guidance to assist in the determination of control where this is difficult to assess. IFRS 10 requires retrospective application and early adoption is permitted.
•: IFRS 11, "Joint Arrangements", focuses on the rights and obligations of the joint arrangement, rather than its legal form (as is currently the case) and requires a single method to account for interests in jointly controlled entities (equity method). This standard requires retrospective application and early adoption is permitted.
•: IFRS 12, "Disclosure of Interest in Other Entities", is a comprehensive standard on disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, structure entities and other off balance sheet interests. IFRS 12 requires retrospective application and early adoption is permitted.
•: IFRS 13, "Fair Value Measurement", provides a consistent definition of fair value, establishes a single framework for determining fair value and introduces requirements for disclosures related to fair value measurement. IFRS 13 applies prospectively from the beginning of the annual period in which the standard is adopted. Early adoption is permitted.

Harvest is assessing the potential financial statement impact from adopting these new standards.

•: On June 16, 2011, the IASB issued an amendment to IAS 19, "Employee Benefits", which changes the recognition and measurement of defined benefit pension expense and termination benefits and expands disclosure requirements for all employee benefit plans. The new standard is required to be adopted for periods beginning on or after January 1, 2013. Harvest is currently assessing the financial statement impact of the new standard.
•: The IASB issued an amendment to IAS 1, "Presentation of Financial Statements" on June 16, 2011, which requires separating items presented in other comprehensive income between those that are recycled to income and those that are not. The standard is required to be adopted for periods beginning on or after July 1, 2012. The adoption of this standard should not have a material impact on the Company's consolidated financial statements.
•: In December 2011, the IASB issued amendments to IFRS 7 "Financial Instruments: Disclosures" and IAS 32, "Financial Instruments: Presentation" to clarify the current offsetting model and develop common disclosure requirements. Amendments to IFRS 7 are effective for annual periods beginning on or after January 1, 2013. Retrospective application is required and early adoption is permitted. Amendments to IAS 32 are

F-24

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

2. Basis of Presentation and Significant Accounting Policies (Continued)

effective for annual periods beginning on or after January 1, 2014. Retrospective application is required. Harvest is currently assessing the financial statement impact of the new standard.

3. Acquisitions

(a): Hunt Acquisition

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 $511.0 million. KNOC provided $505.4 million of equity to fund the acquisition and acquisition costs were $1.3 million (2010—$0.1 million) for the year ended December 31, 2011. An additional $25 million is payable to Hunt in the event that Canadian natural gas prices exceed certain pre-determined levels in 2012. This potential payable is considered contingent consideration and is required to be fair valued. Based on forecast gas prices, the probability of incurring this payment was assessed as low; as such no fair value was assigned on the allocation of consideration transferred. The Company's assessment of this contingent liability remained the same at December 31, 2011 whereby no provision was recorded.

Hunt reimbursed Harvest for costs associated with restoring production as well as the lost revenues net of operating costs relating to certain properties between October 1, 2010 and April 3, 2011, when production was resumed. A portion of the reimbursement could have reverted to Hunt if the future net revenue earned by Harvest during the six months after April 3, 2011 exceeded the reimbursed amount. Subsequent to the six-month period, it was agreed that no refund of the reimbursement was necessary.

The acquisition was accounted for as a business combination. The fair values of identifiable assets and liabilities, including interim adjustments as at the date of acquisition were:


Property, plant and equipment	$	530,946
Evaluation and exploration assets		18,627
Decommissioning liabilities		(38,030	)
Other liabilities		(500	)

Cash consideration	$	511,043

The final review of the fair value of the purchase price allocation was completed at December 31, 2011.

From the date of acquisition, the Hunt assets have contributed $133.0 million of revenue and $96.6 million to Harvest's earnings before depletion and income tax in 2011. If the acquisition had been completed on the first day of 2011, Harvest's revenues for the year ended December 31, 2011 would have been $14.6 million higher and the earnings before depletion and income tax would have been $7.4 million higher.

F-25

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

3. Acquisitions (Continued)

(b): Petroleum and Natural Gas Assets

On September 30, 2010, Harvest acquired certain petroleum and natural gas assets including the remaining 40% interest in an operating partnership for total cash consideration of $144.2 million. The acquisition was accounted for as a business combination and acquisition costs were $0.2 million (2010—$0.3 million) for the year ended December 31, 2011. The fair values of identifiable assets and liabilities as at the date of acquisition were:


Property, plant and equipment	$	166,966
Evaluation and exploration assets		587
Decommissioning liabilities		(18,358	)
Deferred tax liabilities		(5,032	)

Total cash consideration	$	144,163

The assets have contributed $8.4 million of revenue and $6.0 million to Harvest's earnings before depletion and income tax from the date of acquisition to December 31, 2010. If the acquisition had been completed on the first day of 2010, Harvest's revenues for the year would have been $27.1 million higher and the earnings before depletion and income tax would have been $16.6 million higher.

The final statement of adjustments was received in 2011 and as a result, the property, plant and equipment balance decreased as compared to the provisional value by an immaterial amount. Therefore the 2010 comparative financial statements were not restated. The decrease in depletion, depreciation and amortization as a result of the revised property, plant and equipment balance was also not material.

4. Cash and Cash Equivalents

	December 31, 2011		December 31, 2010		January 1, 2010

Cash on hand and at banks	$	6,607	$	7,906	$	—
Short-term deposits		—		11,000		—

	$	6,607	$	18,906	$	—

5. Inventories

	December 31, 2011		December 31, 2010		January 1, 2010

Petroleum products
Upstream—pipeline fill	$	1,325	$	1,010	$	1,183
Downstream		56,298		70,586		81,240

Total petroleum product inventory		57,623		71,596		82,423
Parts and supplies		3,329		3,921		4,396

	$	60,952	$	75,517	$	86,819

F-26

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

5. Inventories (Continued)

For the year ended December 31, 2011, Harvest recognized net inventory impairments of $2.5 million (2010—$2.4 Million) in its Downstream operations. Such write-downs and recoveries amounts are included as costs in "purchased products for processing and resale" in the consolidated statements of comprehensive loss.

6. Exploration and Evaluation Assets ("E&E")


As at January 1, 2010	$	36,034
Additions		46,997
Acquisition		—
Dispositions		(971	)
Unsuccessful exploration and evaluation costs		(2,858	)
Transfer to property, plant and equipment		(19,648	)

As at December 31, 2010	$	59,554
Additions		50,883
Acquisition		18,627
Dispositions		(717	)
Unsuccessful exploration & evaluation costs		(17,757	)
Transfer to property, plant & equipment		(36,073	)

As at December 31, 2011	$	74,517

	Year Ended December 31

	2011		2010
Pre-licensing costs	$	532	$	442
Unsuccessful E&E costs		17,757		2,858

E&E expense	$	18,289	$	3,300

F-27

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

7. Property, Plant and Equipment ("PP&E")

	Upstream			Downstream			Total

Cost:
As at January 1, 2010	$	2,940,877		$	1,113,742		$	4,054,619
Additions		356,788			71,297			428,085
Acquisitions		574,941			—			574,941
Change in decommissioning liabilities		71,838			2,407			74,245
Transfers from E&E		19,648			—			19,648
Exchange adjustment		—			(63,037	)		(63,037	)
Disposals		63			(49	)		14
Investment tax credits		—			(42,475	)		(42,475	)

As at December 31, 2010		3,964,155			1,081,885			5,046,040
Additions		682,497			284,244			966,741
Acquisitions		533,963			—			533,963
Change in decommissioning liabilities		(18,245	)		3,767			(14,478	)
Transfers from E&E		36,073			—			36,073
Exchange adjustment		—			36,928			36,928
Disposals		(882	)		(18,031	)		(18,913	)
Investment tax credits		—			(10,187	)		(10,187	)

As at December 31, 2011	$	5,197,561		$	1,378,606		$	6,576,167

Accumulated depletion, amortization, depreciation and impairment losses:
As at January 1, 2010	$	—		$	—		$	—
Depreciation, depletion and amortization		470,641			83,091			553,732
Impairment		13,661			—			13,661
Exchange adjustment		—			(4,589	)		(4,589	)

As at December 31, 2010		484,302			78,502			562,804
Depreciation, depletion and amortization		535,384			91,006			626,390
Disposals		—			(18,031	)		(18,031	)
Exchange adjustment		—			4,617			4,617

As at December 31, 2011	$	1,019,686		$	156,094		$	1,175,780

Net Book Value:
As at December 31, 2011	$	4,177,875		$	1,222,512		$	5,400,387
As at December 31, 2010	$	3,479,853		$	1,003,383		$	4,483,236
As at January 1, 2010	$	2,940,877		$	1,113,742		$	4,054,619

General and administrative costs of $22.2 million (2010—$14.6 million) and interest of $4.5 million (2010—$0.4 million) have been capitalized in Upstream PP&E for the year ended December 31, 2011. Interest of $4.1 million (2010—$nil) have been capitalized in Downstream PP&E during the year ended December 31, 2011. Capitalized interest measured using a weighted average interest rate of 6.65% (2010—6.50%) arose from the BlackGold oil sands project ("BlackGold") and Downstream debottlenecking project.

F-28

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

7. Property, Plant and Equipment ("PP&E") (Continued)

At December 31, 2011 the following costs were excluded from the asset base subject to depreciation, depletion and amortization: Downstream major parts inventory of $7.5 million (2010—$6.8 million), Downstream assets under construction of $102.5 million (2010—$68.8 million) and Upstream BlackGold oil sands project assets of $497.2 million (2010—$385.3 million). For the year ended December 31, 2011, an investment tax credit of $10.2 million (2010—$42.5 million) was applied against Downstream assets.

During the year ended December 31, 2011, Harvest recorded an impairment loss of $nil to PP&E. An increase of 50 bps in the pre-tax discount rate would result in an impairment of $38.4 million, while a 10% decrease in gross margin would result in an impairment of $222.3 million in Downstream PP&E. During the year ended December 31, 2010, Harvest recorded a $13.7 million impairment related to certain Upstream properties in Southern Alberta to reflect declining forecasted gas prices which resulted in lower estimated future cash flows using a pre-tax discount rate of 12%. The recoverable amount is based on the assets' value-in-use, estimated using the net present value of the future cash flow.

F-29

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

8. Goodwill

Goodwill of $404.9 million (2010—$404.9 million) has been allocated to the Upstream operating segment. In assessing whether goodwill has been impaired, the carrying amount (including goodwill) is compared with the recoverable amount of the Upstream operating segment. At December 31, 2011, the recoverable amount was determined by using the expected cash flows generated from the projected oil and natural gas production profiles up to the expected dates of cessation of production. The key assumptions required to estimate the recoverable amount are the oil and natural gas prices, production volumes and the discount rate. The values assigned to the key assumptions represent management's assessment of future trends in the oil and gas industry based on both external and internal sources. A pre-tax discount rate of 10% (and the following forward commodity price estimates) were used in the goodwill impairment calculation:

Year

2012	97.50	3.50	0.975
2013	97.50	4.20	0.975
2014	100.00	4.70	0.975
2015	100.80	5.10	0.975
2016	101.70	5.55	0.975
2017	102.70	5.90	0.975
2018	103.60	6.25	0.975
2019	104.50	6.45	0.975
2020	105.40	6.70	0.975
2021	107.60	6.85	0.975
2022	109.70	6.95	0.975
2023	111.90	7.05	0.975
2024	114.10	7.20	0.975
2025	116.40	7.40	0.975
2026	118.80	7.55	0.975
Thereafter⁽²⁾	+2%/year	+2%/year	0.975

(1): Source: McDaniel & Associates Consultants Ltd, effective January 1, 2012.
(2): Percentage change represents the change in each year after 2026 to the end of the reserve life.

Management believes that currently, there is no reasonably possible change in the key assumptions that would cause the carrying amount of the Upstream operating segment to exceed the recoverable amount.

9. Decommissioning Liabilities

Harvest's decommissioning liabilities arise from its net ownership interests in petroleum and natural gas assets including well sites, gathering systems, pipeline, processing facilities and Downstream refining and marketing assets and its legal obligations to retire and reclaim them. Harvest estimates the total undiscounted amount of cash flows required to settle its decommissioning liabilities to be approximately $1.4 billion at December 31, 2011 (2010—

F-30

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

9. Decommissioning Liabilities (Continued)

$1.2 billion), which will be incurred between 2012 and 2072. A risk-free discount rate of 3.0% (2010—3.4%) and inflation rate of 1.7% (2010—1.7%) were used to calculate the fair value of the decommissioning liabilities. Revisions in decommissioning liabilities in 2011 resulted from changes in the discount rates, estimated abandonment dates and estimated costs, while 2010 revisions resulted from a change in the discount rate. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning work required, which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain. A reconciliation of the decommissioning liabilities is provided below:

	Upstream			Downstream		Total

Balance at January 1, 2010	$	559,810		$	7,676	$	567,486
Liabilities assumed on acquisitions		22,393			—		22,393
Liabilities incurred		9,316			—		9,316
Settled during the period		(20,257	)		—		(20,257	)
Revisions (change in estimate)		58,989			2,407		61,396
Accretion		22,342			343		22,685

Balance at December 31, 2010		652,593			10,426		663,019
Liabilities assumed on acquisitions		38,030			—		38,030
Liabilities incurred		28,382			—		28,382
Settled during the period		(22,110	)		—		(22,110	)
Revisions (change in estimate)		(46,627	)		3,767		(42,860	)
Disposals		(708	)		—		(708	)
Accretion		23,151			400		23,551

Balance at December 31, 2011	$	672,711		$	14,593	$	687,304

Current portion of decommissioning liabilities	$	12,782		$	—	$	12,782
Non-current portion of decommissioning liabilities		659,929			14,593		674,522

Balance at December 31, 2011	$	672,711		$	14,593	$	687,304

10. Bank Loan

At the time of the purchase of Harvest Energy Trust ("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. At January 1, 2010, $428 million was drawn under the credit facility. 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.

On April 29, 2011, Harvest further extended the term of its credit facility by 2 years to April 30, 2015. Harvest pays a floating interest rate under its credit facility, which is determined by a grid based on the Company's secured debt (excluding 6⁷/8% senior notes and convertible debentures) to earnings before interest, taxes, depletion, amortization and other non-cash items ("EBITDA"). The

F-31

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

10. Bank Loan (Continued)

minimum rate charged on the credit facility was amended on April 29, 2011, decreasing the floating rate from 200 bps to 175 bps over bankers' acceptance rates, to the extent that Harvest's secured debt to EBITDA ratio remains below or equal to one.

On December 16, 2011, the credit facility was amended to increase the capacity of the facility from $500 million to $800 million and the minimum rate charged on the credit facility decreased further from 175 bps to 160 bps over bankers' acceptance rates. The determination of the financial covenants remains unchanged and is disclosed below. At December 31, 2011, Harvest had $358.9 million drawn from the $800 million available under the credit facility (2010—$14 million).

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 the shareholder 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 6⁷/8% senior notes and convertible debentures) to its EBITDA. In addition to the availability under this facility being limited by the borrowing base covenant of the 6⁷/8% senior notes described in note 11, availability is subject to the following quarterly financial covenants as defined in the credit facility agreement:



Secured debt⁽¹⁾ to Annualized EBITDA	3.0 to 1.0 or less	0.73	0.06
Total debt⁽²⁾ to Annualized EBITDA	3.5 to 1.0 or less	2.72	2.39
Secured debt⁽¹⁾ to Capitalization⁽³⁾	50% or less	10%	1%
Total debt⁽²⁾ to Capitalization⁽³⁾	55% or less	36%	31%

(1): Secured debt consists of letters of credit of $8.7 million (2010—$2.5 million), bank loan of $355.6 million (2010—$11.4 million) and guarantees of $92.1 million (2010—$15.5 million) at December 31, 2011.
(2): Total debt consists of secured debt, convertible debentures and senior notes.
(3): Capitalization consists of total debt and shareholder's equity less equity for BlackGold of $459.9 million at December 31, 2010 and 2011.

For the year ended December 31, 2011 interest charges on the bank loan aggregated to $5.7 million (2010—$5.7 million) reflecting an effective interest rate of 3.0% (2010—3.7%).

11. Senior Notes

On October 4, 2010, Harvest issued US$500 million of 6⁷/8% senior notes for net cash proceeds of US$484.6 million. The senior notes are unsecured with interest payable semi-annually on April 1 and October 1 and mature on October 1, 2017. The senior notes are unconditionally guaranteed by Harvest and all of its wholly-owned subsidiaries that guarantee the revolving credit facility and

F-32

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

11. Senior Notes (Continued)

every future restricted subsidiary that guarantees certain debt. 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, plus 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 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 indebtedness under the credit facilities may be limited by the borrowing base covenant and certain other specific circumstances. The covenant restricts Harvest's incurrence of indebtedness under the credit facility in an aggregate principal amount not to exceed the greater of $1.0 billion and 15% of total assets. In addition, the covenants of the senior notes restrict the amount of dividends Harvest can pay to shareholders; no dividends have been paid during the year ended December 31, 2011.

In 2010, Harvest redeemed the US$250 million of 7⁷/8% senior notes for total consideration of $256.9 million.

12. Convertible Debentures

Harvest has four series of convertible unsecured subordinated debentures outstanding. Interest on the debentures is payable semi-annually in arrears in equal installments on dates prescribed by each series.

As a result of KNOC'S acquisition of Harvest Energy Trust, in 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. 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. After the second redemption period, the debentures are redeemable at par. Any redemption will include accrued and unpaid interest at such time.

The following is a summary of the four series of convertible debentures:

Series		Conversion price/share

D	6.40%	$	46.00	Oct. 31, 2012	Nov. 1/08 – Oct. 31/09	Nov. 1/09 – Oct. 31/10
E	7.25%	$	32.20	Sept. 30, 2013	Oct. 1/09 – Sept. 30/10	Oct. 1/10 – Sept. 30/11
F	7.25%	$	27.25	Feb. 28, 2014	Mar. 1/10 – Feb. 28/11	Mar. 1/11 – Feb. 29/12
G	7.50%	$	27.40	May 31, 2015	Jun. 1/11 – May 31/12	Jun. 1/12 – May 31/13

F-33

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

12. Convertible Debentures (Continued)

The following table summarizes the face value, carrying amount and fair value of the convertible debentures:

	December 31, 2011						December 31, 2010						January 1, 2010

Series	Face Value		Carrying Amount		Fair Value		Face Value		Carrying Amount		Fair Value		Face Value		Carrying Amount		Fair Value
B	$	—	$	—	$	—	$	—	$	—	$	—	$	37,062	$	37,562	$	37,562
D		106,796		107,146		108,184		106,796		107,544		108,291		174,626		176,460		176,460
E		330,548		333,346		337,159		330,548		334,804		339,142		379,256		385,703		385,703
F		60,050		60,616		61,551		60,050		60,851		61,912		73,222		74,467		74,467
G		236,579		240,959		245,451		236,579		242,058		248,763		250,000		256,875		256,875

	$	733,973	$	742,067	$	752,345	$	733,973	$	745,257	$	758,108	$	914,166	$	931,067	$	931,067

The KNOC acquisition of the Trust triggered the "change of control" provision included within the convertible debentures' indentures, which 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 4, 2010 all of the offers had expired. The following redemptions were made:

•: Series B—$13.3 million principal amount tendered, with the remaining principal balance of $23.8 million maturing on December 31, 2010
•: Series D—$67.8 million principal amount tendered leaving a principal balance of $106.8 million outstanding
•: Series E—$48.7 million principal amount tendered leaving a principal balance of $330.5 million outstanding
•: Series F—$13.2 million principal amount tendered leaving a principal balance of $60.1 million outstanding
•: Series G—$13.4 million principal amount tendered leaving a principal balance of $236.6 million outstanding

F-34

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

13. Shareholder's Capital

(a): Authorized

The authorized capital consists of an unlimited number of common shares with no par value and an unlimited number of preferred shares issuable in series.

(b): Number of Common Shares Issued


	Outstanding at January 1, 2010			242,268,802
	Issued to KNOC at $10.00 per share to fund debt repayment			46,567,852
	Issued to KNOC at $10.00 per share for BlackGold consideration(Note 26)			37,416,913
	Issued to KNOC at $10.00 per share for BlackGold project development			4,700,000
	Issued to KNOC at $10.00 per share for BlackGold project development			3,868,600
	Issued to KNOC at $10.00 per share for KNOC Global Technology and Research centre			712,880

	Outstanding at December 31, 2010			335,535,047

	Issued to KNOC at $10.00 per share for Hunt acquisition			50,543,602

	Outstanding at December 31, 2011			386,078,649

14. Capital Structure

Harvest considers its capital structure to be its credit facility, senior notes, convertible debentures and shareholder's equity.

	December 31, 2011		December 31, 2010		January 1, 2010

Bank loan⁽¹⁾	$	358,885	$	14,000	$	428,017
6⁷/8% senior notes⁽¹⁾⁽²⁾		508,500		497,300		—
7⁷/8% senior notes⁽¹⁾⁽²⁾		—		—		262,750
Principal amount of convertible⁽¹⁾ Debentures		733,973		733,973		914,166

		1,601,358		1,245,273		1,604,933
Shareholder's equity		3,453,644		3,016,855		2,219,513

	$	5,055,002	$	4,262,128	$	3,824,446

(1): Excludes deferred financing costs.
(2): Face value converted at the period end exchange rate.

F-35

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

14. Capital Structure (Continued)

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 financial ratios: bank loan to twelve month trailing EBITDA 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, 2011.

15. Revenue and Other Income

	Year Ended December 31

	2011			2010
Crude oil and natural gas sales, net of royalty	$	1,100,838		$	852,247
Refinery products sales		3,239,455			3,105,957
Effective portion of realized crude oil hedges		(9,424	)		—

	$	4,330,869		$	3,958,204

16. Operating and General and Administrative ("G&A") Expenses

	Year Ended December 31

	2011						2010
Operating expenses	Upstream		Downstream		Total		Upstream		Downstream		Total
Power and purchased energy	$	83,092	$	117,275	$	200,367	$	59,106	$	106,126	$	165,232
Well servicing		61,592		—		61,592		50,427		—		50,427
Repairs and maintenance		60,038		20,407		80,445		43,720		22,341		66,061
Lease rentals and property taxes		34,728		—		34,728		30,637		—		30,637
Salaries and benefits		28,137		58,907		87,044		22,641		60,959		83,600
Professional and consultation fees		19,378		4,519		23,897		15,966		3,784		19,750
Chemicals		15,360		—		15,360		12,981		—		12,981
Processing fees		22,643		—		22,643		13,538		—		13,538
Trucking		13,261		—		13,261		9,645		—		9,645
Other		12,227		24,567		36,794		6,932		22,430		29,362

	$	350,456	$	225,675	$	576,131	$	265,593	$	215,640	$	481,233

F-36

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

16. Operating and General and Administrative ("G&A") Expenses (Continued)

	Year Ended December 31

General and administrative expenses	2011			2010
Salaries and benefits	$	59,543		$	44,545
Professional and consultation fees		7,864			8,387
Other		18,512			9,334
G&A capitalized and recovery		(23,351	)		(15,199	)

	$	62,568		$	47,067

17. Finance Costs

	Year Ended December 31

	2011			2010
Interest and other finance charges	$	94,216		$	78,520
Accretion of decommissioning liabilities		23,551			22,685
Less: capitalized interest		(8,640	)		(397	)

	$	109,127		$	100,808

18. Foreign Exchange

	Year Ended December 31

	2011			2010
Realized (gains) losses on foreign exchange	$	(6,541	)	$	(1,524	)
Unrealized (gains) losses on foreign exchange		2,555			(1,875	)

	$	(3,986	)	$	(3,399	)

F-37

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

19. Supplemental Cash Flow Information

	Year Ended December 31

	2011		2010
Source (use) of cash:
Accounts receivable and other	$	1,679	$	(35,269	)
Prepaid expenses (including long-term deposit)		42,223		(70,123	)
Inventories		14,565		11,302
Accounts payable		103,661		155,109

Net changes in non-cash working capital		162,128		61,019

Changes relating to operating activities		51,061		32,299
Changes relating to financing activities		—		1,952
Changes relating to investing activities		108,747		22,503
Add: Non-cash changes		2,320		4,265

	$	162,128	$	61,019

20. Income Taxes

	Year Ended December 31

	2011			2010
Current income tax expense (recovery)	$	53		$	(212	)
Deferred income tax ("DIT") recovery		(29,880	)		(65,097	)

	$	(29,827	)	$	(65,309	)

F-38

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

20. Income Taxes (Continued)

The income tax recovery varies from the amount that would be computed by applying the relevant Canadian income tax rates to reported losses before taxes as follows:

	Year Ended December 31

	2011			2010
Loss before income tax	$	(134,484	)	$	(146,472	)
Combined Canadian federal and provincial statutory income tax rate		28.08%			28.25%

Computed income tax recovery at statutory rates		(37,763	)		(41,378	)
Increased expense (recovery) resulting from the following:
Difference between current and expected tax rates		13,894			(12,862	)
Foreign exchange impact not recognized in income		7,848			(10,931	)
Amended returns and pool balances		4,946			—
Change in valuation allowance		(12,692	)		—
Non-deductible expenses		(3,499	)		(2,409	)
Other		(2,561	)		(212	)
Non-taxable portion of capital loss		—			2,483

Income tax recovery	$	(29,827	)	$	(65,309	)

The change in the applicable tax rate for the year ended December 31, 2011 from the previous year is due to a reduction in the federal component of the tax rate.

Movements in the DIT asset (liability) are as follows:

	PP&E			Decommissioning liabilities		Non-capital tax losses		Other			Total deferred asset (Liability)

At January 1, 2010	$	(574,644	)	$	144,867	$	289,647	$	(1,975	)	$	(142,105	)
Recognized in profit or loss		23,205			23,615		13,469		4,808			65,097
Acquired in business combination		(5,032	)		—		—		—			(5,032	)
Recognized in other comprehensive loss		—			—		—		2,530			2,530

At December 31, 2010	$	(556,471	)	$	168,482	$	303,116	$	5,363		$	(79,510	)⁽¹⁾

Recognized in profit or loss		(48,823	)		3,898		71,921		2,884			29,880
Recognized in other comprehensive loss		—			—		—		(5,277	)		(5,277	)

At December 31, 2011	$	(605,294	)	$	172,380	$	375,037	$	2,970		$	(54,907	)

(1): The net DIT liability at December 31, 2010 consists of a $1.6 million DIT asset and an $81.1 million DIT liability.

DIT assets are recognized to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax losses can be utilized. As at December 31, 2011, Harvest had approximately $1.6 billion of carry-forward tax

F-39

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

20. Income Taxes (Continued)

losses that would be available to offset against future taxable profit. A DIT asset has been recognized in respect of all of these losses, and is included in the net DIT liability of $54.9 million. The DIT asset related to the carry-forward losses has been recorded despite the fact that the Company has incurred losses before income tax in 2010 and 2011. The Company has tax planning opportunities available that could support full recognition of these losses as a DIT asset.

21. Post-Employment Benefits

The measurement of the accrued benefit obligation and annual expense for the defined benefit plans requires actuarial calculations and the following key assumptions.

	December 31, 2011				December 31, 2010				January 1, 2010

	Pension Plans		Other Benefit Plans		Pension Plans		Other Benefit Plans		Pension Plans		Other Benefit Plans
Discount rate		5.0%		5.0%		5.25%		5.25%		5.5%		5.5%
Expected long-term rate of return on plan assets		7.0%		—		7.0%		—		7.0%		—
Rate of compensation increase		3.5%		—		3.5%		—		3.5%		—
Employee contribution of pensionable income		6.0%		—		6.0%		—		6.0%		—
Annual rate of increase in covered health care benefits		—		8%		—		8%		—		9%

The defined benefit pension plan asset mix is as follows:



Bonds/fixed income securities	30%	32%	31%
Equity securities	70%	68%	69%

Total cash payments for employee future benefits, consisting of cash contributed by Harvest to the pension plans and other benefit plans was $3.6 million for the year ended December 31, 2011 (2010—$3.9 million); the expected contribution for the pension plans and other benefit plans in 2012 is $5.3 million.

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.

F-40

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

21. Post-Employment Benefits (Continued)

The defined benefit plans were subject to an actuarial valuation on December 31, 2011, and the next valuation report is due December 31, 2012.

	December 31, 2011									December 31, 2010

	Pension Plans			Other Benefit Plans			Total			Pension Plans			Other Benefit Plans			Total
Employee benefit obligation, beginning of period	$	63,791		$	7,901		$	71,692		$	56,476		$	7,047		$	63,523
Current service costs		2,466			285			2,751			2,189			291			2,480
Interest costs		3,507			423			3,930			3,258			397			3,655
Employee contributions		1,606			202			1,808			1,526			170			1,696
Actuarial gain (loss)		1,572			(137	)		1,435			2,250			423			2,673
Benefits paid		(2,123	)		(481	)		(2,604	)		(1,908	)		(427	)		(2,335	)

Employee benefit obligation, end of period	$	70,819		$	8,193		$	79,012		$	63,791		$	7,901		$	71,692
Fair value of plan assets, beginning of period	$	51,327		$	—		$	51,327		$	46,070		$	—		$	46,070
Expected return on plan assets		3,623			—			3,623			3,277			—			3,277
Actuarial loss		(4,678	)					(4,678	)		(1,243	)		—			(1,243	)
Employer contributions		3,299			279			3,578			3,605			257			3,862
Employee contributions		1,606			202			1,808			1,526			170			1,696
Benefits paid		(2,123	)		(481	)		(2,604	)		(1,908	)		(427	)		(2,335	)

Fair value of plan assets, end of period	$	53,054		$	—		$	53,054		$	51,327		$	—		$	51,327

Funded status—deficit	$	(17,765	)	$	(8,193	)	$	(25,958	)	$	(12,464	)	$	(7,901	)	$	(20,365	)

Experience adjustments arising on plan assets		(8.8	)%		—						(2.4	)%		—
Experience adjustments arising on plan liabilities		(2.2	)%		1.7%						(3.5	)%		(5.4	)%

The table below shows the components of the net benefit plan expense:

	Year Ended December 31

	2011								2010
	Pension Plans			Other Benefit Plans		Total			Pension Plans			Other Benefit Plans		Total
Current service cost	$	2,466		$	285	$	2,751		$	2,189		$	291	$	2,480
Interest costs		3,507			423		3,930			3,258			397		3,655
Expected return on assets		(3,623	)		—		(3,623	)		(3,277	)		—		(3,277	)

Net benefit plan expense	$	2,350		$	708	$	3,058		$	2,170		$	688	$	2,858

F-41

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

21. Post-Employment Benefits (Continued)

The actual loss on plan assets for the year ended December 31, 2011 was $1.1 million (December 31, 2010—a return of $2.0 million).

For the year ended December 31, 2011 the net benefit plan expense of $3.1 million (2010—$2.9 million) has been included in operating expenses in the statement of comprehensive loss. An actuarial loss of $4.9 million, net of tax of $1.2 million (2010—$3.2 million, net of tax of $0.7 million) has been included in other comprehensive income. The cumulative amount of actuarial loss included in accumulated other comprehensive loss as at December 31, 2011 is $8.1 million, net of tax of $1.9 million.

Under the pension regulations, North Atlantic is required to fund its defined benefit pension plan obligation within 5 to 15 years. The funding requirements are included in note 25.

A 1% change in the expected health care cost trend rate would have an immaterial annual impact on post-retirement benefit expense and projected benefit obligation as at December 31, 2011.

22. Accumulated Other Comprehensive Income (Loss)

	Foreign Currency Translation Adjustment			Gains (Losses) on Designated Cash Flow Hedges, Net of Tax			Actuarial Loss, Net of Tax			Total

Balance at January 1, 2010	$	—		$	—		$	—		$	—
Losses on derivatives designated as cash flow hedges		—			(5,020	)		—			(5,020	)
Actuarial loss		—			—			(3,217	)		(3,217	)
Losses on foreign currency translation		(45,920	)		—			—			(45,920	)

Balance at December 31, 2010		(45,920	)		(5,020	)		(3,217	)		(54,157	)
Reclassification to net income of losses on cash flow hedges		—			7,050			—			7,050
Gains on derivatives as designated cash flow hedges		—			12,371			—			12,371
Actuarial loss		—			—			(4,891	)		(4,891	)
Gains on foreign currency translation		21,480			—			—			21,480

Balance at December 31, 2011	$	(24,440	)	$	14,401		$	(8,108	)	$	(18,147	)

F-42

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

22. Accumulated Other Comprehensive Income (Loss) (Continued)

The effective portion of the unrealized gain of $12.4 million net of tax of $4.2 million (2010—$5.0 million loss net of tax recovery of $1.8 million) was included in other comprehensive loss for the year ended December 31, 2011. The amount removed from accumulated other comprehensive loss and included in petroleum, natural gas, and refined product sales was a loss of $7.1 million, net of tax recovery of $2.4 million for the year ended December 31, 2011 (2010—$nil).

The Company expects that $14.4 million of gains reported in accumulated other comprehensive loss will be released to net income within the next 12 months.

23. Financial Instruments

(a): Fair Values

The carrying value and fair value of these financial instruments are disclosed below by financial instrument category:

	December 31, 2011				December 31, 2010				January 1, 2010

	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
Financial Assets
Loans and Receivables
Accounts receivable	$	212,252	$	212,252	$	213,931	$	213,931	$	178,662	$	178,662
Held for Trading
Cash and cash equivalents		6,607		6,607		18,906		18,906		—		—
Risk management contracts		20,162		20,162		1,007		1,007		—		—

Total Financial Assets	$	239,021	$	239,021	$	233,844	$	233,844	$	178,662	$	178,662

Financial Liabilities
Held for Trading
Risk management contracts	$	—	$	—	$	7,553	$	7,553	$	2,052	$	2,052
Measured at Amortized Cost
Accounts payable and accrued liabilities		464,148		464,148		360,487		360,487		205,378		205,378
Bank loan		355,575		358,885		11,379		14,000		428,017		428,017
6⁷/8% senior notes		495,674		523,119		482,389		507,246		—		—
7⁷/8% senior notes		—		—		—		—		265,377		265,377
Convertible debentures		742,067		752,345		745,257		758,108		931,067		931,067

Total Financial Liabilities	$	2,057,464	$	2,098,497	$	1,607,065	$	1,647,394	$	1,831,891	$	1,831,891

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 are mainly 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

F-43

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

23. Financial Instruments (Continued)

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 or the Company's own default risk. The changes in counterparty credit risk had no material effect on the hedge effectiveness assessment for derivatives designated in the hedging relationship 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, 2011. The fair value of the bank loan approximates the carrying value (excluding deferred financing charges) as the bank loan bears floating market rates. The carrying value of the bank loan includes $3.3 million of deferred financing charges at December 31, 2011 (2010—$2.6 million). Due to the short term maturities of accounts receivable 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 significance 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, 2011, there were no transfers among Levels 1, 2 and 3.

(b): Risk Management Contracts

The Company enters into crude oil and foreign exchange contracts to reduce the volatility of cash flows from some of its forecast sales. Harvest designates all of its crude oil derivative contracts and certain foreign exchange contracts as cash flow hedges. The effective portion of the unrealized gains and losses is included in other comprehensive income. The effective portion of the realized gains and losses is removed from accumulated other comprehensive income and included in petroleum, natural gas, and refined product sales (see note 22). The

F-44

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

23. Financial Instruments (Continued)

ineffective portion of the unrealized and realized gains and losses recognized in the consolidated income statement from these cash flow hedges is shown below for crude oil, together with the realized and unrealized (gains) losses on power and currency risk management contracts:

	Year Ended December 31

	2011											2010
	Power			Crude oil			Currency		Total			Power			Crude oil		Currency		Total
Realized (gains) losses	$	(7,730	)	$	1,730		$	—	$	(6,000	)	$	1,808		$	—	$	—	$	1,808
Unrealized (gains) losses		1,008			(1,754	)		—		(746	)		(3,060	)		702		—		(2,358	)

	$	(6,722	)	$	(24	)	$	—	$	(6,746	)	$	(1,252	)	$	702	$	—	$	(550	)

The following is a summary of Harvest's risk management contracts outstanding at December 31, 2011 and 2010:

Contracts Designated as Hedges

December 31, 2011

Contract Quantity	Type of Contract	Term	Contract Price	Fair Value
4,200 bbls/day	Crude oil price swap	2012	US $111.37/bbl	$	19,718
US $468/day	Foreign exchange swap	2012	$1.0236 Cdn/US		444

				$	20,162

(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, counterparty risk from 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

F-45

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

23. Financial Instruments (Continued)

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 off take agreement exposes Harvest to the credit risk of Macquarie Energy Canada Ltd. ("Macquarie") as all feedstock purchases and the majority of product sales are made with Macquarie. This credit risk is mitigated by the amounts owing to Macquarie for feedstock purchases that are offset against amounts receivable from Macquarie for product sales with the balance being net settled. The supply and off take agreement also requires both Harvest and Maquarie's parent, Macquarie Bank Ltd, to provide reciprocal guarantees of US$75 million to each other in order to mitigate the risk of either counter party being unable to settle a net payable amount. At December 31, 2011, Harvest is in a net payable position with Macquarie and 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, 2011 is the carrying value of accounts receivable. The table below provides an analysis of Harvest's current and past due but not impaired receivables.

	December 31, 2011

			Overdue AR
	Current AR		<30 days		>30 days, <60 days		>60 days, <90 days		>90 days
Upstream accounts receivable	$	146,164	$	1,286	$	556	$	1,168	$	4,000
Downstream accounts receivable		50,660		6,155		1,702		206		355

	$	196,824	$	7,441	$	2,258	$	1,374	$	4,355	⁽¹⁾

(1): Net of $3.3 million of allowance for doubtful accounts.

F-46

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

23. Financial Instruments (Continued)

(ii): Liquidity Risk

Harvest is exposed to liquidity risk due to the Company's borrowings under its credit facility, convertible debentures and 6⁷/8% 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 and eliminating the requirement for margin calls and the pledging of collateral.

In addition to the guarantee provided to Macquarie at December 31, 2011, Harvest has also provided guarantees of $15.8 million for Downstream product purchases.

The following table provides an analysis of Harvest's financial liability maturities based on the remaining terms of its liabilities as at December 31, 2011 and includes the related interest charges:

	December 31, 2011

	<1 year		>1 year <3 years		>3 years <5 years		>5 years		Total
Accounts payable and accrued liabilities	$	464,148	$	—	$	—	$	—	$	464,148
Bank loan and interest		5,643		11,287		360,756		—		377,686
Convertible debentures and interest		158,554		449,138		243,972		—		851,664
6⁷/8% senior notes and interest		34,959		69,919		69,919		534,720		709,517
Guarantees⁽¹⁾		47,004		—		—		—		47,004

	$	710,308	$	530,344	$	674,647	$	534,720	$	2,450,019

(1): Amounts are net of the related payables and receivables to and from counterparties.

(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.

F-47

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

23. Financial Instruments (Continued)

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. Harvest's convertible debentures and 6⁷/8% 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.

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 6⁷/8% 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's Downstream operations operate 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. Harvest is also exposed to currency exchange rate risk on its net investment in its Downstream operations. 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.

	Increase (decrease) in Net Income			Increase (decrease) in Other Comprehensive Income

U.S. Dollar Exchange Rate—10% increase	$	(19,870	)	$	(34,754	)
U.S. Dollar Exchange Rate—10% decrease	$	19,870		$	34,754

(1): The sensitivity to net income and other comprehensive income is done independently.

F-48

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

23. Financial Instruments (Continued)

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 protect a portion of the Company's future cash flows and net income against unfavorable movements in commodity prices. These contracts are recorded on the consolidated statement of financial position 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, the pre-tax impact would be as follows:

	December 31, 2011

	Increase (decrease) in Net Income			Increase (decrease) in Other Comprehensive Income
Forward price of crude oil—10% increase	$	(1,020	)	$	(18,517	)
Forward price of crude oil—10% decrease	$	621		$	11,390

F-49

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

24. 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.

	Year Ended December 31

	Downstream						Upstream						Total
	2011			2010			2011			2010			2011			2010
Petroleum, natural gas and refined products sales	$	3,239,455		$	3,105,957		$	1,286,866		$	1,007,004		$	4,526,321		$	4,112,961
Royalty		—			—			(195,452	)		(154,757	)		(195,452	)		(154,757	)

Revenues		3,239,455			3,105,957			1,091,414			852,247			4,330,869			3,958,204
Expenses
Purchased products for resale and processing		3,055,236			2,893,805			—			—			3,055,236			2,893,805
Operating		225,675			215,640			350,456			265,593			576,131			481,233
Transportation and marketing		6,293			6,366			29,626			9,394			35,919			15,760
General and administrative		1,764			1,764			60,804			45,303			62,568			47,067
Exploration and evaluation		—			—			18,289			3,300			18,289			3,300
Depletion, depreciation and amortization		91,006			83,091			535,692			470,641			626,698			553,732
Gains on disposition of PP&E		—			—			(7,883	)		(741	)		(7,883	)		(741	)
Risk management contracts gains		—			—			(6,746	)		(550	)		(6,746	)		(550	)
Impairment on PP&E		—			—			—			13,661			—			13,661

		(140,519	)		(94,709	)		111,176			45,646			(29,343	)		(49,063	)
Finance costs														109,127			100,808
Foreign exchange gains														(3,986	)		(3,399	)

Loss before income tax														(134,484	)		(146,472	)
Income tax recovery														(29,827	)		(65,309	)

Net loss													$	(104,657	)	$	(81,163	)

Capital Expenditures
Business acquisition	$	—		$	—		$	509,829		$	145,144		$	509,829		$	145,144
Additions to PP&E		284,244			71,234			682,497			356,851			966,741			428,085
Additions to E&E		—			—			50,883			46,997			50,883			46,997
Additions to other long term asset		—			—			7,413			—			7,413			—
Property acquisitions (dispositions), net		—			—			(4,474	)		30,513			(4,474	)		30,513

Total expenditures	$	284,244		$	71,234		$	1,246,148		$	579,505		$	1,530,392		$	650,739

(1): Of the total Downstream revenue, two customers represent sales of $1.5 billion and $586 million for the year ended December 31, 2011 (2010—$2 billion and $145 million). No other single customer within either segment represents greater than 10% of Harvest's total revenue.
(2): There is no intersegment activity.

F-50

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

24. Segment Information (Continued)

	Total Assets		PP&E		E&E		Other Long Term Assets		Goodwill

December 31, 2011
Downstream	$	1,408,112	$	1,222,512	$	—	$	—	$	—
Upstream		4,876,258		4,177,875		74,517		7,105		404,943

Total	$	6,284,370	$	5,400,387	$	74,517	$	7,105	$	404,943

December 31, 2010
Downstream	$	1,211,367	$	1,003,384	$	—	$	—	$	—
Upstream		4,177,373		3,479,852		59,554		—		404,943

Total	$	5,388,740	$	4,483,236	$	59,554	$	—	$	404,943

January 1, 2010
Downstream	$	1,273,882	$	1,113,742	$	—	$	—	$	—
Upstream		3,504,923		2,940,877		36,034				404,943

Total	$	4,778,805	$	4,054,619	$	36,034	$	—	$	404,943

25. 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, 2011:

Harvest entered into two contracts in relation to the engineering, procurement and construction ("EPC") of the production and processing facilities required for its BlackGold oil sands project in 2010 for a total contracted cost of $311 million. Harvest provided a cash deposit of $31.1 million in 2010, of which $24.9 million (2010—$30.6 million) remains at December 31, 2011 to be applied to future payments. The remaining balances of the two contracts are included in the contractual obligation and commitment table below.

The Downstream operations have a supply and offtake agreement ("SOA") with Macquarie Energy Canada Ltd. ("Macquarie") for a primary term to October 31, 2012. This agreement provides that the ownership of substantially all crude oil feedstock and refined product inventory at the refinery be retained by Macquarie and that Macquarie has 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. As such, as at December 31, 2011, Downstream had

F-51

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

25. Commitments and Contingencies (Continued)

commitments totaling approximately $776 million in respect of future crude oil feedstock purchases from Macquarie.

The following is a summary of Harvest's contractual obligations and commitments as at December 31, 2011:

	Payments Due by Period

	1 year		2-3 years		4-5 years		After 5 years		Total
Debt repayments⁽¹⁾	$	106,796	$	390,598	$	595,464	$	508,500	$	1,601,358
Debt interest payments⁽¹⁾		92,360		139,745		79,182		26,220		337,507
Purchase commitments⁽²⁾		207,207		48,409		1,143		—		256,759
Operating leases		9,368		15,267		2,187		564		27,386
Transportation agreements⁽³⁾		13,936		22,606		9,680		317		46,539
Feedstock and other purchase commitments⁽⁴⁾		776,092		—		—		—		776,092
Employee benefits⁽⁵⁾		4,534		7,828		4,944		3,837		21,143
Decommissioning liabilities⁽⁶⁾		12,782		58,989		33,805		1,343,584		1,449,160

Total	$	1,223,075	$	683,442	$	726,405	$	1,883,022	$	4,515,944

(1): Assumes constant foreign exchange rate.
(2): Relates to drilling commitments, AFE commitments, BlackGold oil sands project commitment and Downstream capital commitments.
(3): Relates to firm transportation commitments.
(4): Includes commitments to purchase refinery crude stock and refined products for resale under the SOA with Macquarie.
(5): Relates to the expected contributions to employee benefit plans and long-term incentive plan payments.
(6): Represents the undiscounted obligation by period.

26. Related Party Transactions

Harvest's has a Global Technology and Research Centre ("GTRC"), is used as a training facility for KNOC personnel. For the year ended December 31, 2011, Harvest billed KNOC and certain subsidiaries for a total of $1.6 million (2010—$0.2 million) primarily related to technical services provided by the GTRC. As at December 31, 2011, $1.1 million (2010—$0.1 million) remained outstanding from KNOC in accounts receivable. KNOC billed Harvest $0.6 million (2010—$ nil) for reimbursement to KNOC for secondee salaries paid by KNOC on behalf of Harvest for the year ended December 31, 2011. As at December 31, 2011, $0.6 million (2010—$nil) remains outstanding in accounts payable.

As at September 30, 2011, North Atlantic had committed to purchase $322.5 million of crude feedstock from KNOC, which Macquarie has taken over under the SOA.

On August 6, 2010, Harvest acquired the BlackGold oil sands project from KNOC for $374.2 million, representing the fair value of the oil and gas assets acquired. The acquisition was

F-52

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

26. Related Party Transactions (Continued)

paid with the issuance of shares to KNOC. The following amounts were added to Harvest's statement of financial position at August 6, 2010 as a result of this transaction:


Current assets	$	500
Property, plant and equipment		374,182
Long-term liabilities		(10	)
Decommissioning liabilities		(503	)

Shareholder's capital	$	(374,169	)

Directors and Key Management Personnel Remuneration

Key management personnel includes the Company's officers and other members of the executive management team. Included in the following table is remuneration to 5 (2010—9) independent directors and 15 (2010—14) key management personnel for the year ended December 31, 2011.

	Year Ended December 31

	2011		2010
Salaries, wages and short-term employee benefits	$	4,630	$	5,248
Post-employment benefits		49		49
Other long-term benefits		961		989

	$	5,640	$	6,286

27. First Time Adoption of IFRS

IFRS 1 "First-time Adoption of International Financial Reporting Standards" establishes the transitional requirements for the preparation of financial statements upon first time adoption of IFRS. IFRS 1 generally requires an entity to comply with IFRS effective at the reporting date and to apply the standards retrospectively to the opening balance sheet, the comparative period and the reporting period. The standard allows certain optional exceptions from full retrospective application and other elections on transition, which the Company has applied as follows:

Business Combinations Exemption

The Company has applied the business combinations exemption in IFRS 1. It has not restated business combinations that took place prior to the January 1, 2010 transition date ("Transition Date").

Deemed Cost Election for Oil and Gas Assets

Under Canadian GAAP, the Company accounted for its oil and gas properties in one cost centre using full cost accounting. The Company elected to apply the exemption in IFRS 1 available to full

F-53

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

27. First Time Adoption of IFRS (Continued)

cost oil and gas entities to its Upstream PP&E and measure its oil and gas properties at the Transition Date on the following basis:

•: E&E assets at the amount determined under Canadian GAAP; and
•: the remainder allocated to the underlying PP&E assets on a pro rata basis using proved and probable reserve values discounted at 10% at the Transition Date.

Fair Value as Deemed Cost Exemption

The Company elected to use the fair value as deemed cost exemption on its Downstream PP&E at the Transition Date.

Lease Exemption

The Company has elected to carry forward assessments made under Canadian GAAP for arrangements containing leases. The assessment of arrangements containing leases results in the same outcome under IAS 17 and IFRIC 4 "Determining whether an Arrangement contains a Lease".

Decommissioning Liabilities

Harvest has applied the deemed cost election for oil and gas assets under IFRS 1 and as such decommissioning liabilities at the Transition Date have been measured in accordance with IAS 37, "Provisions, Contingent Liabilities and Contingent Assets". The Company recognized directly in retained earnings any difference between the remeasured amount and the carrying amount of those liabilities at the Transition Date.

For the Downstream decommissioning liabilities, Harvest applied the exemption from full retrospective application of IAS 37 under IFRS 1. As such, the Company measured the decommissioning liabilities at the Transition Date, and recognized the corresponding charge in retained earnings.

Reconciliations of Canadian GAAP to IFRS

This is the first year that the Company has presented financial statements under IFRS; as such, the following reconciliations between Canadian GAAP and IFRS are included to provide an understanding of the material adjustments to the financial statements. The transition from Canadian GAAP to IFRS had no material effect upon previously reported cash flows. The following represents the reconciliations from Canadian GAAP to IFRS for the respective periods for shareholder's equity, net loss, and comprehensive loss.

F-54

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

27. First Time Adoption of IFRS (Continued)

Reconciliation of Shareholder's Equity

	Note	December 31, 2010			January 1, 2010

Shareholder's equity under Canadian GAAP		$	3,250,943		$	2,422,688
Decommissioning liabilities	a		(270,142	)		(272,258	)
Exploration and evaluation expenses	b
Impairment of exploration and evaluation asset			(2,858	)		—
Pre-licensing costs			(442	)		—
Impairment of PP&E	c		(13,661	)		—
Depletion, depreciation and amortization	d		(47,792	)		—
Dispositions	e		335			—
Acquisitions	f
Acquisition costs			(329	)		—
BlackGold asset transfer			8,467			—
Gain on acquisition			406			—
Post-employment benefits	g		(2,765	)		—
Deferred income taxes	h		94,283			69,083
Cumulative translation adjustments	i		440			—

Shareholder's equity under IFRS		$	3,016,885		$	2,219,513

Reconciliation of Net Loss

	Note	Year Ended December 31, 2010

Net loss under Canadian GAAP		$	(44,561	)
Decommissioning liabilities	a		2,556
Exploration and evaluation expenses	b
Unsuccessful exploration and evaluation costs			(2,858	)
Pre-licensing costs			(442	)
Impairment of PP&E	c		(13,661	)
Depletion, depreciation and amortization	d		(47,792	)
Dispositions	e		335
Acquisitions	f
Acquisition costs			(329	)
Gain on acquisition			406
Post-employment benefits	g		423
Deferred income taxes	h		25,200
Foreign currency translation	i		(440	)

Total differences			(36,602	)

Net loss under IFRS		$	(81,163	)

F-55

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

27. First Time Adoption of IFRS (Continued)

Reconciliation of Other Comprehensive Loss

	Note	Year Ended December 31, 2010

Other comprehensive loss under Canadian GAAP		$	(51,380	)
Post-employment benefits	g		(3,217	)
Cumulative translation adjustments	i		440

Total differences			(2,777	)
Other comprehensive loss under IFRS			(54,157	)
Net loss under IFRS			(81,163	)

Comprehensive loss under IFRS		$	(135,320	)

The following adjustments were made to the consolidated statement of cash flows for the year ended December 31, 2010.

		Cash used in Operating Activities			Cash used in Investing Activities

Exploration and evaluation expenses	b	$	(442	)	$	442
Acquisition cost	f		(329	)		329

There was no difference between Canadian GAAP and IFRS related to cash from financing activities.

(a): Decommissioning liabilities

The Company elected to apply the IFRS 1 exemption relating to decommissioning liabilities and re-measured decommissioning liabilities as at January 1, 2010 using the relevant risk-free rate. The exemption resulted in an increase of $272.3 million in decommissioning liabilities and a corresponding increase to deficit. This increase is mainly attributable to the change from the credit-adjusted risk-free rate to the risk-free rate of 4% for the Upstream decommissioning liabilities, resulting in an adjustment of $264.6 million. The recognition standards are different between Canadian GAAP and IFRS, which resulted in the recognition of the Downstream decommissioning liabilities of $7.7 million under IFRS on the Transition Date.

Under IFRS, the discount rate is adjusted each reporting period to reflect the current market risk-free rate. As at December 31, 2010, PP&E and the decommissioning liability were $68.8 million higher under IFRS.

As the opening decommissioning liabilities and the discount rates are different under IFRS, the accretion expense decreased by $2.6 million for the year ended December 31, 2010. There was minimal impact to the accretion due to the reduction of decommissioning liabilities resulting from the dispositions discussed under item (e).

F-56

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

27. First Time Adoption of IFRS (Continued)

(b): Exploration and evaluation costs

Unsuccessful exploration and evaluation costs

Under IFRS, Harvest capitalizes costs relating to exploration and evaluation activities until a project is determined to be successful or otherwise. If a project is deemed to be successful because it is technically feasible and commercially viable, then the costs are tested for impairment and transferred to property, plant and equipment. If a project is deemed to be unsuccessful, the associated costs are charged to the consolidated statement of income in the period as exploration and evaluation expense. During the year ended December 31, 2010, the Company recognized $2.9 million of exploration and evaluation expenses on certain unsuccessful E&E projects.

Pre-licensing costs

Under IFRS, costs incurred prior to obtaining the legal right to explore for oil and gas must be expensed while under Canadian GAAP these costs were capitalized in PP&E under one full-cost centre. For the year ended December 31, 2010, $0.4 million of pre-licensing costs were charged to the consolidated statement of income as exploration and evaluation expense. The accounting policy difference has resulted in a decrease in cash from operating activities and an increase in cash from investing activities by $0.4 million for the year ended December 31, 2010.

(c): CGU impairment

Under IFRS, impairment testing is performed at a lower level of asset aggregation than under Canadian GAAP. During the fourth quarter of 2010, Harvest recorded a $13.7 million before tax impairment related to certain properties in South Alberta to reflect declining forecasted gas prices which resulted in lower estimated future cash flows. The recoverable amount was based on the assets' value-in-use, estimated using the net present value of the expected future cash flows.

(d): Depletion, depreciation and amortization

Under IFRS, Harvest aggregates its PP&E into major components for depletion, depreciation and amortization. For the Upstream PP&E, costs accumulated within each component are depleted using the unit-of-production method based on estimated proved developed reserves, whereas under Canadian GAAP, estimated proved reserves were used. The carrying value of PP&E under IFRS differs from that under Canadian GAAP as a result of changes in the accounting of decommissioning liabilities and dispositions of PP&E as discussed in items (a) and (e). Among these changes, the componentization of PP&E and the use of proved developed reserves for depletion primarily attributed to the recognition of additional $47.8 million of depletion, depreciation and amortization expense for the year ended December 31, 2010.

F-57

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

27. First Time Adoption of IFRS (Continued)

(e): Dispositions

Under Canadian GAAP, proceeds on the dispositions of PP&E were credited to the full cost pool and no gain or loss was recognized unless the effect of the sale would have changed the DD&A rate by 20% or more. Under IFRS, all gains and losses are recognized on oil and gas property divestitures and calculated as the difference between net proceeds and the carrying value of the net assets disposed. Accordingly, Harvest recognized a gain on PP&E disposal of $1.3 million for the year ended December 31, 2010 under IFRS. During the year ended December 31, 2010, Harvest also recognized a loss of $1.0 million relating to disposition of certain E&E assets.

(f): Acquisition

Acquisition costs

Under IFRS, acquisition costs relating to a business combination are expensed. As such, $0.3 million of acquisition costs were expensed for the year ended December 31, 2010. Under Canadian GAAP, such costs were capitalized as part of PP&E.

BlackGold asset transfer

Under IFRS, the transfer of BlackGold oil sand assets from KNOC in August 2010 is measured at the fair value of the assets and liabilities. Under Canadian GAAP, the assets and liabilities were transferred at the carrying value. The difference in the accounting treatment results in a reversal of an $8.5 million loss that was previously recognized in retained earnings and an increase of $8.5 million in PP&E.

Gain on acquisition

On September 30, 2010, Harvest purchased the remaining 40% of the Redearth Partnership ("Partnership") as well as additional petroleum and natural gas rights, tangible assets, seismic data and other miscellaneous interests and associated production. Under IFRS, the acquirer is required to re-measure its previously held equity interest in the acquiree (the Partnership) at its acquisition-date fair value and recognize the resulting gain or loss, if any, in profit or loss; as such a gain of $0.4 million was recognized in the income statement relating to the 60% previously held interest in the Partnership for the year end December 31, 2010. Canadian GAAP did not require such re-measurement. See note 3 for other information on this asset acquisition.

(g): Post-employment benefits

Under Canadian GAAP, the Company amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the consolidated financial statements. Under IFRS, actuarial gains and losses are recognized directly in other comprehensive income in the period in which they occur. For the year ended December 31, 2010, actuarial losses amortization of $0.4 million were reclassified to other comprehensive income from the net income. Together with the recognition of the

F-58

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

27. First Time Adoption of IFRS (Continued)

unamortized actuarial losses, other comprehensive income was reduced by $3.2 million (net of deferred tax asset of $0.7 million) under IFRS.

(h): Deferred income taxes ("DIT")

IFRS requires recognition of the DIT asset or liability that arises on the difference between historical and current exchange rates on the translation of non-monetary assets, whereas Canadian GAAP did not. This difference, however, does not impact the DIT liability balance on transition date as the cumulative translation adjustments balance at transition date is $nil as a result of the KNOC acquisition. For the year ended December 31, 2010, the DIT expense decreased by $10.9 million.

As a result of the increase in the net book value of the decommissioning liabilities, the DIT effect has been adjusted. This resulted in a corresponding increase in retained earnings of $69.1 million on January 1, 2010.

The DIT expense decreased by $14.3 million for the year ended December 31, 2010, resulting from the increase in decommissioning liabilities and PP&E.

(i): Currency translation

Harvest's Downstream functional currency is U.S. dollars. As a result of the addition of the Downstream decommissioning liabilities in accordance with IAS 37, a currency exchange loss resulted from the revaluation of the liabilities at the end of each reporting period. For the year ended December 31, 2010 the amount of foreign exchange loss recognized was $0.4 million, which increased net loss and decreased other comprehensive loss.

Reclassifications

E&E and PP&E

Under Canadian GAAP, the Company had accounted for E&E and PP&E amounts under the full-cost method where these costs were included in PP&E. IFRS requires E&E costs to be segregated from PP&E.

As a result of the application of IFRS, the Company has separately classified E&E expenditures of $36.0 million from PP&E at the Transition Date. At December 31, 2010, $47.0 million, were reclassified. Note 6 discloses a reconciliation of E&E assets from the Transition Date to December 31, 2011.

Accretion of decommissioning liabilities

Accretion expense under Canadian GAAP has been reclassified from depreciation, depletion, amortization and accretion expense to finance costs under IFRS. The amount that was reclassified was $25.2 million for the year ended December 31, 2010.

F-59

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

27. First Time Adoption of IFRS (Continued)

Downstream loyalty program

Under Canadian GAAP, the Company had accounted for loyalty program costs by recording an expense. Under IFRS, the fair value of the consideration received or receivable in respect of the initial sale should be allocated between the award credits. As such, the Company has allocated the fair value of the consideration received from the sales to the award credits. This resulted in reclassifying $1.3 million of petroleum, natural gas, and refined product sales to Downstream operating expenses for the year ended December 31, 2010.

28. Subsequent Event

On May 30, 2012, Harvest executed an agreement with its engineering, procurement and construction (EPC) contractor to amend aspects of the EPC contract, including revising the compensation terms from a lump sum price to a cost reimbursable price and confirming greater Harvest control over project execution. The project pressures and resultant contract changes are expected to increase the net EPC costs to approximately $520 million, after allowing for certain costs which are not reimbursable to the EPC contractor.

29. Supplemental Guarantor Condensed Financial Information

Harvest Breeze Trust No. 1, Harvest Breeze Trust No. 2, Breeze Resources Partnership, Hay River Partnership, 1496965 Alberta Ltd. and North Atlantic Refining Limited (collectively "guarantor subsidiaries") fully and unconditionally guarantees the 6⁷/8% senior notes issued by Harvest Operations Corporation ("HOC"). Each of the guarantor subsidiary is 100% owned by HOC. The following financial information for HOC, the guarantor subsidiaries and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about HOC and its subsidiaries and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each guarantor subsidiary. Investments include the investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity income of subsidiaries is the group's share of profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between subsidiaries. HOC's cost basis has not been pushed down to the subsidiaries as push-down accounting is not permitted in the separate financial statements of the subsidiaries.

F-60

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

29. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF FINANCIAL POSITION
As at December 31, 2011



Assets
Current assets
Cash and cash equivalents	470		3,048		3,089		—		6,607
Accounts receivable and other	121,291		89,795		1,166		—		212,252
Inventories	1,325		58,601		1,026		—		60,952
Prepaid expenses	11,763		6,737		26		—		18,526
Risk management contracts	20,162		—		—		—		20,162
Due from affiliates	517,100		44,778		222		(562,100	)	—

	672,111		202,959		5,529		(562,100	)	318,499
Non-current assets
Long-term deposit	24,925		—		—		—		24,925
Investment tax credits and other	—		53,994		—		—		53,994
Exploration & evaluation assets	69,645		4,872		—		—		74,517
Property, plant and equipment	3,460,884		1,938,111		1,392		—		5,400,387
Other long-term asset	7,105		—		—		—		7,105
Investment in subsidiaries	1,127,353		143		—		(1,127,496	)	—
Goodwill	404,943		—		—		—		404,943

Total assets	5,766,966		2,200,079		6,921		(1,689,596	)	6,284,370

Liabilities
Current liabilities
Accounts payable and accrued liabilities	260,968		200,885		2,295		—		464,148
Current portion of convertible debentures	107,146		—		—		—		107,146
Current portion of decommissioning liabilities	12,782		—		—		—		12,782
Due to affiliates	39,294		513,334		9,472		(562,100	)	—

	420,190		714,219		11,767		(562,100	)	584,076
Non-current liabilities
Bank loan	355,575		—		—		—		355,575
Convertible debentures	634,921		—		—		—		634,921
Senior notes	495,674		—		—		—		495,674
Decommissioning liabilities	464,125		210,397		—		—		674,522
Post-employment benefit obligations	—		25,958		—		—		25,958
Deferred credits and other	5,093		—		—		—		5,093
Deferred income tax liability	(62,258	)	118,017		(852	)	—		54,907
Intercompany loan	—		1,189,756		—		(1,189,756	)	—

Total liabilities	2,313,320		2,258,347		10,915		(1,751,856	)	2,830,726
Shareholder's equity	3,453,646		(58,268	)	(3,994	)	62,260		3,453,644

Total liabilities and shareholder's equity	5,766,966		2,200,079		6,921		(1,689,596	)	6,284,370

F-61

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

29. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
For the year ended December 31, 2011



Petroleum, natural gas, and refined product sales	985,887		3,516,668		70,653		(46,887	)	4,526,321
Royalties	(146,291	)	(49,161	)	—		—		(195,452	)
Earnings from equity accounted subsidiaries	(55,664	)	(150	)	—		55,814		—

Revenues	783,932		3,467,357		70,653		8,927		4,330,869
Expenses
Purchased products for processing and resale	—		3,035,560		65,446		(45,770	)	3,055,236
Operating	280,698		290,141		6,409		(1,117	)	576,131
Transportation and marketing	22,212		13,720		(13	)	—		35,919
General and administrative	48,161		14,407		—		—		62,568
Depletion, depreciation and amortization	423,833		202,835		30		—		626,698
Exploration and evaluation	15,987		2,302		—		—		18,289
Gain on disposition of property, plant and equipment	(7,883	)	—		—		—		(7,883	)
Finance costs	102,477		6,650		—		—		109,127
Risk management contracts gains	(6,746	)	—		—		—		(6,746	)
Foreign exchange (gains) losses	11,752		(15,788	)	50		—		(3,986	)

Loss before income tax	(106,559	)	(82,470	)	(1,269	)	55,814		(134,484	)
Income tax recovery	(1,902	)	(27,367	)	(558	)	—		(29,827	)

Net loss	(104,657	)	(55,103	)	(711	)	55,814		(104,657	)
Other comprehensive income (loss)
Gains on derivatives designated as cash flow hedges, net of tax	19,421		—		—		—		19,421
Gains on foreign currency translation	21,480		21,480		—		(21,480	)	21,480
Actuarial loss, net of tax	(4,891	)	(4,891	)	—		4,891		(4,891	)

Comprehensive loss	(68,647	)	(38,514	)	(711	)	39,225		(68,647	)

F-62

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

29. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF CASH FLOWS
For the year ended December 31, 2011



Cash provided by (used in) operating activities	62,023		498,793		(327	)	—		560,489
Cash provided by (used in) financing activities	848,751		(157,141	)	—		157,141		848,751
Cash used in investing activities	(922,818	)	(341,686	)	—		(157,141	)	(1,421,645	)

Change in cash and cash equivalents	(12,044	)	(34	)	(327	)	—		(12,405	)
Effect of exchange rate changes on cash	—		106		—		—		106
Cash and cash equivalents, beginning of year	12,514		2,976		3,416		—		18,906

Cash and cash equivalents, end of year	470		3,048		3,089		—		6,607

F-63

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

29. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF FINANCIAL POSITION
As at December 31, 2010



Assets
Current assets
Cash and cash equivalents	12,514		2,976	3,416		—		18,906
Accounts receivable and other	102,929		109,386	1,616		—		213,931
Inventories	1,010		73,769	738		—		75,517
Prepaid expenses	49,352		5,701	18		—		55,071
Risk management contracts	1,007		—	—		—		1,007
Due from affiliates	139,587		28,476	210		(168,273	)	—

	306,399		220,308	5,998		(168,273	)	364,432
Non-current assets
Long-term deposit	30,603		—	—		—		30,603
Investment tax credits and other	—		44,339	—		—		44,339
Deferred income tax asset	—		1,633	—		—		1,633
Exploration & evaluation assets	53,004		6,550	—		—		59,554
Property, plant and equipment	2,760,202		1,721,612	1,422		—		4,483,236
Investment in subsidiaries	1,323,569		293	—		(1,323,862	)	—
Goodwill	404,943		—	—		—		404,943

Total assets	4,878,720		1,994,735	7,420		(1,492,135	)	5,388,740

Liabilities
Current liabilities
Accounts payable and accrued liabilities	208,302		150,713	1,472		—		360,487
Current portion of decommissioning liabilities	16,672		—	—		—		16,672
Risk management contracts	7,553		—	—		—		7,553
Due to affiliates	21,860		136,893	9,520		(168,273	)	—

	254,387		287,606	10,992		(168,273	)	384,712
Non-current liabilities
Bank loan	11,379		—	—		—		11,379
Convertible debentures	745,257		—	—		—		745,257
Senior notes	482,389		—	—		—		482,389
Decommissioning liabilities	435,008		211,339	—		—		646,347
Post-employment benefit obligations	—		20,365	—		—		20,365
Deferred credits and others	293		—	—		—		293
Deferred income tax liability	(66,847	)	148,280	(290	)	—		81,143
Intercompany loan	—		1,189,756	—		(1,189,756	)	—

Total liabilities	1,861,866		1,857,346	10,702		(1,358,029	)	2,371,885
Shareholder's equity	3,016,854		137,389	(3,282	)	(134,106	)	3,016,855

Total liabilities and shareholder's equity	4,878,720		1,994,735	7,420		(1,492,135	)	5,388,740

F-64

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

29. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
For the year ended December 31, 2010

							Eliminations

Petroleum, natural gas, and refined product sales	719,504		3,381,443		34,375		(22,361)	4,112,961
Royalties	(107,901	)	(46,856	)	—		—	(154,757	)
Earnings from equity accounted subsidiaries	(65,031	)	(267	)	—		65,298	—

Revenues	546,572		3,334,320		34,375		42,937	3,958,204
Expenses
Purchased products for processing and resale	—		2,884,230		30,421		(20,846)	2,893,805
Operating	202,774		274,903		5,071		(1,515)	481,233
Transportation and marketing	8,078		7,703		(21	)	—	15,760
General and administrative	31,360		15,707		—		—	47,067
Depletion, depreciation and amortization	340,244		213,449		39		—	553,732
Exploration and evaluation	3,300		—		—		—	3,300
Gain on disposition of property, plant and equipment	(741	)	—		—		—	(741	)
Finance costs	65,769		35,038		1		—	100,808
Risk management contracts gains	(550	)	—		—		—	(550	)
Foreign exchange (gains) losses	(21,215	)	17,809		7		—	(3,399	)
Impairment on property, plant and equipment	7,455		6,206		—		—	13,661

Loss before income tax	(89,902	)	(120,725	)	(1,143	)	65,298	(146,472	)
Income tax recovery	(8,740	)	(56,462	)	(107	)	—	(65,309	)

Net loss	(81,162	)	(64,263	)	(1,036	)	65,298	(81,163	)
Other comprehensive income (loss)
Losses on derivatives designated as cash flow hedges, net of tax	(5,020	)	—		—		—	(5,020	)
Losses on foreign currency translation	(45,920	)	(45,920	)	—		45,920	(45,920	)
Actuarial loss, net of tax	(3,218	)	(3,217	)	—		3,218	(3,217	)

Comprehensive loss	(135,320	)	(113,400	)	(1,036	)	114,436	(135,320	)

F-65

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

29. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF CASH FLOWS
For the year ended December 31, 2010



Cash provided by operating activities	263,674		171,953		3,557		—		439,184
Cash provided by (used in) financing activities	204,887		(60,471	)	—		58,097		202,513
Cash used in investing activities	(456,047	)	(113,951	)	(141	)	(58,097	)	(628,236	)

Change in cash and cash equivalents	12,514		(2,469	)	3,416		—		13,461
Effect of exchange rate changes on cash	—		5,445		—		—		5,445
Cash and cash equivalents, beginning of year	—		—		—		—		—

Cash and cash equivalents, end of year	12,514		2,976		3,416		—		18,906

F-66

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Years ended December 31, 2011 and December 31, 2010

(amounts in thousands of Canadian dollars unless otherwise indicated)

29. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF FINANCIAL POSITION
As at January 1, 2010



Assets
Current assets
Accounts receivable and other	85,850		91,158		1,654		—		178,662
Inventories	1,182		85,473		164		—		86,819
Prepaid expenses	9,684		5,859		8		—		15,551
Due from affiliates	90,501		10,088		2,995		(103,584	)	—

	187,217		192,578		4,821		(103,584	)	281,032
Non-current assets
Investment tax credits and other	—		2,177		—		—		2,177
Exploration & evaluation assets	33,870		2,164		—		—		36,034
Property, plant and equipment	2,172,948		1,880,351		1,320		—		4,054,619
Investment in subsidiaries	1,495,835		560		—		(1,496,395	)	—
Goodwill	404,943		—		—		—		404,943

Total assets	4,294,813		2,077,830		6,141		(1,599,979	)	4,778,805

Liabilities
Current liabilities
Bank loan	424,999		3,018		—		—		428,017
Accounts payable and accrued liabilities	127,250		77,074		1,054		—		205,378
Current portion of convertible debentures	182,806		—		—		—		182,806
Current portion of senior notes	42,921		—		—		—		42,921
Current portion of decommissioning liabilities	11,710		—		—		—		11,710
Risk management contracts	2,052		—		—		—		2,052
Due to affiliates	4,475		91,632		7,477		(103,584	)	—

	796,213		171,724		8,531		(103,584	)	872,884
Non-current liabilities
Convertible debentures	748,261		—		—		—		748,261
Senior notes	222,456		—		—		—		222,456
Decommissioning liabilities	369,571		186,205		—		—		555,776
Post-employment benefit obligations	—		17,453		—		—		17,453
Deferred credits and other	357		—		—		—		357
Deferred income tax liability	(61,559	)	203,807		(143	)	—		142,105
Intercompany loan	—		2,193,476		—		(2,193,476	)	—

Total liabilities	2,075,299		2,772,665		8,388		(2,297,060	)	2,559,292
Shareholder's equity	2,219,514		(694,835	)	(2,247	)	697,081		2,219,513

Total liabilities and shareholder's equity	4,294,813		2,077,830		6,141		(1,599,979	)	4,778,805

F-67

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

		As At

(thousands of Canadian dollars)	Notes	March 31, 2012			December 31, 2011
Assets
Current assets
Cash and cash equivalents	17	$	7,396		$	6,607
Accounts receivable and other	17		180,697			212,252
Inventories	5		105,430			60,952
Prepaid expenses			18,070			18,526
Risk management contracts	17		10,645			20,162

			322,238			318,499
Non-current assets
Long-term deposit			24,359			24,925
Investment tax credits and other			53,742			53,994
Deferred income tax asset			1,766			—
Exploration and evaluation assets	6		93,201			74,517
Property, plant and equipment	7		5,415,046			5,400,387
Other long-term asset			6,955			7,105
Goodwill			404,943			404,943

			6,000,012			5,965,871

Total assets		$	6,322,250		$	6,284,370

Liabilities
Current liabilities
Accounts payable and accrued liabilities	17	$	457,237		$	464,148
Current portion of convertible debentures	17		107,043			107,146
Current portion of decommissioning liabilities	8		16,687			12,782

			580,967			584,076
Non-current liabilities
Bank loan	9, 17		531,619			355,575
Convertible debentures	17		634,194			634,921
Senior notes	17		486,611			495,674
Decommissioning and environmental remediation liabilities	8		673,964			674,522
Post-employment benefit obligations			28,011			25,958
Deferred credits and other			757			5,093
Deferred income tax liability			30,794			54,907

			2,385,950			2,246,650

Total liabilities		$	2,966,917		$	2,830,726

Shareholder's equity
Shareholder's capital	10		3,860,786			3,860,786
Deficit			(461,076	)		(388,995	)
Accumulated other comprehensive loss	16		(44,377	)		(18,147	)

Total shareholder's equity			3,355,333			3,453,644

Total liabilities and shareholder's equity		$	6,322,250		$	6,284,370

Commitments[Note 19]

The accompanying notes are an integral part of these consolidated financial statements.

F-68

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

		Three months ended March 31,

(thousands of Canadian dollars)	Notes	2012			2011
Petroleum, natural gas, and refined products sales		$	1,479,557		$	1,284,782
Royalties			(53,417	)		(35,858	)

Revenues	12		1,426,140			1,248,924
Expenses
Purchased products for processing and resale			1,101,716			892,013
Operating			174,456			137,534
Transportation and marketing			7,051			4,697
General and administrative			12,303			13,963
Depletion, depreciation and amortization			171,052			140,744
Exploration and evaluation	6		6,736			6,215
Gains on disposition of property, plant and equipment			(106	)		(240	)
Finance costs	13		27,336			27,517
Risk management contracts gains	17		(271	)		(5,463	)
Foreign exchange gains	14		(1,194	)		(9,808	)
Impairment on property, plant and equipment	7		21,843			—

Income (loss) before income tax			(94,782	)		41,752
Income tax expense (recovery)			(22,701	)		3,791

Net income (loss)			(72,081	)		37,961

Other comprehensive loss
Losses on designated cash flow hedges, net of tax	16,17		(7,321	)		(40,407	)
Losses on foreign currency translation	16		(16,068	)		(23,921	)
Actuarial loss, net of tax	16		(2,841	)		—

Comprehensive loss		$	(98,311	)	$	(26,367	)

The accompanying notes are an integral part of these consolidated financial statements.

F-69

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (UNAUDITED)

(thousands of Canadian dollars)	Notes	Shareholder's Capital		Deficit			Accumulated Other Comprehensive Loss			Total Shareholder's Equity

Balance at December 31, 2011		$	3,860,786	$	(388,995	)	$	(18,147	)	$	3,453,644
Losses on derivatives designated as cash flow hedges, net of tax	16		—		—			(7,321	)		(7,321	)
Losses on foreign currency translation	16		—		—			(16,068	)		(16,068	)
Actuarial loss, net of tax	16		—		—			(2,841	)		(2,841	)
Net loss			—		(72,081	)		—			(72,081	)

Balance at March 31, 2012		$	3,860,786	$	(461,076	)	$	(44,377	)	$	3,355,333

Balance at December 31, 2010		$	3,355,350	$	(284,338	)	$	(54,157	)	$	3,016,855
Issue of share capital for cash			505,436		—			—			505,436
Losses on derivatives designated as cash flow hedges, net of tax			—		—			(40,407	)		(40,407	)
Losses on foreign currency translation			—		—			(23,921	)		(23,921	)
Net income			—		37,961			—			37,961

Balance at March 31, 2011		$	3,860,786	$	(246,377	)	$	(118,485	)	$	3,495,924

The accompanying notes are an integral part of these consolidated financial statements.

F-70

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

		Three Months Ended March 31,

(thousands of Canadian dollars)	Notes	2012			2011
Cash provided by (used in)
Operating Activities
Net income (loss)		$	(72,081	)	$	37,961
Items not requiring cash
Depletion, depreciation and amortization			171,052			140,744
Accretion of decommissioning and environmental remediation liabilities	8, 13		5,153			5,796
Unrealized gains on risk management contracts	17		(271	)		(3,240	)
Unrealized gains on foreign exchange	14		(2,765	)		(9,617	)
Non-cash interest income			(132	)		(67	)
Unsuccessful exploration and evaluation costs	6		4,158			6,091
Impairment on property, plant and equipment	7		21,843			—
Gains on disposition of property, plant and equipment			(106	)		(240	)
Deferred income tax expense (recovery)			(22,701	)		3,807
Other non-cash items			(4,752	)		370
Settlement of decommissioning and environmental remediation liabilities	8		(6,587	)		(1,967	)
Change in non-cash working capital	15		(7,701	)		(32,810	)

			85,110			146,828

Financing Activities
Issue of common shares, net of issue costs	10		—			505,436
Bank borrowing (repayments), net			175,789			18,636

			175,789			524,072

Investing Activities
Business acquisitions	4		—			(513,458	)
Additions to property, plant and equipment	7		(224,022	)		(238,216	)
Additions to exploration and evaluation assets	6		(27,833	)		(35,312	)
Property dispositions (acquisitions), net			1,988			(2,038	)
Change in non-cash working capital	15		(10,243	)		105,113

			(260,110	)		(683,911	)

Change in cash and cash equivalents			789			(13,011	)
Cash and cash equivalents, beginning of period			6,607			18,906

Cash and cash equivalents, end of period		$	7,396		$	5,895

Interest paid		$	10,128		$	8,297
Income tax (received) paid, net		$	—		$	(16	)

The accompanying notes are an integral part of these consolidated financial statements.

F-71

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

1. Nature of Operations and Structure of the Company

Harvest is a wholly owned subsidiary of Korea National Oil Corporation ("KNOC"). The Company is incorporated and domiciled in Canada.

These consolidated financial statements were approved and authorized for issue by the Board of Directors on June 14, 2012.

Harvest's principal place of business is located at 2100, 330 - 5^th Avenue SW, Calgary, Alberta, Canada T2P 0L4.

2. Basis of Presentation

These interim consolidated financial statements have been prepared in accordance with IAS 34—"Interim Financial Reporting" using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). The interim consolidated financial statements do not include all of the information required for annual financial statements and should be read in conjunction with the Audited Consolidated Financial Statements as at and for the year ended December 31, 2011, which were prepared in accordance with IFRS.

(a): Basis of Measurement

The consolidated financial statements have been prepared on the historical cost basis except for held-for-trading financial assets and derivative financial instruments, which are measured at fair value.

(b): Functional and Presentation Currency

3. Significant Accounting Policies

These interim consolidated financial statements follow the same accounting principles and methods of application as those disclosed in note 2 to the Company's Audited Consolidated Financial Statements as at and for the year ended December 31, 2011.

4. Acquisitions

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

F-72

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

4. Acquisitions (Continued)

consideration of $511.0 million. The acquisition was accounted for as a business combination. KNOC provided $505.4 million of equity to fund the acquisition. An additional $25 million is payable to Hunt in the event that Canadian natural gas prices exceed certain pre-determined levels in 2012. This potential payable is considered contingent consideration and is required to be fair valued. Based on forecast gas prices, the probability of incurring this payment was assessed as low; as such no fair value was assigned on the allocation of consideration transferred. The Company's assessment of this contingent liability remained the same at March 31, 2012 whereby no provision was recorded.

From the date of acquisition, the Hunt assets have contributed $10.5 million of revenue and $6.9 million to Harvest's earnings before depletion and income tax for the three months ended March 31, 2011. If the acquisition had been completed on the first day of 2011, Harvest's revenues for the three months ended March 31, 2011 would have been $14.6 million higher and the earnings before depletion and income tax would have been $7.4 million higher.

5. Inventories

	March 31, 2012		December 31, 2011

Petroleum products
Upstream—pipeline fill	$	1,680	$	1,325
Downstream		100,561		56,298

Total petroleum product inventory		102,241		57,623
Parts and supplies		3,189		3,329

	$	105,430	$	60,952

6. Exploration and Evaluation Assets (E&E)


As at December 31, 2010	$	59,554
Additions		50,883
Acquisition		18,627
Dispositions		(717	)
Unsuccessful exploration & evaluation costs		(17,757	)
Transfer to property, plant & equipment		(36,073	)

As at December 31, 2011	$	74,517
Additions		27,833
Unsuccessful exploration and evaluation costs		(4,158	)
Transfer to property, plant and equipment		(4,991	)

As at March 31, 2012	$	93,201

F-73

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

6. Exploration and Evaluation Assets (E&E) (Continued)

The Company determined certain E&E costs to be unsuccessful and not recoverable and were expensed as follows:

	Three months ended March 31

	2012		2011
Pre-licensing costs	$	2,578	$	124
Unsuccessful E&E costs		4,158		6,091

E&E expense	$	6,736	$	6,215

7. Property, Plant and Equipment (PP&E)

	Upstream			Downstream			Total

Cost:
As at December 31, 2010	$	3,964,155		$	1,081,885		$	5,046,040
Additions		682,497			284,244			966,741
Acquisitions		533,963			—			533,963
Change in decommissioning liabilities		(18,245	)		3,767			(14,478	)
Transfers from E&E		36,073			—			36,073
Exchange adjustment		—			36,928			36,928
Disposals		(882	)		(18,031	)		(18,913	)
Investment tax credits		—			(10,187	)		(10,187	)

As at December 31, 2011	$	5,197,561		$	1,378,606		$	6,576,167
Additions		210,759			13,263			224,022
Disposals		(1,882	)		—			(1,882	)
Change in decommissioning liabilities		3,713			—			3,713
Transfers from E&E		4,991			—			4,991
Exchange adjustment		—			(26,521	)		(26,521	)

As at March 31, 2012	$	5,415,142		$	1,365,348		$	6,780,490

F-74

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

7. Property, Plant and Equipment (PP&E) (Continued)

	Upstream		Downstream			Total

Accumulated depletion, depreciation, amortization and impairment losses:
As at December 31, 2010	$	484,302	$	78,502		$	562,804
Depreciation, depletion and amortization		535,384		91,006			626,390
Disposals		—		(18,031	)		(18,031	)
Exchange adjustment		—		4,617			4,617

As at December 31, 2011		1,019,686		156,094			1,175,780
Depreciation, depletion and amortization		144,333		26,570			170,903
Impairment		21,843		—			21,843
Exchange adjustment		—		(3,082	)		(3,082	)

As at March 31, 2012	$	1,185,862	$	179,582		$	1,365,444

Net Book Value
As at March 31, 2012	$	4,229,280	$	1,185,766		$	5,415,046
As at December 31, 2011	$	4,177,875	$	1,222,512		$	5,400,387

General and administrative costs of $6.0 million have been capitalized during the three month period ended March 31, 2012 (2011—$4.4 million). Borrowing costs relating to the development of BlackGold assets and the Downstream debottlenecking project have been capitalized within PP&E during the three months ended March 31, 2012 in the amount of $2.9 million (2011—$1.3 million), at a weighted average interest rate of 5.76% (2011—7.12%).

At March 31, 2012, the following costs were excluded from the asset base subject to depreciation, depletion and amortization: Downstream major parts inventory of $7.4 million (2011—$7.5 million); Downstream assets under construction of $107.5 million (2011—$102.5 million); and BlackGold oil sands assets of $528.9 million (2011—$497.2 million).

During the three months ended March 31, 2012, Harvest recorded an impairment of $21.8 million (before tax) to its Upstream PP&E relating to certain gas properties in the South Alberta cash generating unit to reflect lower forecasted gas prices, which resulted in lower estimated future cash flows. The recoverable amount was based on the assets' value-in-use, estimated using the net

F-75

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

7. Property, Plant and Equipment (PP&E) (Continued)

present value of the future cash flows. A pre-tax discount rate of 10% and the following forward gas prices were used in the impairment calculation:

	Year		AECO Gas ($Cdn/Mmbtu)⁽¹⁾

	2012 (9 months)			2.65
	2013			3.60
	2014			4.20
	2015			4.75
	2016			5.15
	2017			5.70
	2018			6.00
	2019			6.20
	2020			6.35
	2021			6.50
	2022			6.65
	2023			6.75
	2024			6.90
	2025			7.05
	2026			7.20
	Thereafter⁽²⁾			+2%/year

(1): Source: McDaniel & Associates Consultants Ltd, effective April 1, 2012.
(2): Percentage change represents the change in each year after 2026 to the end of the reserve.

8. Decommissioning & Environmental Remediation Liabilities

Harvest estimates the total undiscounted amount of cash flows required to settle its decommissioning and environmental remediation liabilities to be approximately $1.5 billion at March 31, 2012 (2011—$1.4 billion), which will be incurred between 2012 and 2072. A risk-free discount rate of 3.0% (2011—3.0%) and inflation rate of 1.7% (2011—1.7%) were used to

F-76

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

8. Decommissioning & Environmental Remediation Liabilities (Continued)

calculate the fair value of the decommissioning and environmental remediation liabilities. The following is a reconciliation of the decommissioning liabilities:

	Upstream			Downstream		Total

Decommissioning liabilities at December 31, 2010	$	651,048		$	10,426	$	661,474
Liabilities assumed on acquisitions		36,403			—		36,403
Liabilities incurred		28,382			—		28,382
Settled during the period		(22,110	)		—		(22,110	)
Revisions (change in estimate)		(46,627	)		3,767		(42,860	)
Disposals		(708	)		—		(708	)
Accretion		23,099			400		23,499

Decommissioning liabilities at December 31, 2011	$	669,487		$	14,593	$	684,080
Environmental remediation at December 31, 2011		3,224			—		3,224

Balance at December 31, 2011	$	672,711		$	14,593	$	687,304

Decommissioning liabilities at December 31, 2011	$	669,487		$	14,593	$	684,080
Liabilities incurred		3,713			—		3,713
Settled during the period		(6,256	)		—		(6,256	)
Accretion		5,021			108		5,129

Decommissioning liabilities at March 31, 2012	$	671,965		$	14,701	$	686,666
Environmental remediation at March 31, 2012		3,985			—		3,985

Balance at March 31, 2012	$	675,950		$	14,701	$	690,651

Current portion	$	16,687		$	—	$	16,687
Non-current portion		659,263			14,701		673,964

Balance at March 31, 2012	$	675,950		$	14,701	$	690,651

9. Bank Loan

At March 31, 2012, Harvest had $534.7 million drawn from the $800 million available under the credit facility (2011—$358.9 million). The carrying value of the bank loan includes $3.1 million of deferred financial charges at March 31, 2012 (2011—$3.3 million). For the three months ended March 31, 2012, interest charges on bank loans aggregated to $3.4 million (2011—$0.4 million), reflecting an effective interest rate of 2.84% (2011—3.06%).

10. 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.

F-77

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

10. Shareholder's Capital (Continued)

(b): Number of Common Shares Issued


	Outstanding at December 31, 2010			335,535,047
	Issued to KNOC at $10.00 per share for Hunt acquisition			50,543,602

	Outstanding at December 31, 2011 and March 31, 2012			386,078,649

11. Capital Structure

Harvest considers its capital structure to be its credit facility, senior notes, convertible debentures and shareholder's equity.

	March 31, 2012		December 31, 2011

Bank loan⁽¹⁾	$	534,675	$	358,885
Senior notes (US$500 million)⁽²⁾		498,750		508,500
Principal amount of convertible debentures		733,973		733,973

	$	1,767,398	$	1,601,358
Shareholder's equity		3,355,333		3,453,644

	$	5,122,731	$	5,055,002

(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 financial ratios. These ratios are also included in the externally imposed capital requirements under the Company's credit facility, senior notes and convertible debentures; Harvest was in compliance with all debt covenants at March 31, 2012.

	Covenant

Secured debt⁽¹⁾ to Annualized EBITDA	3.0 to 1.0 or less	1.18	0.73
Total debt⁽²⁾ to Annualized EBITDA	3.5 to 1.0 or less	3.48	2.72
Secured debt⁽¹⁾ to Capitalization⁽³⁾	50% or less	13%	10%
Total debt⁽²⁾ to Capitalization⁽³⁾	55% or less	39%	36%

(1): Secured debt consists of letters of credit of $8.7 million (2011—$8.7 million), bank loan of $531.6 million (2011—$355.6 million) and guarantees of $90.3 million (2011—$92.1 million) at March 31, 2012.
(2): Total debt consists of secured debt, convertible debentures and senior notes.
(3): Capitalization consists of total debt and shareholder's equity less equity for BlackGold of $458.9 million at March 31, 2012 (2011—$459.9 million).

F-78

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

12. Revenue and other income

	Three months ended March 31

	2012		2011
Crude oil and natural gas sales, net of royalty	$	266,554	$	248,228
Refinery products sales		1,155,406		1,003,731
Effective portion of realized crude oil hedges		4,180		(3,035	)

	$	1,426,140	$	1,248,924

13. Finance Costs

	Three months ended March 31

	2012			2011
Interest and other finance charges	$	25,075		$	23,017
Accretion of decommissioning and environmental remediation liabilities		5,153			5,796
Less: capitalized interest		(2,892	)		(1,296	)

	$	27,336		$	27,517

14. Foreign Exchange

	Three months ended March 31

	2012			2011
Realized (gains) losses on foreign exchange	$	1,571		$	(191	)
Unrealized gains on foreign exchange		(2,765	)		(9,617	)

	$	(1,194	)	$	(9,808	)

F-79

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

15. Supplemental Cash Flow Information

	Three months ended March 31

	2012			2011
Source (use) of cash:
Accounts receivable and other	$	31,555		$	(13,457	)
Prepaid expenses and long-term deposit		1,022			40,146
Inventories		(44,478	)		(24,484	)
Accounts payable and accrued liabilities		(6,911	)		72,542

Net changes in non-cash working capital	$	(18,812	)	$	74,747

Changes relating to operating activities		(7,701	)		(32,810	)
Changes relating to financing activities		—			—
Changes relating to investing activities		(10,243	)		105,113
Add: Non-cash changes		(868	)		2,444

	$	(18,812	)	$	74,747

16. Accumulated Other Comprehensive Income (Loss)

	Foreign Currency Translation Adjustment			Designated Cash Flow Hedges, Net of Tax			Actuarial Loss, Net of Tax			Total

Balance at December 31, 2010	$	(45,920	)	$	(5,020	)	$	(3,217	)	$	(54,157	)
Reclassification to net income of losses on cash flow hedges		—			7,050			—			7,050
Gains on derivatives designated as cash flow hedges		—			12,371			—			12,371
Actuarial loss		—			—			(4,891	)		(4,891	)
Gains on foreign currency translation		21,480			—			—			21,480

Balance at December 31, 2011	$	(24,440	)	$	14,401		$	(8,108	)	$	(18,147	)
Reclassification to net income of gains on cash flow hedges		—			(3,126	)		—			(3,126	)
Losses on derivatives designated as cash flow hedges		—			(4,195	)		—			(4,195	)
Actuarial loss		—			—			(2,841	)		(2,841	)
Losses on foreign currency translation		(16,068	)		—			—			(16,068	)

Balance at March 31, 2012	$	(40,508	)	$	7,080		$	(10,949	)	$	(44,377	)

The effective portion of the after tax unrealized loss on derivatives designated as cash flow hedges of $4.2 million (pre-tax loss of $5.6 million) was included in other comprehensive loss for the three months ended March 31, 2012 (2011—after tax and pre-tax losses of $42.6 million and $58.2 million respectively). The amount removed from accumulated other comprehensive loss and included in petroleum, natural gas, and refined product sales was an after tax gain of $3.1 million

F-80

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

16. Accumulated Other Comprehensive Income (Loss) (Continued)

(pre-tax gain of $4.2 million) for the three months ended March 31, 2012 (2011—after tax and pre-tax losses of $2.2 million and $3.0 million respectively). The Company expects that $7.1 million of gains reported in accumulated other comprehensive loss will be released to net income within the next 9 months.

17. Financial Instruments

(a): Fair Values

Financial instruments of Harvest consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, bank loan, risk management contracts, convertible debentures and senior notes. The carrying value and fair value of these financial instruments are disclosed below by financial instrument category:

	March 31, 2012				December 31, 2011

	Carrying Value		Fair Value		Carrying Value		Fair Value
Financial assets
Loans and Receivables
Accounts receivable and other	$	180,697	$	180,697	$	212,252	$	212,252
Held for Trading
Cash and cash equivalents		7,396		7,396		6,607		6,607
Risk management contracts		10,645		10,645		20,162		20,162

Total Financial Assets	$	198,738	$	198,738	$	239,021	$	239,021

Financial Liabilities
Measured at Amortized Cost
Accounts payable and accrued liabilities		457,237		457,237		464,148		464,148
Bank loan		531,619		534,675		355,575		358,885
Senior notes		486,611		531,483		495,674		523,119
Convertible debentures		741,237		755,935		742,067		752,345

Total Financial Liabilities	$	2,216,704	$	2,279,330	$	2,057,464	$	2,098,497

(b): Risk Management Contracts

F-81

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

17. Financial Instruments (Continued)

income and included in petroleum, natural gas, and refined product sales (see note 16). The ineffective portion of the unrealized and realized gains and losses recognized in the consolidated income statement from these cash flow hedges is shown below for crude oil, together with the realized and unrealized (gains) losses on power and currency risk management contracts:

	Three months ended March 31

	2012											2011
	Power		Crude oil			Currency			Total			Power			Crude oil		Currency		Total
Realized (gains) losses	$	—	$	—		$	—		$	—		$	(2,282	)	$	59	$	—	$	(2,223	)
Unrealized (gains) losses		—		(205	)		(66	)		(271	)		(3,554	)		285		29		(3,240	)

	$	—	$	(205	)	$	(66	)	$	(271	)	$	(5,836	)	$	344	$	29	$	(5,463	)

The following is a summary of Harvest's risk management contracts outstanding at March 31, 2012:

Contracts Designated as Hedges

Contract Quantity	Type of Contract	Term	Contract Price	Fair Value

4,200 bbls/day	Crude oil price swap	Apr—Dec 2012	US $111.37/bbl	$	10,578
US $468/day	Foreign exchange swap	Apr—Dec 2012	$1.0236 Cdn/US		67

				$	10,645

F-82

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

18. Segment Information

	Three months ended March 31

	Downstream					Upstream						Total
	2012			2011		2012			2011			2012			2011
Petroleum, natural gas and refined products sales	$	1,155,406		$	1,003,731	$	324,151		$	281,051		$	1,479,557		$	1,284,782
Royalties		—			—		(53,417	)		(35,858	)		(53,417	)		(35,858	)

Revenues	$	1,155,406		$	1,003,731	$	270,734		$	245,193		$	1,426,140		$	1,248,924
Expenses
Purchased products for resale and processing		1,101,716			892,013		—			—			1,101,716			892,013
Operating		74,481			53,939		99,975			83,595			174,456			137,534
Transportation and marketing		1,365			1,694		5,686			3,003			7,051			4,697
General and administrative		150			441		12,153			13,522			12,303			13,963
Exploration and evaluation		—			—		6,736			6,215			6,736			6,215
Depletion, depreciation and amortization		26,570			19,400		144,482			121,344			171,052			140,744
Gains on disposition of PP&E		—			—		(106	)		(240	)		(106	)		(240	)
Risk management contracts gains		—			—		(271	)		(5,463	)		(271	)		(5,463	)
Impairment on PP&E		—			—		21,843			—			21,843			—

	$	(48,876	)	$	36,244	$	(19,764	)	$	23,217		$	(68,640	)	$	59,461
Finance costs													27,336			27,517
Foreign exchange gains													(1,194	)		(9,808	)

Income (Loss) before income tax												$	(94,782	)	$	41,752
Income tax (recovery) loss													(22,701	)		3,791

Net income (loss)												$	(72,081	)	$	37,961

Capital Expenditures
Business acquisition	$	—		$	—	$	—		$	513,458		$	—		$	513,458
Additions to PP&E		13,263			35,879		210,759			202,337			224,022			238,216
Additions to E&E		—			—		27,833			35,312			27,833			35,312
Property acquisitions (dispositions), net		—			—		(1,988	)		2,038			(1,988	)		2,038

Total expenditures	$	13,263		$	35,879	$	236,604		$	753,145		$	249,867		$	789,024

(1): Of the total Downstream revenue, one customer represents sales of $978.8 million for the three months ended March 31, 2012 (2011—two customers with sales of $663.2 million and $101.6 million). No other single customer within either segment represents greater than 10% of Harvest's total revenue.
(2): There is no intersegment activity.

F-83

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

18. Segment Information (Continued)

	Total Assets		PP&E		E&E		Other Long- Term Assets		Goodwill

March 31, 2012
Downstream	$	1,400,470	$	1,185,766	$	—	$	—	$	—
Upstream		4,921,780		4,229,280		93,201		6,955		404,943

Total	$	6,322,250	$	5,415,046	$	93,201	$	6,955	$	404,943

December 31, 2011
Downstream	$	1,408,112	$	1,222,512	$	—	$	—	$	—
Upstream		4,876,258		4,177,875		74,517		7,105		404,943

Total	$	6,284,370	$	5,400,387	$	74,517	$	7,105	$	404,943

19. Commitments

The following is a summary of Harvest's contractual obligations and commitments as at March 31, 2012:

	Maturity

	1 year		2-3 years		4-5 years		After 5 years		Total
Debt repayments⁽¹⁾	$	106,796	$	390,598	$	771,254	$	498,750	$	1,767,398
Debt interest payments⁽¹⁾		106,158		145,976		75,646		19,288		347,068
Purchase commitments⁽²⁾		222,988		42,144		—		—		265,132
Operating leases		12,100		19,713		7,224		2,358		41,395
Transportation agreements⁽³⁾		8,803		12,808		4,186		237		26,034
Feedstock & other purchase commitments⁽⁴⁾		940,304		—		—		—		940,304
Employee benefits⁽⁵⁾		4,102		7,433		5,178		2,877		19,590
Decommissioning liabilities⁽⁶⁾		16,687		53,884		34,343		1,349,810		1,454,724

Total	$	1,417,938	$	672,556	$	897,831	$	1,873,320	$	4,861,645

(1): Assumes constant period end foreign exchange rate.
(2): Relates to drilling commitments, AFE commitments, BlackGold oil sands project commitment and Downstream capital commitments.
(3): Relates to firm transportation commitments.
(4): Includes commitments to purchase refinery crude stock and refined products for re-sale under the supply and offtake agreement.
(5): Relates to the expected contributions to employee benefit plans and long-term incentive plan payments.
(6): Represents the undiscounted obligation by period.

F-84

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

20. Subsequent Event

21. Supplemental Guarantor Condensed Financial Information

F-85

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

21. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENTS OF FINANCIAL POSITION
As at March 31, 2012



Assets
Current assets
Cash and cash equivalents	360	2,402		4,634		—		7,396
Accounts receivable and other	108,490	70,544		1,663		—		180,697
Inventories	1,680	102,639		1,111		—		105,430
Prepaid expenses	12,368	5,646		56		—		18,070
Risk management contracts	10,645	—		—		—		10,645
Due from affiliates	658,945	49,489		223		(708,657	)	—

	792,488	230,720		7,687		(708,657	)	322,238
Non-current assets
Long-term deposit	24,359	—		—		—		24,359
Investment tax credits and other	—	53,742		—		—		53,742
Deferred income tax asset	67,824	(66,942	)	884		—		1,766
Exploration & evaluation assets	87,732	5,469		—		—		93,201
Property, plant and equipment	3,505,810	1,907,854		1,382		—		5,415,046
Other long-term asset	6,955	—		—		—		6,955
Investment in subsidiaries	1,031,124	259		—		(1,031,383	)	—
Goodwill	404,943	—		—		—		404,943

Total assets	5,921,235	2,131,102		9,953		(1,740,040	)	6,322,250

Liabilities
Current liabilities
Accounts payable and accrued liabilities	283,374	169,875		3,988		—		457,237
Current portion of convertible debentures	107,043	—		—		—		107,043
Current portion of decommissioning liabilities	16,687	—		—		—		16,687
Due to affiliates	43,654	654,981		10,022		(708,657	)	—

	450,758	824,856		14,010		(708,657	)	580,967
Non-current liabilities
Bank loan	531,619	—		—		—		531,619
Convertible debentures	634,194	—		—		—		634,194
Senior notes	486,611	—		—		—		486,611
Decommissioning and environmental remediation liabilities	461,963	212,001		—		—		673,964
Post-employment benefit obligations	—	28,011		—		—		28,011
Deferred credits and other	757	—		—		—		757
Deferred income tax liability	—	30,820		(26	)	—		30,794
Intercompany loan	—	1,189,756		—		(1,189,756	)	—

Total liabilities	2,565,902	2,285,444		13,984		(1,898,413	)	2,966,917
Shareholder's equity	3,355,333	(154,342	)	(4,031	)	158,373		3,355,333

Total liabilities and shareholder's equity	5,921,235	2,131,102		9,953		(1,740,040	)	6,322,250

F-86

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

21. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the three months ended March 31, 2012

										��

Petroleum, natural gas, and refined product sales	243,258		1,229,818		19,460		(12,979	)	1,479,557
Royalty expense	(38,239	)	(15,178	)	—		—		(53,417	)
Earnings from equity accounted subsidiaries	(37,581	)	116		—		37,465		—

Revenues	167,438		1,214,756		19,460		24,486		1,426,140
Expenses
Purchased products for processing and resale	—		1,096,443		18,134		(12,861	)	1,101,716
Operating	78,871		94,307		1,396		(118	)	174,456
Transportation and marketing	5,632		1,420		(1	)	—		7,051
General and administrative	8,479		3,824		—		—		12,303
Depletion, depreciation and amortization	115,880		55,163		9		—		171,052
Exploration and evaluation	6,580		156		—		—		6,736
Gain on disposition of property, plant & equipment	(106	)	—		—		—		(106	)
Finance costs	25,887		1,449		—		—		27,336
Risk management contracts gains	(271	)	—		—		—		(271	)
Foreign exchange (gains) losses	(9,634	)	8,424		16		—		(1,194	)
Impairment on property, plant & equipment	11,301		10,542		—		—		21,843

Loss before income tax	(75,181	)	(56,972	)	(94	)	37,465		(94,782	)
Income tax recovery	(3,100	)	(19,544	)	(57	)	—		(22,701	)

Net loss	(72,081	)	(37,428	)	(37	)	37,465		(72,081	)
Other comprehensive loss
Losses on designated cash flow hedges, net of tax	(7,321	)	—		—		—		(7,321	)
Losses on foreign currency translation	(16,068	)	(16,068	)	—		16,068		(16,068	)
Actuarial loss, net of tax	(2,841	)	(2,841	)	—		2,841		(2,841	)

Comprehensive loss for the period	(98,311	)	(56,337	)	(37	)	56,374		(98,311	)

CONDENSED STATEMENT OF CASH FLOWS
For the three months ended March 31, 2012



Cash provided by (used in) operating activities	(30,297	)	113,862		1,545	—		85,110
Cash provided by (used in) financing activities	175,789		(39,738	)	—	39,738		175,789
Cash used in investing activities	(145,602	)	(74,770	)	—	(39,738	)	(260,110	)

Change in cash and cash equivalents	(110	)	(646	)	1,545	—		789
Cash and cash equivalents, beginning of year	470		3,048		3,089	—		6,607

Cash and cash equivalents, end of year	360		2,402		4,634	—		7,396

F-87

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

21. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF FINANCIAL POSITION
As at December 31, 2011



Assets
Current assets
Cash and cash equivalents	470		3,048		3,089		—		6,607
Accounts receivable and other	121,291		89,795		1,166		—		212,252
Inventories	1,325		58,601		1,026		—		60,952
Prepaid expenses	11,763		6,737		26		—		18,526
Risk management contracts	20,162		—		—		—		20,162
Due from affiliates	517,100		44,778		222		(562,100	)	—

	672,111		202,959		5,529		(562,100	)	318,499
Non-current assets
Long-term deposit	24,925		—		—		—		24,925
Investment tax credits and other	—		53,994		—		—		53,994
Exploration & evaluation assets	69,645		4,872		—		—		74,517
Property, plant and equipment	3,460,884		1,938,111		1,392		—		5,400,387
Other long-term asset	7,105		—		—		—		7,105
Investment in subsidiaries	1,127,353		143		—		(1,127,496	)	—
Goodwill	404,943		—		—		—		404,943

Total assets	5,766,966		2,200,079		6,921		(1,689,596	)	6,284,370

Liabilities
Current liabilities
Accounts payable and accrued liabilities	260,968		200,885		2,295		—		464,148
Current portion of convertible debentures	107,146		—		—		—		107,146
Current portion of decommissioning liabilities	12,782		—		—		—		12,782
Due to affiliates	39,294		513,334		9,472		(562,100	)	—

	420,190		714,219		11,767		(562,100	)	584,076
Non-current liabilities
Bank loan	355,575		—		—		—		355,575
Convertible debentures	634,921		—		—		—		634,921
Senior notes	495,674		—		—		—		495,674
Decommissioning liabilities	464,125		210,397		—		—		674,522
Post-employment benefit obligations	—		25,958		—		—		25,958
Deferred credits and other	5,093		—		—		—		5,093
Deferred income tax liability	(62,258	)	118,017		(852	)	—		54,907
Intercompany loan	—		1,189,756		—		(1,189,756	)	—

Total liabilities	2,313,320		2,258,347		10,915		(1,751,856	)	2,830,726
Shareholder's equity	3,453,646		(58,268	)	(3,994	)	62,260		3,453,644

Total liabilities and shareholder's equity	5,766,966		2,200,079		6,921		(1,689,596	)	6,284,370

F-88

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

21. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the three months ended March 31, 2011



Petroleum, natural gas, and refined product sales	207,991		1,072,062		14,630		(9,901	)	1,284,782
Royalty expense	(23,299	)	(12,559	)	—		—		(35,858	)
Earnings from equity accounted subsidiaries	69,170		(14	)	—		(69,156	)	—

Revenues	253,862		1,059,489		14,630		(79,057	)	1,248,924
Expenses
Purchased products for processing and resale	—		888,266		13,530		(9,783	)	892,013
Operating	62,955		73,342		1,355		(118	)	137,534
Transportation and marketing	2,935		1,765		(3	)	—		4,697
General and administrative	9,932		4,031		—		—		13,963
Depletion, depreciation and amortization	121,321		19,423		—		—		140,744
Exploration and evaluation	6,215		—		—		—		6,215
Gain on disposition of property, plant & equipment	(240	)	—		—		—		(240	)
Finance costs	27,425		92		—		—		27,517
Risk management contracts gains	(5,463	)	—		—		—		(5,463	)
Foreign exchange (gains) losses	(12,466	)	2,648		10		—		(9,808	)

Income (loss) before income tax	41,248		69,922		(262	)	(69,156	)	41,752
Income tax expense (recovery)	3,287		521		(17	)	—		3,791

Net income (loss)	37,961		69,401		(245	)	(69,156	)	37,961
Other comprehensive loss
Losses on designated cash flow hedges, net of tax	(40,407	)	—		—		—		(40,407	)
Loss on foreign currency translation	(23,921	)	(23,921	)	—		23,921		(23,921	)

Comprehensive loss	(26,367	)	45,480		(245	)	(45,235	)	(26,367	)

F-89

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

For the three months ended March 31, 2012 and 2011

(Tabular amounts in thousands of Canadian dollars)

21. Supplemental Guarantor Condensed Financial Information (Continued)

CONDENSED STATEMENT OF CASH FLOWS
For the three months ended March 31, 2011



Cash provided by operating activities	52,269		93,599		960	—		146,828
Cash provided by (used in) financing activities	523,436		(35,799	)	—	36,435		524,072
Cash used in investing activities	(588,129	)	(59,347	)	—	(36,435	)	(683,911	)

Change in cash and cash equivalents	(12,424	)	(1,547	)	960	—		(13,011	)
Cash and cash equivalents, beginning of year	12,514		2,976		3,416	—		18,906

Cash and cash equivalents, end of year	90		1,429		4,376	—		5,895

F-90

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (Unaudited)

The information below provides supplemental information on the oil and gas producing activities of the Corporation as of January 1, 2010, December 31, 2010 and 2011 and for the years ended December 31, 2010 and 2011 in accordance Financial Accounting Standards Board ("FASB") Statement of Accounting Standards No. 69—Disclosures about Oil and Gas Producing Activities ("FAS 69"). Activities not directly associated with oil and gas producing activities are excluded from all aspects of this supplemental information.

Tables I through III present information on Harvest's estimated net proved reserve quantities; standardized measure of discounted future net cash flows, and changes in the standardized measure of discounted future net cash flows. Tables IV through VI provide historical cost information pertaining to result of operations related to oil and gas producing activities, capitalized costs related to oil and gas producing activities, and costs incurred in oil and gas exploration and development. Financial information included in tables IV through VI is derived from Harvest's audited annual financial statements which are prepared in accordance with IFRS.

Table I: Net Proved Reserves (Harvest's Share After Royalties)

Harvest's net proved oil and gas reserves as of January 1, 2010, December 31, 2010 and 2011, and changes thereto for the years ended December 31, 2010 and 2011 are shown in the following table. Note that all Harvest's proved reserves are located within Canada. Proved reserves as of the January 1, 2010, December 31, 2010 and 2011 were calculated using the average first-day-of-the-month oil and gas prices for the prior twelve-month period.

Proved oil and gas reserves, as defined within the SEC's Regulation S-X, are those quantities of oil and gas, which by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate.

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered:

1.: Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; and
2.: Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

The process of estimating proved and proved developed reserves is very complex and requires significant judgment in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may change significantly over time as a result of numerous factors, such as but not limited to, additional development activities, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Although reasonable effort is made to ensure that reserve estimates reported represent the most

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accurate assessments possible, reserve estimates are subject to change as additional information becomes available, and as future economic and operating conditions change.



January 1, 2010	90.4		—		153.1		116.0

Revisions of previous estimates (including infill drilling & improved recovery)	9.7		—		18.9		12.8
Purchase of reserves in place	5.3		86.7		11.3		93.9
Sale of reserves in place	—		—		—		—
Discoveries and extensions	3.0		—		4.7		3.8
Production	(11.0	)	—		(24.3	)	(15.1	)

December 31, 2010	97.4		86.7		163.7		211.4

Revisions of previous estimates (including infill drilling & improved recovery)	4.5		(4.5	)	21.1		3.5
Purchase of reserves in place	5.9		—		107.3		23.8
Sale of reserves in place	—		—		—		—
Discoveries and extensions	5.3		—		24.9		9.4
Production	(12.2	)	—		(36.6	)	(18.3	)

December 31, 2011	100.9		82.2		280.4		229.8

Proved Developed
January 1, 2010	79.0		—		137.8		102.0
December 31, 2010	84.3		—		143.7		108.3
December 31, 2011	88.3		—		226.6		126.0
Proved Undeveloped
January 1, 2010	11.4		—		15.3		14.0
December 31, 2010	13.1		86.7		20.0		103.1
December 31, 2011	12.6		82.2		53.8		103.8

Table II: Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table provides the standardized measure of discounted future cash flows relating to the proved reserves disclosed in Table I above. Future cash inflows are computed using Harvest's after royalty share of estimated annual future production from proved oil and gas reserves and the average first-day-of-the-month oil and gas prices for the prior twelve-month period as prescribed by the SEC. Future development, production and abandonment costs to be incurred in producing and further developing the proved reserves are based on the costs at the balance sheet date and assuming continuation of existing economic conditions. Future income taxes are computed by applying year-end statutory tax rates to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10% mid-period discount factors. This discounting requires a year-by-year estimate of when the future expenditure will be incurred and when the reserves will be produced.

The information provided in this table does not represent Harvest's estimate of the Corporation's expected future cash flows or the fair market value of the proved oil and gas reserves due to several factors including:

•: Estimates of proved reserve quantities are subject to change as new information becomes available;

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•: Probable and possible reserves, which may become proved in the future, are excluded from the calculations;
•: Future prices and costs rather than twelve-month average prices and costs at balance sheet date will apply;
•: Economic conditions such as interest rates and income tax rates and operating conditions may differ from what is used in the preparation of the estimates; and
•: Future development and asset decommissioning costs will differ from those estimated.

(thousands of Canadian dollars)	December 31, 2011			December 31, 2010			January 1, 2010

Future cash inflows	$	15,741,619		$	12,302,457		$	6,241,849
Less future:
Production costs		(7,467,785	)		(6,272,986	)		(3,249,477	)
Development costs		(1,664,733	)		(1,503,936	)		(364,839	)
Decommissioning costs		(885,825	)		(865,652	)		(830,850	)
Income taxes		(598,210	)		(210,257	)		—

Future net cash flows		5,125,066			3,449,626			1,796,683
Less 10% annual discount		(2,285,876	)		(1,585,699	)		(553,778	)

Standardized measure of discounted future net cash flows	$	2,839,190		$	1,863,927		$	1,242,905

Table III: Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

(thousands of Canadian dollars)	December 31, 2011			December 31, 2010

Future discounted net cash flow, beginning of year	$	1,863,927		$	1,242,905
Sales & transfers of oil and gas produced, net of production costs		(711,332	)		(577,260	)
Net change in sales & transfer prices and production costs related to future production		616,785			566,000
Development costs incurred during the period		680,279			354,916
Change in future development costs		(658,367	)		(429,126	)
Change due to extensions and discoveries		176,717			84,300
Accretion of discount		233,997			159,495
Sales of reserves in place		—			—
Purchase of reserves in place		293,325			200,234
Net change in income taxes		(387,953	)		(187,455	)
Changes due to revisions in timing of future net cash flow and other		731,812			449,917

Future discounted net cash flow, end of year	$	2,839,190		$	1,863,926

Net change for the year	$	975,263		$	621,021

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Table IV: Results of Operations

	Year Ended

(thousands of Canadian dollars)	December 31, 2011		December 31, 2010
Petroleum and natural gas revenues, net of royalties	$	1,091,414	$	852,247
Less:
Production costs		350,456		265,593
Exploration expense		18,289		3,300
Depletion, depreciation, and amortization⁽¹⁾		533,425		470,688
Accretion of decommissioning liability		23,151		22,342
Impairment on oil and gas properties		—		13,661
Other (transportation and marketing costs)		29,626		9,394
Income tax expense⁽²⁾		29,681		9,049

Results of operations (excluding corporate overhead and interest costs)	$	106,786	$	58,220

(1): Excludes depreciation on corporate assets.
(2): Income tax expense has been calculated in accordance with FAS 69 using the statutory tax rate and reflecting tax deductions and credits and allowances relating to the oil and gas producing activities that are reflected in the consolidated income tax expense for the period.

Table V: Capitalized Costs

(thousands of Canadian dollars)	December 31, 2011			December 31, 2010			January 1, 2010

Proved oil and gas properties⁽¹⁾	$	5,180,432		$	3,945,379		$	2,936,446
Unproved oil and gas properties
Unproven properties included in property, plant and equipment⁽²⁾		8,467			12,392			3,142
Exploration and evaluation assets		74,517			59,554			36,034

Total unproved oil and gas properties		82,984			71,946			39,176
Total capital costs		5,263,416			4,017,325			2,975,622
Accumulated depreciation, depletion and amortization ("DD&A")⁽³⁾		(1,015,540	)		(482,422	)		—

Net capitalized costs	$	4,247,876		$	3,534,903		$	2,975,622

(1): Proved oil and gas properties exclude $8.7 million of corporate assets as at December 31, 2011 (December 31, 2010—$6.4 million; January 1, 2010—$1.3 million).
(2): Costs related to incomplete wells as at year end. As at December 31, 2011, Harvest was in the process of drilling a total of 10 gross wells (December 31, 2010—13 gross wells; January 1, 2010—4 gross wells).
(3): Accumulated DD&A excludes accumulated depreciation on corporate assets of $4.1 million as at December 31, 2011 (December 31, 2010—$1.9 million; January 1, 2010—$nil).

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Table VI: Costs Incurred

	Year Ended

(thousands of Canadian dollars)	December 31, 2011		December 31, 2010
Property acquisitions⁽¹⁾
Proved property	$	495,456	$	550,870
Unproved property		18,627		—

Total property acquisition costs		514,083		550,870
Exploration costs		50,883		46,997
Development costs		662,035		423,593

Total costs incurred⁽²⁾	$	1,227,001	$	1,021,460

(1): Property acquisition costs include business and property acquisitions and exclude proceeds received from dispositions of $8.7 million for the year ended December 31, 2011 (2010—$1.0 million).
(2): Total costs incurred exclude costs related to corporate assets of $2.2 million for the year ended December 31, 2011 (2010—$5.1 million).

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US$500,000,000

Harvest Operations Corp.

Offer to Exchange

6⁷/8% Senior Notes due 2017
(US$500,000,000 aggregate principal amount) and related guarantees which have been registered under the Securities Act of 1933

for

all outstanding 6⁷/8% Senior Notes due 2017
(US$500,000,000 aggregate principal amount) and related guarantees

July 3, 2012

Exchange Agent:

U.S. Bank National Association
60 Livingston Avenue
St Paul MN 55107
Tel: 800-934-6802
Fax: 651-466-7372

No person has been authorized to give any information or to make any representation other than those contained in this prospectus, and, if given or made, any information or representations must not be relied upon as having been authorized. This prospectus does not constitute an offer to sell or the solicitation of an offer to buy any securities other than the securities to which it relates or an offer to sell or the solicitation of an offer to buy these securities in any circumstances in which this offer or solicitation is unlawful. Neither the delivery of this prospectus nor any sale made under this prospectus shall, under any circumstances, create any implication that there has been no change in the affairs of Harvest since the date of this prospectus.

Until December 30, 2012, broker-dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the broker-dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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