40-F

2006

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 40-F

o      Registration Statement pursuant to section 12 of the Securities Exchange Act of 1934

þ      Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2006 Commission File Number: 001-04307

Husky Energy Inc.

(Exact name of Registrant as specified in its charter)

Alberta, Canada
(Province or other jurisdiction of
incorporation or organization) 1311
(Primary Standard Industrial
Classification Code Numbers) Not Applicable
(I.R.S. Employer Identification Number
(if applicable))

707-8th Avenue S.W., P.O. Box 6525 Station D, Calgary, Alberta, Canada T2P 3G7
(403) 298-6111
(Address and telephone number of Registrant’s principal executive office)

CT Corporation System, 111 Eighth Avenue, New York, New York 10011
(212) 894-8400
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of Each Class: None

Securities registered or to be registered pursuant to Section 12(g) of the Act:
Title of Each Class: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

The Registrant is a “voluntary filer” and files annual reports on Form 40-F, amendments to such reports and furnishes

information on Form 6-K to the securities and Exchange Commission, pursuant to its obligations under its indenture

dated June 14, 2002 relating to its 6.25% Notes due 2012 and 6.15% Notes due 2019.

For annual reports, indicate by check mark the information filed with this Form:

þ Annual information form þ Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period

covered by the annual report: 424,268,509.

Common Shares were outstanding as of December 31, 2006

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the filing number assigned to the Registrant in connection with such Rule.

Yes o No þ

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

Yes þ No o

The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the Registrant’s Registration Statement under the Securities Act of 1933: For F-9 File No. 333-137211.

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F:

A.  Annual Information Form

For the Annual Information Form of Husky Energy Inc. (“Husky”) for the year ended December 31, 2006, see Document A of this Annual Report on Form 40-F.

B.  Audited Annual Financial Statements

For Husky’s audited consolidated financial statements for the year ended December 31, 2006 and 2005, including the auditor’s report with respect thereto, see Document B of this Annual Report on Form 40-F. For a reconciliation of important differences between Canadian and United States generally accepted accounting principles, see Note 19 of the notes to the audited consolidated financial statements.

C.  Management’s Discussion and Analysis

For Husky’s Management’s Discussion and Analysis for the year ended December 31, 2006, see Document C of this Annual Report on Form 40-F.

Controls and Procedures

See “Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2006, which is filed as Document C to this Annual Report on Form 40-F.

Audit Committee Financial Expert

The Board of Directors of Husky has determined that R. Donald Fullerton is an “audit committee financial expert” (as defined in paragraph 8(b) of General Instruction B to Form 40-F) serving on its Audit Committee. Pursuant to paragraph 8(a)(2) of General Instruction B to Form 40-F, the Board has applied the definition of independence applicable to the audit committee members of New York Stock Exchange listed companies. Mr. Fullerton is a corporate director and is independent under the New York Stock Exchange standard. For a description of Mr. Fullerton’s relevant experience in financial matters, see Mr. Fullerton’s five year history in the section “Directors and Officers” and in the section “Audit Committee” in the Registrant’s Annual Information Form for the year ended December 31, 2006, which is included as Document A of this Annual Report on Form 40-F.

Code of Business Conduct and Ethics

Husky’s Code of Ethics is disclosed in its Code of Business Conduct, which is applicable to all its employees, and is posted on its website at www.huskyenergy.ca. In the event that, during Husky’s ensuing fiscal year, Husky:

i.	amends any provision of its Code of Business Conduct that applies to the Registrant’s principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F, or
ii.	grants a waiver, including an implicit waiver, from a provision of its Code of Business Conduct to any of Husky’s principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of the code of ethics definition as enumerated in paragraph (9)(b) of General Instruction B to Form 40-F,

Husky will promptly disclose such occurrences on its website following the date of such amendment or waiver and will specifically describe the nature of any amendment or waiver, and in the case of a waiver, name the person to whom the waiver was granted and the date of the waiver.

Principal Accountant Fees and Services

See “Audit Committee” in the Annual Information Form for the year ended December 31, 2006, which is included as Document A to this Annual Report on Form 40-F.

Off-balance Sheet Arrangements

See “Off- balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2006, which is filed as Document C to this Annual Report on Form 40-F.

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Disclosure of Contractual Obligations

See “Contractual Obligations and Other Commercial Commitments” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2006, which is included as Document C to this Annual Report on Form 40-F.

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Undertaking

Husky undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

Consent to Service of Process

Forms F-X signed by Husky and its agent for service of process have been filed with the Commission together with Forms F-9 in connection with its 6.25% Notes due 2012 and 6.15% Notes due 2019.

Any change to the name or address of the agent for service of process of Husky shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of Husky.

SIGNATURES

Pursuant to the requirements of the Exchange Act, Husky certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized.

Dated this 13th day of March, 2007

Husky Energy Inc.

By:  /s/  John C.S. Lau

Name: John C.S. Lau

Title:  President & Chief Executive Officer

By:  /s/  James D. Girgulis

Name: James D. Girgulis

Title:  Vice President, Legal & Corporate Secretary

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Document A
Form 40-F

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2006

Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2006

March 13, 2007

TABLE OF CONTENTS

	Page
Exchange Rate Information		2
Disclosure of Exemption Under National Instrument 51-101		2
Corporate Structure		3
Intercorporate Relationships		4
General Development of Husky		4
Three Year History of Husky		4
Subsequent Events		5
Events expected to occur during 2007		5
Business Environment Trends		5
Description of Husky’s Business		6
General		6
Upstream Operations		6
Midstream Operations		7
Refined Products		7
Social and Environmental Policy		7
Risk Factors		8
Upstream Operations		10
Disclosures of Oil and Gas Activities		10
Oil and Gas Reserves Disclosures		20
Statement of Financial Accounting Standards No. 69		25
Description of Major Properties and Facilities		30
Distribution of Oil and Gas Production		47
Midstream Operations		47
Refined Products		50
Human Resources		54
Dividends		55
Description of Capital Structure		55
Market for Securities		57
Directors and Officers		57
Audit Committee		61
Legal Proceedings		62
Interest of Management and Others in Material Transactions		62
Transfer Agent and Registrars		62
Interests of Experts		62
Additional Information		63
Abbreviations and Glossary of Terms		64
Special Note Regarding Forward-looking Statements		69
Schedules		71
A — Audit Committee Charter		71
B — Report on Reserves Data by Qualified Reserves Evaluator		75
C — Report of Management and Directors on Reserves Data and Other Information		77
D — Independent Engineer’s Audit Opinion		79
Consent of KPMG
Consent of McDaniel and Associates Consultants Ltd.
Certification of CEO Pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
Certification of the CFO Pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
Certification of the CEO Pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350)
Certification of the CFO Pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350)

Unless otherwise indicated, all financial information is in accordance with accounting principles generally accepted in Canada. Unless otherwise indicated, gross reserves or gross production are reserves or production attributable to Husky’s interest prior to deduction of royalties; net reserves or net production are reserves or production net of such royalties. Gross or net production reported refers to sales volume, unless otherwise indicated. Natural gas volumes are converted to a barrel of oil equivalent (“boe”) basis using the ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel (“bbl”) of oil and natural gas liquids. Unless otherwise indicated, oil and gas commodity prices are quoted after the effect of hedging gains and losses. Natural gas volumes are stated at the official temperature and pressure basis of the area in which the reserves are located. The calculation of boe and thousands of cubic feet equivalent (mcfge) are based on a conversion rate of six thousand cubic feet to one barrel of oil.

Boe or mcfge may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf to one 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.

Refer to page 69 “Special Note Regarding Forward-Looking Statements.”

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EXCHANGE RATE INFORMATION

Except where otherwise indicated, all dollar amounts stated in this Annual Information Form (“AIF”) are Canadian dollars. The following table discloses various indicators of the Canadian/United States rate of exchange or the cost of a U.S. dollar in Canadian currency for the three years indicated.

	Year ended December 31
	2006		2005		2004
Year end		1.165		1.166		1.203
Low		1.095		1.151		1.178
High		1.179		1.210		1.397
Average		1.134		1.211		1.302

Notes:

(1)	The exchange rates were as quoted by the Federal Reserve Bank of New York for the noon buying rate.
(2)	The high, low and average rates were either quoted or calculated as of the last day of the relevant month.

DISCLOSURE OF EXEMPTION UNDER NATIONAL INSTRUMENT 51-101

Husky believes that comparability of its disclosures with those required in its major capital market, the United States, is important to many of the investors and prospective investors in its securities. Accordingly, we applied for and were granted an exemption by the Canadian securities regulators under the provisions of National Instrument 51-101 “Standards of Disclosures for Oil and Gas Activities” (“NI 51-101”). The exemption, under Section 8.4 of the Companion Policy to NI 51-101, permits us to substitute disclosures required by and consistent with those of the Securities and Exchange Commission of the United States (“SEC”) and the Financial Accounting Standards Board in the United States (“FASB”) in place of much of the disclosure required by NI 51-101. In accordance with the exemption, proved oil and gas reserves data and certain other disclosures with respect to our oil and gas activities in this Annual Information Form are presented in accordance with the following requirements:

•  The FASB Statement No. 69 “Disclosure about Oil and Gas Producing Activities — an amendment of FASB Statements No.’s 19, 25, 33 and 39” (“FAS 69”);

•  FASB Current Text Section Oi5, “Oil and Gas Producing Activities” paragraph .103, .106, .107, .108, .112, .160 through .167, .174 through .184 and .401 through .408;

•  SEC Industry Guide 2;

•  SEC Item 102 of regulation S-K (17 CFR 229.102);

•  SEC Item 302(b) of Regulation S-K (17 CFR 229.302(b)); and

•  The definitions and disclosures required by SEC Regulation S-X (CFR 210.4-10).

Proved oil and gas reserves information and other disclosures about oil and gas activities in this Annual Information Form following SEC requirements may differ from corresponding information otherwise required by NI 51-101. Proved reserves disclosed in this Annual Information Form are in accordance with the SEC definitions.

NI 51-101 specifies that proved reserves be determined in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”) definitions. There were no material differences between the oil and gas reserves determined using the SEC definitions and the COGEH definitions. In addition, NI 51-101 requires the inclusion of probable reserves and their associated future net revenue. The SEC does not normally permit the disclosure of probable reserves in documents filed with them.

The SEC requires the evaluation of oil and gas reserves to be based on prices, costs, fiscal regimes and other economic and operating conditions in effect at the time the evaluation is made (“constant prices”). NI 51-101 also requires the evaluation of oil and gas reserves on this basis but also requires an evaluation of oil and gas reserves to be based on a forecast of economic conditions. In establishing the constant prices for bitumen, NI 51-101 provides for a different interpretation of the phrase “price will be the posted price of oil and the spot price of gas, after historical adjustments for transportation, gravity and other factors.” On January 20, 2005 the Canadian Securities Administrators issued Staff Notice 51-315 Guidance Regarding the Determination of Constant Prices for Bitumen Reserves under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities.” Bitumen is very heavy crude oil that is 10º API and lower. This guidance stipulates that for establishing the constant prices for bitumen, companies should use the

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posted price for West Texas Intermediate (“WTI”) and apply the average annual adjustment for transportation, gravity and other factors that create the difference in price between WTI and bitumen. This method was developed primarily in response to the fluctuations in bitumen prices that, for various reasons, tend to experience the lowest prices at the end of the calendar year. Under the FASB/SEC rules the determination of constant price for bitumen does not permit the use of annual average differentials between WTI and bitumen. These rules require the differentials prevailing on the last day of the period to be used to calculate the constant price. As a result on December 31, 2004, the price for bitumen as established under the FASB/SEC formula was lower than the price established under NI 51-101. There is no difference in determining the constant prices for crude oil classified as heavy oil, lighter than 10 degrees API and up to and including 20 degrees API, under NI 51-101 and FASB/SEC, although heavy oil experiences the same pricing patterns as bitumen.

Husky believes that its reserves evaluators are qualified and that it has a well established reserves evaluation process that is at least as rigorous as would be the case were we to rely upon independent reserves evaluators. Husky has adopted written evaluation practices and procedures using the COGEH modified to the extent necessary to reflect the definitions and standards under SEC disclosure requirements. In addition, Husky engages a firm of independent qualified reserves evaluators to conduct an audit of the reserves estimates and respective present worth value of the reserves as at December 31, 2006. They conducted their audit in accordance with the standards described in the COGEH and the auditing standards generally accepted in the United States.

NI 51-101 prescribes a relatively comprehensive set of disclosures in respect of oil and gas reserves and other disclosures about oil and gas activities. In comparison, the SEC prescribes a minimum set of disclosures and advises reporting companies not to approach the SEC rules and regulations as merely a blank form but encourages them to provide such additional information that is necessary to further an investor’s understanding of their business.

In either jurisdiction, information to further an investor’s understanding is specifically encouraged to be included in Management’s Discussion and Analysis (“MD&A”). The MD&A is intended to be a narrative explanation describing the Company, both its history and prospects, as perceived by management. The readers of the AIF are encouraged to also read the Company’s MD&A, which is filed, in accordance with the requirements of the Canadian Securities Administrators, on the System for Electronic Data Analysis and Retrieval (“SEDAR”). Documents filed on SEDAR may be accessed online at www.sedar.com. This AIF together with the MD&A and the Company’s Audited Consolidated Financial Statements are included in the FORM 40-F which is filed in accordance with the Securities and Exchange Commission (United States) on the Electronic Data Gathering Analysis and Retrieval (“EDGAR”) system, which may be accessed online at www.sec.gov.

CORPORATE STRUCTURE

Husky Energy Inc.

Husky Energy Inc. (“Husky Energy”) was incorporated under the Business Corporations Act (Alberta) on June 21, 2000. From the date of its incorporation until August 25, 2000, Husky Energy did not carry on any business. On August 25, 2000, Husky Energy was a party to a plan of arrangement under the Business Corporations Act (Alberta) (the “Arrangement”) pursuant to which Husky Oil Limited (“Husky Oil”), Husky Oil Operations Limited (a subsidiary of Husky Oil) and Renaissance Energy Ltd. (“Renaissance”) were amalgamated under the Business Corporations Act (Alberta) and continued as one corporation under the name “Husky Oil Operations Limited” (“HOOL”) and the security holders of Renaissance and Husky Oil exchanged their securities for securities of Husky Energy. Under the Arrangement, Husky Energy acquired 100% of the common shares of HOOL.

Husky Energy has its registered office and its head and principal office at 707 – 8th Avenue S.W., P.O. Box 6525, Station D, Calgary, Alberta, T2P 3G7.

In this Annual Information Form the term “Husky,” “we,” “our,” “us,” and “the Company,” means Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis including information with respect to predecessor corporations.

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INTERCORPORATE RELATIONSHIPS

The principal subsidiaries of Husky and place of incorporation, continuance or place of organization, as the case may be, are as follows. All of the following companies are directly or indirectly 100% owned.

Name	Jurisdiction
Subsidiaries of Husky Energy Inc.
Husky Oil Operations Limited	Nova Scotia
Subsidiaries of Husky Oil Operations Limited
Husky Oil Limited	Nova Scotia
Husky Energy Marketing Inc.	Alberta
Husky (U.S.A.) Inc.	Delaware
HOI Resources Co.	Nova Scotia
Canterra Resources Canada Ltd. (formerly 147212 Canada Ltd.)	Canada
Subsidiaries of Husky (U.S.A.) Inc.
Husky Gas Marketing Inc.	Delaware
Subsidiaries of HOI Resources Co.
Husky Energy International Corporation	British Columbia
Subsidiaries of Husky Energy International Corporation
Husky Oil China Ltd.	Alberta
Husky Oil (Madura) Ltd.	British Virgin Islands
Husky Oil Overseas Ltd.	Alberta

GENERAL DEVELOPMENT OF HUSKY

Three Year History of Husky

2004

On June 18, 2004, Husky issued U.S. $300 million of 6.15% notes due June 15, 2019. The notes were priced to yield 6.194% and are redeemable at the option of the Company at any time subject to a make-whole provision. The notes are unsecured and unsubordinated and rank equally with all its other unsecured and unsubordinated indebtedness.

Effective July 15, 2004, Husky acquired Temple Exploration Inc. for a cash purchase of $101.5 million plus the assumption of $13.5 million working capital deficit. The acquisition added 21.1 bcf of natural gas and 1.4 million barrels of natural gas liquids to proved reserves as well as undeveloped land.

On August 16, 2004, we signed a Production Sharing Agreement with the CNOOC for the 979,773 acre 29/26 block in the South China Sea. The agreement requires us to drill one exploration well with the option to drill two additional exploration wells before 2011. CNOOC has the right to participate in subsequent development up to 51%.

On October 26, 2004, we announced an agreement to acquire our co-venturer’s interest in the Madura Strait Production Sharing Agreement in Indonesia. Husky now holds a 100% interest in the 690,660 acre exploration block, which contains two discoveries with recoverable resources of natural gas and natural gas liquids.

In November 2004, Husky acquired three exploration licenses in the Jeanne d’Arc Basin offshore Newfoundland and Labrador. We acquired a 50% working interest in 225,100 acres, a 100% working interest in 128,800 acres and a 100% working interest in 208,200 acres. All three parcels are near Husky’s White Rose oil field currently under development.

2005

In September 2005, Husky announced that its Prince George refinery was now capable of producing gasoline that meets the Government of Canada’s new environmental specifications thereby completing the first of two phases of a “Clean Fuel” refinery modification project.

On November 12, 2005, first oil was produced at the White Rose oilfield offshore Newfoundland and Labrador. Husky holds a 72.5% interest in White Rose. Production from White Rose is 31º API light crude oil and will supply markets both in Canada and the United States.

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2006

In January 2006, Husky acquired two additional Exploration Licences (“EL”) in the Jeanne d’Arc Basin of the Grand Banks Region offshore Newfoundland and Labrador. Husky holds 100% working interest in the 33,320 acre EL1094 and the 5,260 acre EL 1096. Husky has committed to spend a total of $37 million evaluating the prospects of these ELs.

On February 1, 2006, Husky redeemed its 8.45% senior secured bonds for U.S. $85 million.

In April 2006, Husky acquired 23,680 acres of oil sands leases adjacent to its Saleski oil sand property. The cost was $10 million and increased Husky’s holdings in the Saleski area to 178,560 acres.

In June 2006, Husky completed a farm-in agreement with Norsk Hydro to earn additional interests in two Significant Discovery Licences in the Jeanne d’Arc Basin. Under the terms of the agreement Husky drilled a delineation well on West Bonne Bay, Significant Discovery Licence 1040, to earn 25% working interest and an additional 7.5% working interest in North Ben Nevis, Significant Discovery Licence 1008.

In July 2006, Husky acquired 14,560 acres of oil sands leases adjacent to its Saleski oil sand property. The cost was $6.6 million and increased Husky’s holdings in the Saleski area to 193,120 acres.

The second phase of modifications to produce low sulphur diesel fuel was completed during the second quarter of 2006. The refinery’s design rate capacity was increased to 12 mbbls/day as a result of this two phase modification.

In August 2006, Husky acquired 19,200 acres of oil sands leases adjacent to its Saleski oil sands property. The cost was $7.9 million and increased Husky’s holdings in the Saleski area to 212,320 acres.

In August 2006, Husky acquired three exploration blocks in the South China Sea totalling 4,168,915 acres. Block 29/06 covers 2,289,431 acres in the Pearl River Mouth Basin in 500 to 1500 metres of water, block 35/18 covers 1,104,314 acres in the Yinggehai Basin in less than 120 metres of water and block 50/14 covers 775,170 acres in the Yinggehai Basin in less than 120 metres of water.

In September 2006, Husky commissioned its Lloydminster ethanol plant, which is located adjacent to Husky’s heavy oil upgrader on the Saskatchewan side of Lloydminster and has a design capacity to produce 130 million litres of ethanol per year.

In September 2006, Husky filed a base shelf prospectus that permits issue of up to U.S. $1 billion of debt securities or the equivalent in other currencies during the 25 months that the prospectus is in effect.

In September, Husky acquired 26,880 acres of oil sands leases adjacent to its Saleski oil sands property. The cost was $13.7 million and increased Husky’s holdings in the Saleski area to 239,200 acres.

In September, Husky acquired an exploration block in the North East Java Basin offshore Indonesia totalling 1.2 million acres. This increased Husky’s total holding in Indonesia to approximately 1.8 million acres.

In October 2006, Husky commissioned its Tucker oil sands project located 30 kilometres north-west of Cold Lake Alberta. The project employs a steam assisted gravity drainage recovery (“SAGD”) system with a plant that has a design rate capacity of 30 mbbls/day.

Subsequent Events

On January 15, 2007 Husky acquired an interest in three Exploration Licences (“EL”) in the Jeanne d’Arc Basin offshore Newfoundland and Labrador. Husky acquired a 100% interest in EL 1099 covering 61,376 acres, a 50% interest in EL 1100 covering 75,545 acres and a 50% interest in EL 1101 covering 51,914 acres. Husky committed to spend $23.5 million on these EL areas during the next five years.

Events expected to occur during 2007

Husky expects construction of its 130 million litre per year ethanol plant at Minnedosa, Manitoba to be completed by the third quarter and fully operational in the fourth quarter of 2007.

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BUSINESS ENVIRONMENT TRENDS

There are a number of trends that are developing, which may have both long and short-term effects on the oil and gas industry in Canada. Conventional production of crude oil in the Western Canada Sedimentary Basin (“WCSB”) has been in decline since 2000 and will, according to industry forecasts⁽¹⁾, continue to decline. Since 2000 increased crude oil production from the WCSB has come from mining and in-situ production of bitumen and heavy crude oils. Non-conventional production of crude oil is forecast⁽¹⁾ to increase overall crude oil production from the WCSB beyond current production levels. Natural gas discoveries in the WCSB have, in the past few years, been made in smaller reservoirs. Natural gas exploration efforts in the WCSB are focused on the traditionally less accessible areas in the overthrust belt along the eastern slope of the Rocky Mountains, in the Northwest Territories, offshore the East Coast of Canada, smaller shallow gas deposits and coal bed methane.

The trend of volatile commodity prices continues and it is expected will continue. Natural gas prices are sensitive to regional supply/demand imbalances, regional industrial activity levels, weather patterns and access to cheaper sources of energy. Oil prices are dependent on the world economy and stable supply. As a result of numerous supply disruptions and increased demand from emerging economies oil prices have remained historically high. However, notwithstanding supply disruptions or major policy changes in respect of greenhouse gas emissions, recent forecasts by the Energy Information Administration (“EIA”) in the United States indicates the possibility of crude oil production capacity increasing significantly over the next two and a half decades, particularly from Saudi Arabia, Russia, Africa and South America. The EIA also expect that petroleum will account for roughly the same proportion of the total energy supply. In terms of crude oil prices the EIA expects the price to remain, on average, at current levels in real terms (2007 dollars) or around the U.S. $60/bbl WTI (February 6, 2007 WTI spot U.S. $60/bbl). The EIA does not explicitly provide any forecast on the range of fluctuation that prices might be subjected to, however, there is no reason to assume any change in the historical pattern of significant price volatility.

Note:

(1)  “Canadian Crude Oil Production and Supply forecast,” July 2004, Canadian Association of Petroleum Producers “Oil Sands Technology Roadmap,” January 30, 2004, Alberta Chamber of Resources.

DESCRIPTION OF HUSKY’S BUSINESS

General

Husky is a publicly held integrated energy and energy related company headquartered in Calgary, Alberta.

Our business is conducted predominantly through three major business segments — upstream, midstream and refined products.

Upstream includes exploration for, development and production of crude oil, natural gas and natural gas liquids. The Company’s upstream operations are located primarily in Western Canada, offshore Eastern Canada, offshore China and offshore Indonesia.

Midstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (upgrading); marketing of the Company’s and other producers’ crude oil, natural gas, natural gas liquids, sulphur and petroleum coke; and pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and natural gas and cogeneration of electrical and thermal energy (infrastructure and marketing).

Refined products include refining of crude oil and marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products.

Upstream Operations

Husky’s portfolio of assets includes properties with reserves classified as light (30º API and lighter), medium (between 20º and 30º API), heavy (20º and heavier but lighter than 10º API) and bitumen (10º API and heavier) crude oil, natural gas liquids, natural gas and sulphur. As operator of the majority of its properties Husky exercises a high degree of control in its upstream operations. We have production, gathering and processing facilities throughout the WCSB. In the Lloydminster heavy oil prone area Husky has a well established position with concentrated landholdings, production, gathering and processing facilities, as well as heavy crude oil pipeline, upgrading and refining facilities.

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Reserves and Land Position

At December 31, 2006, our gross proved oil and gas reserves totalled 1,004 mmboe comprised of 287 mmbbls of light crude oil and NGL, 87 mmbbls of medium crude oil, 213 mmbbls of heavy crude oil, 60 mmbbls of bitumen and 2.1 bcf of natural gas. At December 31, 2006, our gross proved plus probable oil and gas reserves totalled 2,444 mmboe comprised of 428 mmbbls of light crude oil and NGL, 102 mmbbls of medium crude oil, 289 mmbbls of heavy crude oil, 1,187 mmbbls of bitumen and 2.5 bcf of natural gas. Our undeveloped landholdings in the Western Canada Sedimentary Basin totalled 6.9 million gross acres or 35% of our total gross undeveloped land holdings at December 31, 2006.

Properties

In the foothills and deep basin areas in Alberta, we operate the Ram River gas plant and have interests in properties that supply this plant including: Blackstone, Ricinus, Limestone, Clearwater, Benjamin, Brown Creek and Stolberg. We also have an interest in the Caroline gas plant and field. Further north we have interests in the Valhalla and Wapiti crude oil and natural gas fields near Grand Prairie and properties in the Galloway, Ansell and Edson area. In north-eastern British Columbia, we hold natural gas interests in the Sikanni and Federal area as well as Boundary Lake.

In the plains region of north-west Alberta, we operate the Rainbow Lake Plant, miscible floods and properties in surrounding areas. We have interests in the Peace River Arch, Boyer, Marten Hills and Cherpeta areas. In the east central region of Alberta, we have property holdings east of Calgary and around Red Deer and Edmonton including major properties at Hussar and Provost.

In southern Alberta and Saskatchewan, we have extensive property holdings around Taber and Brooks in southern Alberta and throughout south-west Saskatchewan at Shackleton/Lacadena, Cantaur, Fosterton and Carnduff.

On the East Coast of Canada, we hold a 72.5% working interest in the White Rose oil field, which was sanctioned by the co-venturers in March 2002 and produced first oil on November 12, 2005 and a 12.51% working interest in the Terra Nova oil field, which began producing light crude oil in January 2002. We also hold interests in several exploration and significant discovery licenses in the Jeanne d’Arc Basin.

We hold a 40% working interest in the Wenchang oil fields located offshore in the South China Sea. Production at the Wenchang oil fields began in July 2002. We also hold interests in six exploration blocks in the South China Sea and with an aggregate areal extent of approximately 6.2 million acres and one exploration block in the East China Sea of approximately 1.2 million acres.

Husky also holds an interest in a Production Sharing Contract located in the Madura strait offshore Java, Indonesia. We are currently negotiating a natural gas sales contract and upon execution of this sales contract and acquiring an extension of the Production Sharing Agreement we expect to commence development of the BD field. We also signed a Production Sharing Agreement that provides the exploration rights to the 1.1 million acre East Bawean II Block offshore Indonesia. The addition of East Bawean II brings our holdings in Indonesia to approximately 1.8 million acres.

We also hold a non-operated interest in a small crude oil production operation in the Shatirah field, onshore Libya.

Midstream Operations

Husky’s midstream operations include upgrading of heavy crude oil feedstock into synthetic crude oil, pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and natural gas, and cogeneration of electrical and thermal energy, and marketing of Husky’s and third party produced crude oil, natural gas, natural gas liquids, sulphur and petroleum coke.

Refined Products

Husky’s refined products operations include refining of heavy and light crude oil, marketing of refined petroleum products, including asphalt and alternate fuels, and processing of grain for ethanol production. Husky sells and distributes transportation fuels including ethanol blended fuels through independently operated Husky and Mohawk branded petroleum outlets, including service stations, truck stops and bulk distribution facilities located from the west coast of Canada to the eastern border of Ontario, some of which include 24 hour restaurants, convenience stores, service bays, car washes, fast food sales, bank machines and propane sales.

7

SOCIAL AND ENVIRONMENTAL POLICY

Husky’s environmental policy requires regular environmental audits to be conducted at its sites and facilities. Husky has established procedures designed to anticipate and minimize adverse effects of its operations on the environment and for continued compliance with environmental legislation and to minimize future and current costs. Husky’s policies apply equally to employees, subsidiaries and contractors.

RISK FACTORS

The following factors should be considered in evaluating Husky:

Adequacy of crude oil and natural gas prices

Husky’s results of operations and financial condition are dependent on the prices received for its crude oil and natural gas production. Lower prices for crude oil and natural gas could adversely affect the value and quantity of our oil and gas reserves. Husky has significant quantities of heavier grades of crude oil reserves that trade at a discount to light crude oil. Heavier grades of crude oil are typically more expensive to produce, process, transport and refine into high value refined products. Refining capacity for heavy crude oil is limited. As a result, wider price differentials could have adverse effects on financial performance and condition, and could reduce the value and quantities of our heavier crude oil reserves and could delay or cancel projects that involve the development of heavier crude oil resources.

Prices for crude oil are based on world supply and demand. Supply and demand can be affected by a number of factors including, but not limited to, actions taken by the Organization of Petroleum Exporting Countries (“OPEC”), non-OPEC crude oil supply, social conditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, prevailing weather patterns and the availability of alternate sources of energy.

Husky’s natural gas production is located entirely in Western Canada and is, therefore, subject to North American market forces. North American natural gas supply and demand is affected by a number of factors including, but not limited to, the amount of natural gas available to specific market areas, either from the well head or from storage facilities, prevailing weather patterns, the price of crude oil, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions.

Demand for Husky’s other products and services and the cost of required inputs

Husky’s results of operations and financial condition are dependent on the price of refinery feedstock, the price of energy, the demand for refined petroleum products and electrical power and the ability of Husky to recover the increased cost of these inputs from the customer. Husky is also dependent on the demand for Husky’s pipeline and processing capacity.

Husky’s ability to replace reserves

Husky’s future cash flow and cost of capital are dependent on its ability to replace its proved oil and gas reserves in a cost effective manner. Without economic reserve additions through exploration and development or acquisition Husky’s production and, therefore, cash flow will decline. Without adequate proved reserves Husky’s ability to fund development and other capital expenditures with external sources of funds is diminished.

Competition

The energy industry is currently experiencing high levels of activity, which is being driven by high commodity prices. The industry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production and gain access to markets. Husky competes with others to acquire additional prospective lands, to retain drilling capacity and field operating and construction services, to attract and retain experienced skilled management and oil and gas professionals, to obtain sufficient pipeline and other transportation capacity and to gain access to and retain adequate markets for Husky’s products and services. Husky’s ability to successfully complete development projects could be adversely affected by our inability to acquire economic supplies and services. Subsequent increases in the cost of supplies and services or delays in acquiring supplies and services could result in uneconomic projects. Husky’s competitors comprise all types of energy companies, some of which have greater resources.

Husky’s operations are susceptible to business interruption

Our operations are subject to various risks with respect to normal operating conditions. These risks comprise, but are not limited to, explosions, blowouts, cratering, fires, severe storms and adverse weather, all forms of marine perils, release

8

of toxic, combustible or explosive substances, all of which could cause loss of life, injury and destruction of public and Husky owned property.

The occurrence of any of the above listed events or others not listed could result in adverse financial performance and condition that may not be fully recoverable from our insurers.

Foreign Exchange Risk

Our results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky’s U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2006, 81% or $1.3 billion of our long-term debt was denominated in U.S. dollars.

Environmental risks

All phases of the oil and natural gas business are subject to environmental regulation pursuant to a variety of federal, provincial and municipal laws and regulations, as well as international conventions (collectively, “environmental legislation”).

Environmental legislation imposes, among other things, restrictions, liabilities, and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that wells, facilities and other properties associated with Husky’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean-up costs and damages. Husky cannot be certain that the costs of complying with environmental legislation in the future will not have a material adverse effect on Husky’s financial condition and results of operations.

Husky anticipates that changes in environmental legislation may require, among other things, reductions in emissions from its operations and result in increased capital expenditures. Further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on Husky’s financial condition and results of operations.

In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol, which requires the reduction of greenhouse gas emissions. On December 16, 2002, Canada ratified the Kyoto Protocol. This initiative may require Husky to significantly reduce greenhouse gas emissions at its operations such as carbon dioxide, which may increase capital expenditures. Details regarding the implementation of the Kyoto Protocol remain unclear.

Uncertainty of oil and gas proved reserves estimates

There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves, including many factors beyond Husky’s control. The reserves information included in and incorporated by reference in this Annual Information Form are Husky’s estimates. In general, estimates of economically recoverable oil and natural gas reserves and the estimated future net cash flow therefrom are based on a number of variables in effect as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the actual effects of regulation by governmental agencies and the actual future commodity prices and operating costs, all of which may vary considerably from those in effect at the date the reserves were determined. The estimated quantities of reserves expected to be recovered are uncertain and the classification of reserves as proved is only an attempt to define the degree of certainty involved. For these reasons, estimates of economically recoverable oil and natural gas attributable to a particular group of properties, the classification of such reserves as proved and the resultant future net cash flow therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Husky’s

9

actual production, revenues, taxes and development, abandonment, and operating expenditures with respect to its estimated oil and natural gas reserves may vary from such estimates, and such variances could be material.

Estimates with respect to reserves that may be developed and produced in the future (proved developed reserves) are often based on volumetric calculations and upon analogy to similar types of reservoirs, 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 based upon production history may result in variations in the estimated reserves, which may be material.

UPSTREAM OPERATIONS

Disclosures of Oil and Gas Activities

In the tables that follow, light crude oil has an API gravity of 30º or more: medium crude oil has an API gravity of 21º or more and less than 30º: heavy crude oil has an API gravity of less than 21º.

Production

	2006
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil (mbbls/day)
Light crude oil and NGL		111.0		30.3		68.5		98.8		12.1		0.1
Medium crude oil		28.5		28.5		—		28.5		—		—
Heavy crude oil		108.1		108.1		—		108.1		—		—
Total gross		247.6		166.9		68.5		235.4		12.1		0.1
Total net		220.4		143.8		66.5		210.3		10.0		0.1
Natural Gas (mmcf/day)
Gross		672.3		672.3		—		672.3		—		—
Net		528.2		528.2		—		528.2		—		—

	2005
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil (mbbls/day)
Light crude oil and NGL		64.6		31.3		17.2		48.5		16.0		0.1
Medium crude oil		31.1		31.1		—		31.1		—		—
Heavy crude oil		106.0		106.0		—		106.0		—		—
Total gross		201.7		168.4		17.2		185.6		16.0		0.1
Total net		175.7		146.0		15.1		161.1		14.5		0.1
Natural Gas (mmcf/day)
Gross		680.0		680.0		—		680.0		—		—
Net		488.5		488.5		—		488.5		—		—

10

Production (continued)

	2004
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil (mbbls/day)
Light crude oil and NGL		66.2		32.7		13.7		46.4		19.7		0.1
Medium crude oil		35.0		35.0		—		35.0		—		—
Heavy crude oil		108.9		108.9		—		108.9		—		—
Total gross		210.1		176.6		13.7		190.3		19.7		0.1
Total net		183.9		153.0		13.2		166.2		17.6		0.1
Natural Gas (mmcf/day)
Gross		689.2		689.2		—		689.2		—		—
Net		524.0		524.0		—		524.0		—		—

Note:

(1)  Gross volumes are Husky’s lessor royalty, overriding royalty and working interest share of production before deduction of royalties. Net volumes are Husky’s gross volumes, less royalties.

Revenue

	2006
			Western		East
	Total		Canada		Coast		Canada		China		Libya
	($ millions)
Crude Oil
Light crude oil and NGL		2,799		691		1,779		2,470		324		5
Medium crude oil		515		515		—		515		—		—
Heavy crude oil		1,575		1,575		—		1,575		—		—
Total gross		4,889		2,781		1,779		4,560		324		5
Total net		4,357		2,352		1,731		4,083		270		5
Natural Gas
Gross		1,601		1,601		—		1,601		—		—
Net		1,319		1,319		—		1,319		—		—
Processing/Transportation		96		69		27		96		—		—

	2005
			Western		East
	Total		Canada		Coast		Canada		China		Libya
	($ millions)
Crude Oil
Light crude oil and NGL		1,450		686		392		1,078		369		3
Medium crude oil		493		493		—		493		—		—
Heavy crude oil		1,203		1,203		—		1,203		—		—
Total gross		3,146		2,382		392		2,774		369		3
Total net		2,713		2,020		355		2,375		335		3
Natural Gas
Gross		2,000		2,000		—		2,000		—		—
Net		1,594		1,594		—		1,594		—		—
Processing/Transportation		61		58		3		61		—		—

11

Revenue (continued)

	2004
			Western		East
	Total		Canada		Coast		Canada		China		Libya
	($ millions)
Crude Oil
Light crude oil and NGL		967		474		148		622		343		2
Medium crude oil		462		462		—		462		—		—
Heavy crude oil		757		757		—		757		—		—
Total gross		2,186		1,693		148		1,841		343		2
Total net		1,824		1,375		139		1,514		308		2
Natural Gas
Gross		1,596		1,596		—		1,596		—		—
Net		1,248		1,248		—		1,248		—		—
Processing/Transportation		48		48		—		48		—		—

Sales Prices

	2006
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil ($/bbl)
Light crude oil and NGL		69.06		62.46		71.18		68.50		73.58		74.96
Medium crude oil		49.48		49.48		—		49.48		—		—
Heavy crude oil		39.92		39.92		—		39.92		—		—
Total crude oil and NGL		54.08		45.64		71.18		53.07		73.58		74.96
Natural Gas ($/mcf)		6.47		6.47		—		6.47		—		—

	2005
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil ($/bbl)
Light crude oil and NGL		61.56		60.15		62.61		61.02		63.15		69.23
Medium crude oil		43.44		43.44		—		43.44		—		—
Heavy crude oil		31.09		31.09		—		31.09		—		—
Total crude oil and NGL		42.75		38.77		62.61		40.97		63.15		69.23
Natural Gas ($/mcf)		7.96		7.96		—		7.96		—		—

	2004
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil ($/bbl)
Light crude oil and NGL		48.34		49.35		47.87		49.64		47.66		57.88
Medium crude oil		36.13		36.13		—		36.13		—		—
Heavy crude oil		28.66		28.66		—		28.66		—		—
Total crude oil and NGL (before hedging)		36.07		33.85		47.87		34.90		47.66		57.88
Total crude oil and NGL (after hedging)		28.43		26.19		29.45		26.42		47.66		57.88
Natural Gas ($/mcf)
Before hedging		6.25		6.25		—		6.25		—		—
After hedging		6.24		6.24		—		6.24		—		—

12

Capital Expenditures

	2006
			Western		East
	Total		Canada		Coast		Canada		China		Indonesia		Libya
	($ millions)
Property acquisition		193		192		1		193		—		—		—
Exploration		774		618		79		697		71		6		—
Development		1,660		1,361		279		1,646		14		5		1
		2,633		2,171		359		2,536		85		11		1

	2005
			Western		East
	Total		Canada		Coast		Canada		China		Indonesia		Libya
	($ millions)
Property acquisition		133		133		—		133		—		—		—
Exploration		445		324		66		390		55		—		—
Development		2,152		1,550		579		2,129		14		8		1
		2,730		2,007		645		2,652		69		8		1

	2004
			Western		East
	Total		Canada		Coast		Canada		China		Indonesia		Libya
	($ millions)
Property acquisition(1)		116		54		—		54		—		62		—
Exploration		313		271		24		295		18		—		—
Development		1,728		1,208		515		1,723		5		—		—
		2,157		1,533		539		2,072		23		62		—

Note:

(1)  Does not include the acquisition of Temple Exploration Inc.

13

Oil and Gas Netbacks⁽¹⁾

	2006
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil ($/bbl)
Light crude oil
Sales revenue		68.51		59.89		71.18		67.87		73.58		74.96
Royalties		4.49		7.34		1.95		3.52		12.33		—
Operating costs		6.96		11.89		5.48		7.36		3.61		18.51
Netback		57.06		40.66		63.75		56.99		57.64		56.45
Medium crude oil
Sales revenue		48.97		48.97		—		48.97		—		—
Royalties		8.61		8.61		—		8.61		—		—
Operating costs		13.09		13.09		—		13.09		—		—
Net back		27.27		27.27		—		27.27		—		—
Heavy crude oil
Sales revenue		39.91		39.91		—		39.91		—		—
Royalties		5.16		5.16		—		5.16		—		—
Operating costs		11.10		11.10		—		11.10		—		—
Netback		23.65		23.65		—		23.65		—		—
Total crude oil
Sales revenue		53.55		44.90		71.18		52.51		73.58		74.91
Royalties		5.28		6.14		1.95		4.92		12.33		—
Operating costs		9.53		11.60		5.48		9.83		3.61		18.51
Netback		38.74		27.16		63.75		37.76		57.64		56.45
Natural Gas ($/mcf)
Sales revenue		6.65		6.65		—		6.65		—		—
Royalties		1.37		1.37		—		1.37		—		—
Operating costs		1.18		1.18		—		1.18		—		—
Netback		4.10		4.10		—		4.10		—		—
Equivalent Unit ($boe)
Sales revenue		49.34		42.91		71.18		48.58		73.58		74.91
Royalties		6.19		6.97		1.95		5.99		12.33		—
Operating costs		8.77		9.79		5.48		8.98		3.61		18.51
Netback		34.38		26.15		63.75		33.61		57.64		56.45

Note:

(1)  Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification.

14

Oil and Gas Netbacks⁽¹⁾ (continued)

	2005
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil ($/bbl)
Light crude oil
Sales revenue		61.86		60.74		62.61		61.41		63.15		69.23
Royalties		7.22		8.66		5.91		7.67		5.93		—
Operating costs		6.88		9.86		5.14		8.16		2.92		22.73
Netback		47.76		42.22		51.56		45.58		54.30		46.50
Medium crude oil
Sales revenue		43.67		43.67		—		43.67		—		—
Royalties		7.77		7.77		—		7.77		—		—
Operating costs		10.97		10.97		—		10.97		—		—
Net back		24.93		24.93		—		24.93		—		—
Heavy crude oil
Sales revenue		31.22		31.22		—		31.22		—		—
Royalties		3.75		3.75		—		3.75		—		—
Operating costs		9.90		9.90		—		9.90		—		—
Netback		17.57		17.57		—		17.57		—		—
Total crude oil
Sales revenue		42.83		38.91		62.61		41.08		63.15		69.23
Royalties		5.49		5.41		5.91		5.45		5.93		—
Operating costs		9.13		10.10		5.14		9.65		2.92		22.73
Netback		28.21		23.40		51.56		25.98		54.30		46.50
Natural Gas ($/mcf)
Sales revenue		8.02		8.02		—		8.02		—		—
Royalties		1.76		1.76		—		1.76		—		—
Operating costs		1.04		1.04		—		1.04		—		—
Netback		5.22		5.22		—		5.22		—		—
Equivalent Unit ($boe)
Sales revenue		44.56		42.53		62.61		43.69		63.15		69.23
Royalties		7.29		7.45		5.91		7.36		5.93		—
Operating costs		8.12		8.59		5.14		8.39		2.92		22.73
Netback		29.15		26.49		51.56		27.94		54.30		46.50

Note:

(1)  Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification.

15

Oil and Gas Netbacks⁽¹⁾ (continued)

	2004
			Western		East
	Total		Canada		Coast		Canada		China		Libya
Crude Oil ($/bbl)
Light crude oil
Sales revenue		46.95		46.12		47.87		46.63		47.66		57.88
Royalties		5.71		7.76		1.80		6.03		4.91		—
Operating costs		5.82		8.94		3.28		7.29		2.16		16.47
Netback before hedging		35.42		29.42		42.79		33.31		40.59		41.41
Medium crude oil
Sales revenue		36.20		36.20		—		36.20		—		—
Royalties		6.10		6.10		—		6.10		—		—
Operating costs		10.07		10.07		—		10.07		—		—
Netback before hedging		20.03		20.03		—		20.03		—		—
Heavy crude oil
Sales revenue		28.73		28.73		—		28.73		—		—
Royalties		3.38		3.38		—		3.38		—		—
Operating costs		9.33		9.33		—		9.33		—		—
Netback before hedging		16.02		16.02		—		16.02		—		—
Total crude oil
Sales revenue		35.72		33.48		47.87		34.50		47.66		57.88
Royalties		4.58		4.75		1.80		4.54		4.91		—
Operating costs		8.36		9.41		3.28		8.97		2.16		16.47
Netback before hedging		22.78		19.32		42.79		20.99		40.59		41.41
Netback after hedging		15.64		12.25		24.37		13.11		40.59		41.41
Natural Gas ($/mcf)
Sales revenue		6.25		6.25		—		6.25		—		—
Royalties		1.44		1.44		—		1.44		—		—
Operating costs		0.89		0.89		—		0.89		—		—
Netback before hedging		3.92		3.92		—		3.92		—		—
Netback after hedging		3.91		3.91		—		3.91		—		—
Equivalent Unit ($boe)
Sales revenue		36.34		35.01		47.87		35.60		47.66		57.88
Royalties		5.96		6.22		1.80		6.03		4.91		—
Operating costs		7.32		7.85		3.28		7.66		2.16		16.47
Netback		23.06		20.94		42.79		21.91		40.59		41.41

Note:

(1)  Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification.

16

Producing Wells

	Oil Wells				Natural Gas Wells				Total
	Gross(1)(2)		Net(1)		Gross(1)(2)		Net(1)		Gross(1)(2)		Net(1)
Canada
Alberta		4,390		3,395		5,385		4,235		9,775		7,630
Saskatchewan		5,076		4,118		1,084		1,028		6,160		5,146
British Columbia		203		57		219		150		422		207
Newfoundland		21		6		—		—		21		6
North West Territories		5		1		5		1		10		2
		9,695		7,577		6,693		5,414		16,388		12,991
International
China		27		11		—		—		27		11
Libya		2		1		—		—		2		1
		29		12		—		—		29		12
As at December 31, 2006		9,724		7,589		6,693		5,414		16,417		13,003
Canada
Alberta		4,308		3,341		4,658		3,794		8,966		7,135
Saskatchewan		4,567		3,644		922		826		5,489		4,470
British Columbia		224		78		183		122		407		200
Manitoba		17		4		—		—		17		4
Newfoundland		5		1		5		1		10		2
Northwest Territories		9,121		7,068		5,768		4,743		14,889		11,811
International
China		24		10		—		—		24		10
Libya		2		1		—		—		2		1
		26		11		—		—		26		11
As at December 31, 2005		9,147		7,079		5,768		4,743		14,915		11,822

Notes:

(1)	The number of gross wells is the total number of wells in which Husky owns a working interest. The number of net wells is the sum of the fractional interests owned in the gross wells. Producing wells were producing or capable of producing at December 31.
(2)	The above table does not include producing wells in which Husky has no working interest but does have a royalty interest. At December 31, 2006 Husky had a royalty interest in 4,047 wells of which 1,605 were oil producers and 2,442 were gas producers.
(3)	For purposes of the above table, multiple completions are counted as a single well. Where one of the completions in a given well is an oil completion, the well is classified as an oil well. In 2006, there were 210 gross, 188 net oil wells and 416 gross, 353 net natural gas wells which were completed in two or more formations and from which production is not commingled.

17

Landholdings

Developed Acreage

	Gross		Net
	(thousands of acres)
As at December 31, 2006
Western Canada
Alberta		3,235		2,709
Saskatchewan		592		531
British Columbia		185		114
Manitoba		—		—
		4,012		3,354
Northwest Territories and Arctic		7		1
Eastern Canada		35		4
		4,054		3,359
China		17		7
Libya		7		2
		4,078		3,368
As at December 31, 2005
Western Canada
Alberta		3,146		2,633
Saskatchewan		577		517
British Columbia		182		112
Manitoba		—		—
		3,905		3,262
Northwest Territories and Arctic		7		1
Eastern Canada		35		4
		3,947		3,267
China		17		7
Libya		7		2
		3,971		3,276

Undeveloped Acreage

	Gross		Net
	(thousands of acres)
As at December 31, 2006
Western Canada
Alberta		4,358		3,841
Saskatchewan		1,654		1,513
British Columbia		906		639
Manitoba		1		1
		6,919		5,994
Northwest Territories and Arctic		884		239
Eastern Canada		2,591		1,786
		10,394		8,019
China		7,637		3,742
Indonesia		1,742		1,742
		19,773		13,503

18

	Gross		Net
	(thousands of acres)
Landholdings (continued) Undeveloped Acreage
As at December 31, 2005
Western Canada
Alberta		4,518		3,998
Saskatchewan		1,715		1,577
British Columbia		862		615
Manitoba		2		2
		7,097		6,192
Northwest Territories and Arctic		664		180
Eastern Canada		3,722		2,927
		11,483		9,299
China		5,590		2,739
Indonesia		690		690
		17,763		12,728

Drilling Activity

	Year ended December 31
	2006				2005				2004
	Gross		Net		Gross		Net		Gross		Net
Western Canada Drilling
Exploration
Oil		101		99		89		85		45		39
Gas		330		192		392		196		234		180
Dry		26		24		36		36		34		33
		457		315		517		317		313		252
Development
Oil		590		543		466		433		552		499
Gas		565		490		610		551		807		740
Dry		25		22		42		39		57		53
		1,180		1,055		1,118		1,023		1,416		1,292
		1,637		1,370		1,635		1,340		1,729		1,544

Present Activities

	Exploratory				Development
	Gross		Net		Gross		Net
Wells Drilling(1)
Western Canada		8		7		14		13
East Coast		—		—		2		1
		8		7		16		14

Note:

(1)  Denotes wells that were drilling at December 31, 2006.

19

Oil and Gas Reserves Disclosures

Husky’s oil and gas reserves as of December 31, 2006 are based on prices and costs in effect on that date and remain constant in future periods in accordance with the Financial Accounting Standards Board and the Securities and Exchange Commission (U.S.) as prepared internally by Husky’s reserves evaluation staff. Husky uses a formalized process for determining, approving and booking reserves. This process provides for all reserves evaluation to be done on a consistent basis using established definitions and guidelines. Approval of any significant reserve additions and changes requires review by an internal panel of qualified reserves evaluators.

Audit of Oil and Gas Reserves

McDaniel & Associates Consultants Ltd., an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit of Husky’s crude oil, natural gas and natural gas products reserves. McDaniel & Associates Consultants Ltd. issued an audit opinion stating that Husky’s internally generated proved and probable reserves and net present values based on forecast and constant price assumptions are, in aggregate, reasonable, and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices in the United States and as set out in the Canadian Oil and Gas Evaluation Handbook.

Proved Reserves

									Future Net Cash
									Flows Before
	Crude Oil & NGL(1)				Natural Gas(1)				Tax(1)(4)
	Gross(2)		Net(2)		Gross(2)		Net(2)		0%		10%
	(mmbbls)				(bcf)				($ millions)
Proved developed(3)		518		454		1,703		1,424		20,135		13,158
Proved undeveloped(3)(5)		129		113		440		375		3,293		1,668
Proved total(3)		647		567		2,143		1,799		23,428		14,826

Notes:

(1)	Husky applied for and was granted an exemption from National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” to provide oil and gas reserves disclosures in accordance with the U.S. Securities and Exchange Commission guidelines and the U.S. Financial Accounting Standards Board disclosure standards. The information disclosed may differ from information prepared in accordance with National Instrument 51-101. Husky’s internally generated oil and gas reserves data was audited by an independent firm of qualified reserves evaluators.
(2)	Gross reserves are Husky’s lessor royalty, overriding royalty and working interest share of reserves, before deduction of royalties. Net reserves are gross reserves, less royalties.
(3)	These reserve categories have the same meanings as those set out in SEC Regulation S-X.
(4)	The discounted future net cash flows at December 31, 2006 were based on the year-end spot NYMEX natural gas price of U.S. $5.51/mmbtu and on a spot WTI crude oil price of U.S. $60.85/bbl.
(5)	Estimated future capital expenditures required to gain access to proved undeveloped reserves as at December 31, 2006 and 2005 were as follows:

	As at December 31, 2006
	Total		2007		2008		2009		2010		2011		Thereafter
	($ millions undiscounted)
Western Canada		1,725		558		573		263		100		96		135
Eastern Canada		—		—		—		—		—		—		—
		1,725		558		573		263		100		96		135

	As at December 31, 2005
	Total		2006		2007		2008		2009		2010		Thereafter
Western Canada		1,428		545		353		191		116		56		167
Eastern Canada		109		87		—		—		—		—		22
		1,537		632		353		191		116		56		189

(6)  On December 31, 2006, the date our oil and gas reserves were evaluated, the calculated price of Lloydminster heavy crude oil was $39.17 per barrel. Our heavy crude oil reserves were economic at that price and no negative price revision resulted.

20

Reconciliation of Proved Gross Reserves

	Canada																		International				Total
																East
	Western Canada															Coast							Light
Proved reserves,	Light Crude			Medium			Heavy			Natural						Light			Crude Oil			Natural	Crude Oil			Natural
before royalties(1)	Oil & NGL			Crude Oil			Crude Oil			Gas			Bitumen			Crude Oil			& NGL			Gas	& NGL			Gas
	(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(mmbbls)			(mmbbls)			(bcf)	(mmbbls)			(bcf)
End of 2003		173			94			227			2,059						26			24				544			2,059
Revisions		1			1			(114	)		(23	)					(1	)		3				(110	)		(23	)
Purchases		1									23													1			23
Sales								(1	)		(14	)												(1	)		(14	)
Discoveries and extensions		7			2			32			372						24							65			372
Improved recovery		1			2			1			4						3							7			4
Production		(12	)		(13	)		(40	)		(252	)					(5	)		(7	)			(77	)		(252	)
End of 2004		171			86			105			2,169						47			20				429			2,169
Revisions		3			9			121			(65	)					9			2				144			(65	)
Purchases								7			3													7			3
Sales					(3	)		(4	)		(9	)												(7	)		(9	)
Discoveries and extensions		4			3			27			277			48			16			1				99			277
Improved recovery		1			7						9						23							31			9
Production		(12	)		(11	)		(39	)		(248	)					(6	)		(6	)			(74	)		(248	)
End of 2005		167			91			217			2,136			48			89			17				629			2,136
Revisions		(3	)		(1	)		(2	)		(87	)		(1	)		31			2				26			(87	)
Purchases		1			1						25													2			25
Sales		(1	)								(3	)												(1	)		(3	)
Discoveries and extensions		7			5			37			314			13										62			314
Improved recovery		6			1						3						12							19			3
Production		(11	)		(10	)		(39	)		(245	)					(25	)		(5	)			(90	)		(245	)
End of 2006		166			87			213			2,143			60			107			14				647			2,143

Note:

(1)  Proved reserves are the estimated quantities of crude oil, natural gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

21

Reserves and Production by Principal Area

	Gross
Crude Oil and NGL(1)	Proved Reserves		Production
	(mmbbls)		(mbbls/day)
Canada
Western Canada
British Columbia and Foothills
Alberta and BC Plains area		29.9		5.9
Foothills Deep Gas area		28.2		6.1
Ram River and Kaybob areas		6.2		2.4
Northwest Alberta Plains
Rainbow Lake area		78.3		7.6
Peace River Arch area		12.4		3.3
East Central Alberta
North area		2.3		0.6
South area		6.8		2.2
Provost area		29.4		14.3
Southern Alberta and Saskatchewan
South Alberta area		24.0		8.2
South Saskatchewan area		63.9		15.9
Lloydminster Area
Primary production		116.1		80.1
Thermal production		68.7		19.6
Oil Sands		60.1		0.0
Other		0.1		0.7
		526.4		166.9
East Coast Canada
Terra Nova		21.2		4.7
White Rose		85.8		63.8
		107.0		68.5
China
Wenchang		13.3		12.1
Other		0.3		0.1
		647.0		247.6

Note:

(1)  Gross crude oil and NGL reserves as at December 31, 2006 and average 2006 daily gross production of crude oil and NGL.

22

	Gross
Natural Gas(1)	Proved Reserves		Production
	(bcf)		(mmcf/day)
Canada
Western Canada
British Columbia and Foothills
Alberta and BC Plains area		147.6		55.5
Foothills Deep Gas area		336.9		92.1
Ram River and Kaybob areas		245.5		73.3
Northwest Alberta Plains
Rainbow Lake area		446.4		89.0
Peace River Arch		126.0		41.8
Northern Alberta area		39.5		21.1
East Central Alberta
Provost area		74.2		24.2
North area		197.1		51.3
South area		222.1		74.4
Southern Alberta and Saskatchewan
South Alberta area		47.9		25.5
South Saskatchewan area		186.4		65.5
Lloydminster Area		73.2		50.5
Other		—		8.1
		2,142.8		672.3

Note:

(1)  Gross natural gas reserves as at December 31, 2006 and average 2006 daily gross production of natural gas.

23

Probable Oil and Gas Reserves⁽¹⁾

Crude Oil & NGL

	Canada
	Western Canada
	Conventional		Bitumen		East Coast		International		Total
	(mmbbls)
2006		144		1,127		79		9		1,359
2005		146		903		118		13		1,180
2004		113		79		156		13		361

Natural Gas

	Canada
	Western Canada
	Conventional		International		Total
	(bcf)
2006		390		93		483
2005		407		167		574
2004		388		167		555

Barrels of Oil Equivalent

	Canada
	Western Canada
	Conventional		Bitumen		East Coast		International		Total
	(mmboe)
2006		209		1,127		79		25		1,440
2005		213		903		118		41		1,275
2004		177		79		156		41		453

Notes:

(1)	The probable reserves presented have been prepared, using constant prices and costs, in accordance with NI 51-101.
(2)	Bitumen reserves were based on constant prices calculated in accordance with the Canadian Securities Administrators Staff Notice 51-315 Guidance Regarding the Determination of Constant Prices for Bitumen Reserves under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (the “Staff Notice”). Bitumen reserves at December 31, 2004 remain classified as probable reserves because the pricing formula in the Staff Notice results in an economically viable price as at that date whereas 37 mmbbls of heavy oil reserves were subtracted from probable reserves due to low December 31, 2004 heavy oil prices under the constant pricing calculation applicable to heavy oil, which differed from the bitumen calculation. See “Disclosure of Exemption under National Instrument 51-101” for further discussion.
(3)	Proved and probable bitumen reserves are included under the caption Western Canada.
(4)	The SEC generally permits oil and gas registrants to disclose only reserves that meet the standards for proved reserves. Due to the higher uncertainty associated with probable reserves, disclosure or reference to probable reserves does not meet the standards for the inclusion in a document filed with the SEC. The disclosure of probable reserves is included herein in accordance with certain undertakings made in an exemption order granted to Husky pursuant to Part 8 of the Companion Policy to NI 51-101.

24

Statement of Financial Accounting Standards No. 69 — Disclosure about Oil and Gas Producing Activities

The following disclosures have been prepared in accordance with FASB Statement No. 69 “Disclosures about Oil and Gas Producing Activities” (“FAS 69”):

Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

Canadian provincial royalties are determined based on a graduated percentage scale, which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and our estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause our share of future production from Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2006, no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

Results of Operations for Producing Activities

Results of operations for	Canada						International						Total
producing activities(1)(2)	2006		2005		2004		2006		2005		2004		2006		2005		2004
					($ millions except per boe amounts)
Oil and gas production revenue		5,567		4,085		2,866		274		337		310		5,841		4,422		3,176
Operating costs
Lease operating expenses		1,215		925		874		22		18		17		1,237		943		891
Production taxes		69		56		56		—		—		—		69		56		56
Asset retirement obligation accretion		37		28		23		—		—		—		37		28		23
		1,321		1,009		953		22		18		17		1,343		1,027		970
Depreciation, depletion and amortization		1,426		1,102		1,018		50		42		59		1,476		1,144		1,077
Earnings before taxes		2,820		1,974		895		202		277		234		3,022		2,251		1,129
Income tax		982		730		349		72		106		92		1,054		836		441
Results of operations		1,838		1,244		546		130		171		142		1,968		1,415		688
Amortization rate per gross boe		11.24		10.10		9.11		11.24		7.21		8.19		11.24		9.95		9.06
Amortization rate per net boe		13.09		12.45		10.97		13.50		7.96		9.13		13.10		12.19		10.85

Notes:

(1)	The costs in this schedule exclude corporate overhead, interest expense and other operating costs, which are not directly related to producing activities.
(2)	Under U.S. GAAP, the depreciation, depletion and amortization for Canadian producing activities for 2006 amounted to $1,362 million (2005 — $1,036 million; 2004 — $981 million). Income taxes for Canadian producing activities under U.S. GAAP for 2006 amounted to $1,005 million (2005 — $755 million; 2004 — $364 million).

25

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

	Canada		International			Total
	($ millions)
2006
Property acquisition
Proved		97		—			97
Unproved		96		—			96
Exploration		697		77			774
Development		1,637		20			1,657
Capitalized interest		23		—			23
Total costs incurred(1)		2,550		97			2,647
Less: Proved acquisitions		97		—			97
Capitalized interest		23		—			23
Finding and development costs		2,430		97			2,527
Note:
(1) Asset retirement obligation incurred		45		—			45
2005
Property acquisition
Proved		68		—			68
Unproved		65		—			65
Exploration		390		55			445
Development		2,042		23			2,065
Capitalized interest		112		—			112
Total costs incurred(1)		2,677		78			2,755
Less: Proved acquisitions		68		—			68
Capitalized interest		112		—			112
Finding and development costs		2,497		78			2,575
Note:
(1) Asset retirement obligation incurred		51		—			51
2004
Property acquisition
Proved(2)		101		—			101
Unproved(3)		91		62			153
Exploration		295		18			313
Development		1,712		4			1,716
Capitalized interest		75		—			75
Total costs incurred(3)		2,274		84			2,358
Less: Proved acquisitions		101		—			101
Capitalized interest		75		—			75
Finding and development costs		2,098		84			2,182
Notes:
(1) Corporate acquisitions		98		—			98
(2) Corporate acquisitions		40		—			40
(3) Asset retirement obligation incurred		90		(1	)		89

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

Exploration costs include the costs of geological and geophysical activity, retaining undeveloped properties and drilling and equipping exploration wells.

26

Development costs include the costs of drilling and equipping development wells, facilities to extract, treat and gather and store oil and gas and settle the related asset retirement obligations.

Exploration and development costs include administrative costs and depreciation of support equipment directly associated with these activities.

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2006, by the year in which the costs were incurred:

									Prior to
Withheld Costs	Total		2006		2005		2004		2004
	($ millions)
Property acquisitions
Canada		154		97		57		—
International		63		—		—		63
		217		97		57		63
Exploration
Canada		798		398		288		30		82
International		70		70		—		—		—
		868		468		288		30		82
Development
Canada		881		478		399		4		—
International		33		5		6				22
		914		483		405		4		22
Capitalized interest
Canada		98		58		39		1
		2,097		1,106		789		98		104

Capitalized Costs Relating to Oil and Gas Producing Activities

	Canada		International		Total
	($ millions)
2006
Proved properties		19,087		586		19,673
Unproved properties		1,932		165		2,097
		21,019		751		21,770
Accumulated DD&A		8,141		404		8,545
Net Capitalized Costs(1)		12,878		347		13,225
2005
Proved properties		16,195		528		16,723
Unproved properties		2,317		127		2,444
		18,512		655		19,167
Accumulated DD&A		6,729		354		7,083
Net Capitalized Costs(1)		11,783		301		12,084
2004
Proved properties		13,624		458		14,082
Unproved properties		2,399		129		2,528
		16,023		587		16,610
Accumulated DD&A		5,722		311		6,033
Net Capitalized Costs(1)		10,301		276		10,577

Note:

(1)  The net capitalized costs for Canadian oil and gas exploration, development and producing activities under U.S. GAAP for 2006 was $12,449 million (2005 — $11,290 million, 2004 — $9,721 million). The net capitalized costs for International property oil and gas exploration,

27

development and producing activities under U.S. GAAP for 2006 was $346 million (2005 — $300 million, 2004 — $274 million). Please refer to note 19 to the Consolidated Financial Statements for an explanation of the differences between Canadian and U.S. GAAP for oil and gas activities.

Oil and Gas Reserve Information

In Canada, our proved crude oil, natural gas liquids and natural gas reserves are located in the provinces of Alberta, Saskatchewan and British Columbia, and offshore the East Coast. Our international proved reserves are located in China and Libya.

	Canada						International					Total
	Crude			Natural			Crude			Natural		Crude			Natural
	Oil & NGL			Gas			Oil & NGL			Gas		Oil & NGL			Gas
Reserves	(mmbbls)			(bcf)			(mmbbls)			(bcf)		(mmbbls)			(bcf)
Net proved reserves(1)(2)(3)(4)
End of year 2003		463			1,717			22			—		485			1,717
Revisions		(105	)		(54	)		2			—		(103	)		(54	)
Purchases		1			17			—			—		1			17
Sales		(1	)		(12	)		—			—		(1	)		(12	)
Improved recovery		6			3			—			—		6			3
Discoveries and extensions		55			309			—			—		55			309
Production		(62	)		(192	)		(6	)		—		(68	)		(192	)
End of year 2004		357			1,788			18			—		375			1,788
Revisions		129			(75	)		2			—		131			(75	)
Purchases		6			2			—			—		6			2
Sales		(7	)		(7	)		—			—		(7	)		(7	)
Improved recovery		29			6			—			—		29			6
Discoveries and extensions		94			230			1			—		95			230
Production		(59	)		(173	)		(5	)		—		(64	)		(173	)
End of year 2005		549			1,771			16			—		565			1,771
Revisions		9			(71	)		—			—		9			(71	)
Purchases		2			21			—			—		2			21
Sales		—			(2	)		—			—		—			(2	)
Improved recovery		16			2			—			—		16			2
Discoveries and extensions		56			267			—			—		56			267
Production		(77	)		(189	)		(4	)		—		(81	)		(189	)
End of year 2006		555			1,799			12			—		567			1,799
Net proved developed reserves,(1)(2)(3)(4)
End of year 2003		372			1,423			23			—		395			1,423
End of year 2004		299			1,436			18			—		317			1,436
End of year 2005		327			1,413			15			—		342			1,413
End of year 2006		442			1,424			12			—		454			1,424

Notes:

(1)	Net reserves are the Company’s lessor royalty, overriding royalty and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.
(2)	Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations from a given date forward, by known technology, under existing operating conditions and prices in effect at year end.
(3)	Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
(4)	Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by FAS 69 and based on crude oil and natural gas reserve and production volumes estimated by our reserves evaluation staff. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating Husky or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of Husky’s reserves.

The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2006 was based on the NYMEX year-end natural gas spot price of U.S. $5.51/mmbtu (2005 — U.S. $9.52/mmbtu; 2004 — U.S. $6.02/mmbtu) and on crude oil prices computed with reference to the year-end WTI spot price of U.S. $60.85/bbl (2005 — U.S. $61.06/bbl; 2004 — U.S. $43.36/bbl).

	Canada(1)						International(1)						Total(1)
Standardized Measure	2006		2005		2004		2006		2005		2004		2006		2005		2004
	($ millions)
Future cash inflows		37,006		40,066		22,681		900		999		979		37,906		41,065		23,660
Future production and development costs		14,321		13,430		9,353		157		122		148		14,478		13,552		9,501
Future income taxes		6,934		9,000		4,871		234		272		266		7,168		9,272		5,137
Future net cash flows		15,751		17,636		8,457		509		605		565		16,260		18,241		9,022
Annual 10% discount factor		6,045		7,115		3,712		93		123		105		6,138		7,238		3,817
Standardized measure of discounted
Future net cash flows		9,706		10,521		4,745		416		482		460		10,122		11,003		5,205

Note:

(1)  The schedules above are calculated using year-end prices, costs, statutory income tax rates and existing proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves

	Canada(1)									International(1)									Total(1)
	2006			2005			2004			2006			2005			2004			2006			2005			2004
	($ millions)
Present value at January 1		10,521			4,745			5,420			482			460			418			11,003			5,205			5,838
Sales and transfers, net of production costs		(4,318	)		(3,101	)		(1,952	)		(257	)		(320	)		(294	)		(4,575	)		(3,421	)		(2,246	)
Net change in sales and transfer prices, net of development and production costs		(1,672	)		5,585			555			126			155			197			(1,546	)		5,740			752
Extensions, discoveries and improved recovery, net of related costs		1,666			2,027			958			—			24			—			1,666			2,051			958
Revisions of quantity estimates		553			2,310			(1,318	)		(22	)		110			85			531			2,420			(1,233	)
Accretion of discount		1,601			762			877			70			68			61			1,671			830			938
Sale of reserves in place		(19	)		(62	)		(20	)		—			—			—			(19	)		(62	)		(20	)
Purchase of reserves in place		65			36			45			—			—			—			65			36			45
Changes in timing of future net cash flows and other		338			826			(233	)		(9	)		(13	)		17			329			813			(216	)
Net change in income taxes		971			(2,607	)		413			26			(2	)		(24	)		997			(2,609	)		389
Net increase (decrease)		(815	)		5,776			(675	)		(66	)		22			42			(881	)		5,798			(633	)
Present value at December 31		9,706			10,521			4,745			416			482			460			10,122			11,003			5,205

Note:

(1)  The schedules above are calculated using year-end prices, costs, statutory income tax rates and existing proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.

DESCRIPTION OF MAJOR PROPERTIES AND FACILITIES

Husky’s portfolio of assets upstream includes properties with reserves of light (30º API and lighter), medium (between 20º and 30º API), heavy (20º API and heavier but lighter than 10º API) and bitumen (10º API and heavier) gravity crude oil, NGL, natural gas and sulphur.

Lloydminster Heavy Oil and Gas

Husky’s heavy oil assets are concentrated in a large producing area in the Lloydminster Alberta/Saskatchewan region in the Canadian provinces of Saskatchewan and Alberta. We maintain a land position of approximately 1.6 million acres within this area, of which approximately 73% is undeveloped. Approximately 80% of Husky’s proved reserves in the region are contained in the heavy crude oil producing fields of Pikes Peak, Edam, Tangleflags, Celtic, Bolney, Westhazel, Big Gully, Hillmond, Mervin, Marwayne, Lashburn, Gully Lake and Rush Lake, and in the medium gravity crude oil producing fields of Wildmere and Wainwright. These fields contain accumulations of heavy crude oil at relatively shallow depths.

We currently produce from oil and gas wells ranging in depth from 450 to 650 metres and hold a 100% working interest in the majority of these wells. We produce heavy oil from the Lloydminster area using a variety of techniques, including standard primary production methods, as well as steam injection, horizontal well technology and steam assisted gravity drainage (“SAGD”). We have increased primary production from the area through cold production techniques which utilize progressive cavity pumps capable of simultaneous production of sand and heavy oil from unconsolidated formations. Our gross heavy and medium crude oil production from the area totalled 99.7 mbbls/day in 2006. Of the total production, 77.1 mbbls/day was primary production of heavy crude oil, 19.6 mbbls/day was production from our thermal operations at Pikes Peak (cyclic steam), Bolney/Celtic (SAGD) and the Lashburn pilot (SAGD), and 3.2 mbbls/day was from the medium gravity waterflooded fields in the Wainwright and Wildmere areas. We believe that the future growth from this area will be driven by primary heavy oil production and new thermal projects.

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In the Lloydminster area we own and operate 19 oil treating facilities, all of which are tied into our heavy oil pipeline systems. These pipeline systems transport heavy crude oil from the field locations to our Lloydminster asphalt refinery, to the Husky Lloydminster Upgrader and to the Enbridge Pipeline and Express Pipeline systems at Hardisty, Alberta.

We are focused on increasing our heavy oil production and believe that our undeveloped land position in the Lloydminster area, coupled with the application of improved technologies, a reduced cost structure and increased upgrading capacity, will provide sustained heavy oil production.

We also produce natural gas from numerous small shallow natural gas pools in the Lloydminster area (approximately 73 bcf of proved reserves). Our total gross natural gas production from the area during 2006 was 50.5 mmcf/day.

Lloydminster Area

British Columbia Foothills/Northwest Plains

Rainbow Lake District

Rainbow Lake, located approximately 700 kilometres north-west of Edmonton, Alberta, is the site of our largest light oil production operation in Western Canada. Husky operates a number of crude oil pools in the Rainbow basin, with an average working interest of 54%. Our production in this area is derived from more than 50 oil and gas pools.

We use secondary and tertiary oil recovery methods extensively in the Rainbow Lake district. These methods include injecting water, natural gas and NGL into the oil reservoirs to enhance crude oil recovery. The use of tertiary recovery programs, such as the miscible flood used at Rainbow Lake, has increased the estimated amount of recoverable crude oil-in-place from 50% to 70% of the original crude oil-in-place in certain pools. Historically only small volumes of gas and NGL have been marketed from the Rainbow Lake district prior to 2002. In 2003, we initiated the recovery of natural gas from several pools. NGL recovery is forecast to begin in the 2008-2010 timeframe and is expected to generate revenues as the crude oil production from the pools is completed. We use horizontal drilling techniques, including the re-

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entry of existing well bores, to maintain the level of crude oil production and to increase recovery rates. We plan to continue exploration efforts to supplement our development initiatives in the Rainbow Lake district. Husky’s gross production from this area averaged 7.5 mbbls/day of light crude oil and NGL and 31.5 mmcf/day of natural gas during 2006.

We hold a 50% interest in, and operate, the Rainbow Lake processing plant. The processing design rate capacity of the plant is 69 mbbls/day of crude oil and water and 230 mmcf/day of raw gas. The extraction design capacity is 17 mbbls/day of NGL.

Husky also has a 100% interest in a compression and dehydration facility at Bivouac that has a capacity to process 20 mmcf/day. In 2006 throughput at this facility averaged 15.6 mmcf/day. Our strategy in respect of this area is to drill and tie-in eight to ten development wells per year to fully load the facility.

We hold an interest in two significant non-operated properties in the Rainbow Lake district. They include the Ekwan/Sierra property in north-eastern British Columbia and the Bistcho/Cameron Hills property straddling the Alberta and Northwest Territories border. Our gross production from these properties currently averages 12.9 mmcf/day of natural gas and 278 bbls/day of liquid hydrocarbons. We also hold a working interest in the EnCana Sierra gas plant and the Paramount Bistcho gas plant. We are active in both these areas with development and exploration drilling. In these two areas we hold in excess of 200,000 acres of undeveloped land.

Slave Lake District

The Slave Lake district of northern Alberta, which includes the Slave Lake, Sawn Lake, Red Earth, Lubicon, Nipisi, Utikuma and other properties, has been primarily a light oil producing area located approximately 370 kilometres north-west of Edmonton. We operate and hold an average 80% working interest in several properties in this area. Gross production from these properties averaged 3.7 mbbls/day of crude oil and 25 mmcf/day of natural gas in 2006. The average working interest in these lands is 80%. Infrastructure includes a 100% working interest in a 30 mmcf/day sour gas plant and three oil batteries. Husky anticipates divesting properties averaging 3,200 gross bbls/day crude oil and 7 mmcf/day of natural gas targets in this area in the first half of 2007 due to high operating costs and limited development potential. We will retain our oil sands rights in the area and concentrate on primary bitumen production and new natural gas property development to replace divested production and reduce overall operating costs.

High Level District

The High Level district of Alberta is approximately 600 kilometres north-west of Edmonton, Alberta. We are the operator and hold close to 100% working interest in our properties. The area holds shallow Bluesky gas reservoirs that are characterized as low deliverability and low decline. Gross production from this area in 2006 averaged 29.0 mmcf/day of natural gas.

Athabasca District

The Athabasca district is located approximately 200 kilometres northeast of Edmonton, Alberta. Natural gas is produced from the Clearwater, Colony, McMurray and Wabasca or combination of these zones that lie at a depth of approximately 600 metres. In 2006, natural gas gross production from this district averaged 43.9 mmcf/day. The largest asset in the district is at Amadou, which consists of a 22 mmcf/day dehydration facility, 5,800 horsepower of compression and a gathering system which collects natural gas from an area four townships in size. Amadou gross production was 11.4 mmcf/day in 2006. Our plans for 2007 are to increase recompletions and work-overs to increase production and add reserves at low unit cost and take advantage of existing infrastructure and capacity.

Ram River District

The Ram River district is located in west central Alberta and includes the large Blackstone, Ricinus and Clearwater/Limestone natural gas fields.

The Blackstone field is the most prolific of these fields and contains four high deliverability natural gas wells, capable of combined raw gas production of 62 mmcf/day. We hold a 34% interest in two unitized wells, a 24% and a 50% interest, respectively, in two non-unit wells, and act as the contract operator of the Blackstone wells. Production from these wells is processed at the Ram River gas plant.

We hold an average 72% interest in, and are the operator of, the Ram River sour gas plant and related processing facilities. The Ram River plant has the capacity to process 622 mmcf/day of sour gas, resulting in sales gas capacity of

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525 mmcf/day. The plant also has the capacity to produce in excess of 2.8 mlt/day of sulphur from raw gas. During 2006, the plant operated at approximately 85% of its design rate capacity. The Ram River plant processes in excess of 10% of our total gross natural gas production, which includes an average of 38 mmcf/day of our gross production from the Blackstone, Brown Creek, Cordel and Stolberg fields and an average of 17.0 mmcf/day of our gross production from Ricinus and Clearwater/Limestone and Benjamin fields, in addition to processing third-party volumes. In addition, gross production from the Ferrier area, which is processed at other gas plants, averaged 13.2 mmcf/day of natural gas, bringing our total gross production of natural gas from the Ram River district to 68.5 mmcf/day in 2006. Our 2007 plans for the Ram River district include continued exploration and development along the Mississippian trend and evaluating deeper targets.

Our sour gas pipeline network supports the Ram River plant. We operate a network of 845 kilometres of sour gas pipelines in the Ram River district and hold a 30% interest in 684 kilometres of this pipeline system. The sour gas processed at the Ram River plant is produced from 18 sour gas fields located as far as 145 kilometres from the Ram River plant.

We believe that the Ram River plant and the extensive infrastructure of gathering pipelines, transmission systems and rail lines, which support the plant, represents a strategic base for the natural gas exploration and development planned by us in this part of the foothills region.

In addition, this region is an active exploration and production area for other producers and provides additional opportunities for generating revenue by processing third party natural gas. In 2006, with the addition of Shell Tay River gas volumes and continued success along the Chungo Mississippian trend, net processing income was $27.1 million.

Kaybob District

The Kaybob district consists of land located in the Fox Creek area of Alberta. The Kaybob district consists of four areas. The Kaybob South Beaverhill Lake Unit 1 (35.6% working interest), Kaybob South Triassic Unit 1 (40.5% working interest), Kaybob South Triassic Unit 2 (26.8% working interest), and non-unit lands (various working interests from gross overriding royalty to 100% working interest).

We have a 17.8% working interest in the sour portion and a 20.4% working interest in the sweet gas portion of the plant. We also have various working interests in sweet gas gathering and compression facilities in the area. Our gross production from the district during 2006 was 448 bbls/day of oil, 536 bbls/day of NGL and 10.7 mmcf/day of natural gas.

Alberta/British Columbia Plains District

Boundary Lake Area

We hold a 50% working interest in the Boundary Lake Gas Unit and a 34% and 19% interest in the Boundary Lake oil unit 1 and 2, respectively, in north-east British Columbia. Our natural gas production from this area is derived from five Belloy sour gas pools, and is processed at the nearby Boundary Lake processing plant. Our gross production from this area was 9.4 mmcf/day of natural gas and 1.6 mbbls/day crude oil and NGL during 2006.

Valhalla and Wapiti Area

We hold approximately 30% interest in three Valhalla oil units, a 100% interest in the Valhalla non-unit waterflood wells and a 100% interest in the Wapiti property. Production is primarily from the Doe Creek and Cardium zones and consists of light crude oil, NGL and natural gas. Our gross production from these properties averaged 3.2 mbbls/day of crude oil and NGL and 8.3 mmcf/day of natural gas in 2006. Our plans for this area in 2007 are to continue our horizontal injection well development program with six wells planned to improve waterflood conformance and arrest production decline in the main Doe Creek I pool.

Kakwa Area

We hold an average 60% working interest in oil and gas processing facilities and associated oil and gas gathering systems in the Kakwa area. Our gross production from this area was 14.0 mmcf/day of natural gas, 536 bbls/day NGL and 308 bbls/day of oil in 2006.

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Lynx, Copton and Grande Cache Areas

We continue to focus on exploration in the Lynx/Copton/Grande Cache areas of west Alberta drilling and completing two net wells, which maintained production during 2006 at 17 mmcf/day. We plan to continue to develop these properties in 2007 to maintain our gross production at between 15 mmcf/day to 20 mmcf/day.

Foothills West District

Caroline Area

We hold an 11% working interest in the 32,000 acre Caroline natural gas field located approximately 97 kilometres north-west of Calgary. The field has a high proportion of NGL and, as a result, the economics of this field are enhanced.

We also hold an 11% interest in the Caroline sour gas processing facility. The plant is presently running at a license limit of 78% of design capacity and is processing approximately 98 mmcf/day of total plant sales gas and 23 mbbls/day of NGL. Husky gross production was 2.6 mbbls/day NGL and 7.3 mmcf/day natural gas in 2006. Our plans for 2007 include re-drilling one producing gas well and installing a low pressure steam recovery unit to displace approximately one third of our external power consumption.

Edson Area

We hold and operate an average 85% working interest in two gas processing facilities and associated gas gathering systems in the Edson area. These properties averaged gross production of 32.2 mmcf/day of natural gas and 1.6 mbbls/day of NGL in 2006. Husky had a significant development program of 20 development wells in 2006 with plans to drill 20 wells in 2007 to increase production to 36 mmcf/day and improve drainage of the reservoir.

Sikanni and Federal Areas

We hold interests in properties in the Sikanni and Federal areas of north-east British Columbia, which averaged gross production of 15.0 mmcf/day of natural gas from five wells in 2006. The production flows through our gathering systems for processing at third party plants at Sikanni and McMahon.

Graham Area

We hold a 40% working interest in lands in the Graham area of north-eastern British Columbia. Our gross production from this area averaged 6.5 mmcf/day of gross natural gas sales in 2006. Production from the property is from one Halfway and seven Baldonnel pools. We also hold an interest in two 1,500 horsepower compressor stations and the non-operated Cypress gas plant. Plant capacity is 45 mmcf/day and the plant is currently operating at 80% capacity. We hold a 33.2% interest in the gas treating unit, 28.2% interest in the amine unit and 28% interest in the sulphur unit.

East Central Alberta

Athabasca District

The Athabasca district extends approximately 175 kilometres north of Edmonton, and from the Alberta-Saskatchewan border in the east, to the Alberta foothills in the west. The area target is predominantly shallow gas, ranging from 450-900 metres in the multi-zone Palaeozoic Mannville formation. The main producing areas are Athabasca, Craigend and Cold Lake. We operate 32 facilities with a pipeline system and an average working interest of 90% in the producing wells. We intend to continue to develop this area with infill, step out and exploratory wells to optimize recovery and develop new pools in order to keep the facilities operating at capacity. Our gross production from this area averaged 51.3 mmcf/day of natural gas and 600 bbls/day of crude oil in 2006.

Red Deer and Hussar Districts

The core of the Red Deer and Hussar districts is between Calgary, Drumheller and Sylvan Lake. Husky operates 21 facilities with gas gathering systems in these districts. Our gross production from this area averaged 74.3 mmcf/day of natural gas and 2.2 mmbbls/day of crude oil and NGL in 2006. We intend to continue to develop the natural gas potential of these districts with infill, step out and exploratory wells to optimize gas recovery and develop new pools in order to operate the facilities at capacity. We are involved in coal bed methane development in this area which had 505 wells drilled by year end 2006 and extensive facilities built. There were 420 wells tied-in by year-end that were producing gross 29 mmcf/day of natural gas. Our plans for 2007 include drilling 100 more wells to reach an expected gross 35 mmcf/day of natural gas.

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Provost District

The centre of the Provost district is approximately 240 kilometres south-east of Edmonton. It is predominantly a medium crude oil area that averaged gross production of 14.3 mbbls/day of crude oil and 24.1 mmcf/day of natural gas in 2006. We intend to increase oil drilling in many existing pools, focus on managing operating costs and improving oil recovery, as well as increase investment on natural gas exploration and development. In 2007, we intend to continue to develop several of our recent natural gas discoveries. There is significant competition in the area for land as well as infrastructure. We have a large land position and maintain close to a 100% working interest in most of our facilities.

Southern Alberta and Southern Saskatchewan

Southern Saskatchewan District

Husky is a prominent operator in southern Saskatchewan primarily producing medium gravity crude oil, with some natural gas and light crude oil. Gross production from our properties in this district averaged 16.0 mbbls/day of crude oil and 65.4 mmcf/day of natural gas during 2006.

We operate 31 oil batteries and eight gas facilities in the southern Saskatchewan district. The oil pools in this area are exploited using pressure maintenance and waterflood recovery operations.

At the Shackleton/Lacadena Milk River shallow gas project, 121 wells were drilled and tied in 2006. The project was producing at a rate of 54.0 mmcf/day of natural gas at December 31, 2006 from a total of 456 wells. In 2007, we plan to drill between 100 and 120 additional step out and infill wells.

Southern Alberta District

Taber and Brooks are our two major centres in southern Alberta. We operate 27 oil facilities and three natural gas facilities with an average working interest of 95%. Oil production is mainly medium gravity crude with the majority of reserves being supported by waterfloods or active aquifers. Natural gas production is from a mixture of deep and shallow formations. At Warner, near Taber, we operate a recently implemented alkaline-polymer flood to increase recovery from the Cretaceous Mannville reservoir and we are currently implementing additional floods at Crowsnest in 2007. Our gross production from this district averaged 8.4 mbbls/day of crude oil and 25.5 mmcf/day of natural gas during 2006.

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Oil Sands

Athabasca, Cold Lake and Peace River

Husky currently holds interests in 518,750 acres in the bitumen prone areas of Athabasca, Cold Lake and Peace River.

     Tucker

At Tucker, an in-situ SAGD oil sands project located 30 kilometres north-west of Cold Lake, Alberta, the first five well pairs, of a total 32 completed well pairs, were producing at the end of 2006. Warm-up steaming on the other well pairs on Pads A, B and C will continue. Tucker exited 2006 producing at 7.2 mbbls/day of bitumen. The facilities at Tucker have a design rate of 30 mbbls/day. Tucker will continue to ramp-up production for the next two years to plateau at its design rate.

     Sunrise

During 2006 the conceptual design progressed at the Sunrise in-situ SAGD oil sands project, which is located in the Athabasca region of Alberta. This aspect of the project includes the examination of options for field development, oil treatment, steam generation and has reached approximately 55% of completion. The entire front-end engineering design is expected to be complete by the third quarter of 2007.

We are currently completing seismic studies and have determined 29 stratigraphic test well locations for the remainder of the 2006/2007 winter drilling season. Collaboration with various industry participants continued on regional infrastructure issues, including an access road and airport.

The commercial project application submitted to the Alberta Energy and Utilities Board (AEUB) and Alberta Environment envisioned development to 200 mbbls/day in 50 mbbls/day phases. The application was approved by the AEUB on December 7, 2005.

     Saleski/Caribou

During 2006, we participated in three land sales and acquired oil sands leases totalling 84,320 acres in the Saleski area. We now hold 239,200 acres in this area, which is located approximately 120 kilometres west of Fort McMurray, Alberta. In December 2006 we submitted an application to the AEUB and Alberta Environment applications for the first phase of an in-situ project and have initiated the conceptual design phase of the project.

At Caribou we completed the selection of 44 stratigraphic test well locations, which will be drilled during the remainder of the 2006/2007 winter drilling season. At Saleski we completed selection of 13 stratagraphic test well locations, which will also be drilled during the remainder of the 2006/2007 drilling season. In addition, development planning continued in respect of water source and disposal wells for both Saleski and Caribou and the appropriate bitumen recovery technique for Saleski.

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     Oil Sands Leases

	Oil Sands		Gross		Net		Husky
General Location Name	Area		Acres		Acres		Operator
South Athabasca — overriding royalty		Athabasca		35,601		—		No
South Athabasca		Athabasca		22,032		11,656		Yes
Sunrise — In situ(1)		Athabasca		64,034		64,034		Yes
Misthae (Drowned, Martin Hills W. & Spur)		Athabasca		28,160		28,160		Yes
Saleski		Athabasca		239,200		239,200		Yes
Hoole — overriding royalty		Athabasca		47,040		—		No
Beaverdam		Cold Lake		11,520		11,520		Yes
Caribou(2)		Cold Lake		35,840		35,840		Yes
Lobstick		Cold Lake		37,120		37,120		Yes
Tucker(3)		Cold Lake		11,360		11,360		Yes
Panny (Senex & Welstead)		Peace River		47,360		47,360		Yes
Peace River (Cadotte Lake)		Peace River		11,840		11,840		Yes
Sawn Lake (Loon)		Peace River		20,480		20,480		Yes
				612,227		518,570

Notes:

(1)	Included in the gross and net amounts are an additional 6,400 acres of petroleum and natural gas rights held as protection acreage for gas over bitumen issues. In 2003, the Alberta regulatory authority issued General Bulletin GB 2003-28 that required natural gas wells within certain bitumen prone areas to be shut-in. The production of natural gas where natural gas reservoirs were believed to be in pressure contact with bitumen reserves was deemed to present an unacceptable risk to future in-situ bitumen production. Sunrise was formerly named Kearl.
(2)	Husky also has the exclusive right to acquire an additional 65,280 acres in the Caribou area.
(3)	Included in the gross and net amounts are an additional 1,280 acres of petroleum and natural gas rights held as protection acreage for gas over bitumen issues.

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Offshore East Coast — Canada

Husky’s offshore East Coast exploration and development program is focused in the Jeanne d’Arc Basin on the Grand Banks offshore the coast of Newfoundland and Labrador, which contains the Hibernia, Terra Nova and White Rose oil fields. We hold ownership interests in the Terra Nova and White Rose oil fields as well as in a number of smaller undeveloped fields in the central part of the basin and also hold significant exploration acreage.

White Rose Oil Field

The White Rose oil field, which we operate, is located 354 kilometres off the coast of Newfoundland and Labrador approximately 48 kilometres east of the Hibernia oil field on the eastern section of the Jeanne d’Arc Basin. Husky’s interest in the White Rose oil field is 72.5%. At plateau production, we estimate the oil field will average approximately 120 mbbls/day and Husky’s share is expected to average 87 mbbls/day on an annual basis. Husky’s share of proved plus probable light crude oil reserves for the field is estimated at 135.2 mbbls.

In November 2005, first oil was achieved at White Rose. The White Rose was the third oil field developed offshore Newfoundland and Labrador. On November 12, 2005 crude oil production was introduced into the process stream on the SeaRose FPSO (floating production, storage and offloading vessel). Initially, White Rose production was from three producing wells supported by six water injection wells and one gas injection well for natural gas storage. During 2006, development drilling included three production wells and two water injection wells for a total of 15 wells drilled at White Rose to date. At the end of 2006 the average total production per well was 21 mbbls/day. Our gross production was 23.3 mmbbls or an average of 63.8 mbbls/day during 2006.

Husky has chartered two shuttle tankers, the Heather Knutsen and the Jasmine Knutsen, to transport White Rose crude oil to market. The Samsung-designed double-hulled tankers each have a crude oil capacity of one million barrels.

During 2006, we drilled two successful delineation wells into adjacent Significant Discovery Licence (“SDL”) areas. The White Rose O-28 well encountered a 280 metre oil multi-layered column in the Ben Nevis Avalon formation on SDL 1024 in the western portion of the field and the North Amethyst K-15 well encountered a 50 to 55 metre oil column in the Ben Nevis formation on the SDL 1044 in the south west portion of the field. Both wells are expected to extend the production plateau of the White Rose field.

We are progressing with front-end engineering design on the southern extension of the White Rose field, discovered in 2003 by the delineation wells F-04 and the F-04Z located in the south portion of the SDL 1044. This area is expected to be developed and tied back to the SeaRose FPSO. Subject to regulatory approvals, production from this pool could be brought on stream by late 2009.

We have and will continue to consider technical options for the development of natural gas in the Jeanne d’Arc Basin. We intend to proceed with technical screening of a short list of proposed solutions and review of high level cost estimates. In parallel and pending rig availability, delineation drilling will improve estimates of the resource base ahead of future development. We will also continue to work with the Government of Newfoundland and Labrador as they develop a suitable fiscal regime during 2007.

Terra Nova Oil Field

The Terra Nova oil field is located approximately 350 kilometres south-east of St. John’s, Newfoundland and Labrador in 91 to 100 metres of water. The Terra Nova oil field is divided into three distinct areas, known as the Graben, the East Flank and the Far East. Our current pooled interest in the Terra Nova field is 12.51%. This interest is subject to change, pending re-determination once the field has been further delineated. Production at Terra Nova commenced in January 2002. Husky’s gross share of production in 2006 from the Terra Nova field was 1.7 mmbbls or an average 4.7 mbbls/day. Production in 2006 was approximately 60% lower than in 2005 due to downtime associated with equipment problems and a prolonged turnaround in which the Terra Nova FPSO underwent modifications and repairs at a dry dock in Europe.

As at December 31, 2006, there were 14 development wells drilled in the Graben area, eight production wells, three water injection wells and three gas injection wells. In the East Flank area there were 11 development wells including six production wells and five injection wells. Drilling operations are expected to continue into early 2007 based on a 36 well depletion plan for the Graben and East Flank areas. An extended reach well was drilled from the East Flank sub sea template to the Far East Central area in 2005 and production commenced during the first half of 2006. An injection well was drilled from the south east sub sea template in the East Flank to the central portion of the Far East in 2006 to provide waterflood support to the area. Drilling commenced in December 2006 on a Far East South delineation well, PF8,

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formerly the L-66 well. As at December 31, 2006, we had booked gross proved developed reserves of 21.4 mmbbls of light crude oil and 11.4 mmbbls of proved undeveloped reserves. These reserves are estimated to be capable of being produced using primary and secondary (waterflood and gasflood) production techniques.

East Coast Exploration

We believe that the areas offshore the Canadian East Coast have exploration potential, and that our position there will provide growth opportunities for light crude oil and natural gas in the medium to long-term. We presently hold working interests ranging from 5.33% to 72.5% in 16 SDL areas in the Jeanne d’Arc Basin. We also hold interests ranging from 17.1% to 19.4% in five SDL areas on the Labrador Shelf, a region that could be significant in the long-term for natural gas reserves.

The West Bonne Bay SDL 1040 is located in close proximity to the Terra Nova oil field. In 2006, under a farm-in arrangement with the operator of the SDL, we drilled the West Bonne Bay F-12 and a side track well, F-12Z, which further delineated the reservoir. Both wells encountered hydrocarbons in the Upper Hibernia formation. Further analysis of core, fluids samples and wireline logs is continuing to evaluate the resources present in the reservoir.

We operate nine Exploration Licences (“EL”) in the Jeanne d’Arc Basin. We hold 100% interest in seven ELs, 70% in one and 50% in the remaining EL. In 2006, we were successful bidders on three exploration parcels. We hold 100% of one of the parcels located south east of the White Rose oil field. The other two parcels are located south and east of the Terra Nova oil field and we hold 50% in both and we are non-operating partner. The Canada Newfoundland and Labrador Offshore Petroleum Board is expected to issue an EL for each of these parcels in early 2007. In 2006, we acquired 3-D seismic over EL 1067 in the northern portion of the Jeanne d’Arc Basin as well as on an area in and around the Fortune SDLs 1011 and 1012 to the south of the White Rose oil field. We will continue technical evaluation of our East Coast exploration and SDL acreage. Depending on drilling rig availability, we plan to drill several delineation/exploration wells in the 2007/2008 time frame.

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East Coast

42

International

Our international exploration and development programs are currently located in Southeast Asia. In China, we have a 40% interest in one offshore oil producing operation at Wenchang and six exploration blocks in the South China Sea and one in the East China Sea. In Indonesia, we have a 100% interest in the Madura Strait block Production Sharing Contract and a 100% interest in the Bawean II exploration block.

South China Sea

Wenchang

The Wenchang oil field is located in the western Pearl River Mouth Basin, approximately 400 kilometres south of Hong Kong and 100 kilometres east of Hainan Island. We hold a 40% working interest in the oil fields, which commenced production in July 2002. The Wenchang 13-1 and 13-2 oil fields are producing from 24 wells in 100 metres of water into a floating production, storage and offloading vessel stationed between fixed platforms located in the fields. The blended crude oil from the two fields averages approximately 35º API, similar to the benchmark Minas blend. At December 31, 2006, our gross proved reserves at Wenchang were 13.3 mmbbls of crude oil and NGL. Our gross production averaged 12.1 mbbls/day during 2006. Two near field wildcat exploration wells were drilled in 2006 with no economic success.

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Block 39/05

We executed a Production Sharing Contract with China National Offshore Oil Corporation (“CNOOC”) for the 39/05 exploration block surrounding the Wenchang fields on October 1, 2001. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In January 2003, the Qionghai 18-1-3 exploration type stratigraphic well on the block was plugged and abandoned without testing and in February 2003, the Wenchang 8-1-1 exploration type stratigraphic well was plugged and abandoned without testing. In 2004, we relinquished 25% of block 39/05. Husky has commenced Phase III, the final phase exploration phase of the Production Sharing Contract. In accordance with the contract we, relinquished an additional 25% of 39-05 in February 2006 and have committed to drilling a third exploration well. We currently hold 785,054 acres in block 39/05.

Block 23/15

Husky executed a Production Sharing Contract with CNOOC for the 23/15 exploration block on December 1, 2002. The contract area is located in the South China Sea north of Hainan Island, within 80 kilometres of the Weizhan oil fields. The 23/15 block is approximately 327,415 acres. The work program required Husky to drill a single exploration well on the block within three years. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In 2003, we completed a 247,105 acre 3-D seismic survey shot over a portion of the block. Husky fulfilled its Phase I commitments on block 23/15 with the drilling of Wushi 17-1-1 in 2005, which encountered non-commercial oil. We have decided to proceed with Phase II of the Production Sharing Contract. In accordance with the Production Sharing Contract we have relinquished 25% of the 23/15 block and have committed to drilling a second exploration well before December 31, 2007. We currently hold 243,893 acres in the 23/15 block.

Block 29/26

Husky executed a Production Sharing Contract with CNOOC for the 29/26 exploration block on October 1, 2004. The block is located in the South China Sea approximately 300 kilometres south east of Hong Kong and 65 kilometres south east of the Panyu gas discovery. The block covers an area of approximately 979,773 acres. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. We completed a successful drilling program in 2006, with the drilling of the Liwan 3-1-1. This well was drilled in water 1,500 metres deep. The well location was chosen based on 2-D seismic data and drilled to a total depth of 3,843 metres on a large structure with 14,826 acres of closure and encountered 56 metres of net natural gas pay on logs over four zones. In August 2006, we shot a 98,842 acres seismic survey over Liwan 3-1-1 and the adjacent structures. In January 2007, we signed a three year contract with Seadrill Offshore AS for the deep water semi-submersible drilling rig, West Hercules. The West Hercules is currently under construction in South Korea and is scheduled for delivery in the second quarter of 2008. In preparation for the West Hercules, delineation drilling and further exploration drilling, we signed a contract with China Offshore Seismic Limited for the acquisition of 568,342 acres of 3-D seismic data in 2007.

Block 29/06

Husky executed a Production Sharing Contract with CNOOC for the 29/06 exploration block on October 1, 2006. The block is located in the South China Sea immediately east and adjacent to block 29/26. The block is more than twice the size of 29/26, covering an area of approximately 2,289,431 acres. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In the first exploration phase, we have committed to acquiring 123,553 acres of 3-D seismic and drilling two exploration wells within three years. 123,553 acres of seismic will be integrated with the seismic acquisition on block 29/26, making the total area of 3-D seismic approximately 691,895 acres.

Block 35/18 and 50/14

Husky executed two Production Sharing Contracts with CNOOC for the 35/18 and 50/14 exploration blocks on October 1, 2006. Both contract areas are located in shallow water in the South China Sea immediately west of Hainan Island adjacent to the Dong Fang and Ledong gas fields. The 35/18 block is approximately 1,104,314 acres and the 50/14 block is 775,170 acres. The work program requires us to drill a single exploration well on each block within three years. In addition, Husky is committed to acquiring 123,553 acres of 3-D seismic on block 35/18 within the first three years. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In 2007, we plan to evaluate the existing data on both blocks, before proceeding to acquire seismic in 2008.

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East China Sea

Block 04/35

We executed a Production Sharing Contract with CNOOC for the 04/35 exploration block on December 1, 2003. The block is located in the East China Sea approximately 350 kilometres east of the city of Shanghai and covers an area of approximately 1,194,755 acres. The Production Sharing Contract requires the drilling of a single exploration well in the first exploration phase to a depth of 2,500 metres within three years and a minimum work commitment of U.S. $3 million. Technical evaluations of the hydrocarbon potential are complete and we expect to fulfill our Phase I commitments early in 2007. CNOOC has the right to participate in development of any discoveries up to a 51% working interest.

East Bawean II, Indonesia

We have executed a Production Sharing Contract with the Government of Indonesia for the East Bawean II block. The 1,051,433 acres are located in the North East Java Basin approximately 200 kilometres north of the Madura Strait Production Sharing Contract where we are actively working on the development of the BD gas field. The acquisition of this block increases our total area in Indonesia to 1,742,093 acres. The Production Sharing Contract requires the acquisition of 345,948 acres of 3-D seismic with a commitment of U.S. $7 million, and the drilling of two exploration wells with a commitment of U.S. $16 million, within the first three years of the contract. Husky plans to acquire the 3-D seismic in 2007.

Madura Strait, Indonesia

We have a 100% interest in the approximately 690,660 acre Madura Strait Production Sharing Contract, offshore East Java, Indonesia. There have been two natural gas fields discovered on the block. The larger of these is the Madura BD field, which was granted commercial status and had a plan of development approved by the Indonesian state oil company in 1997. The field was to supply natural gas to a new proposed independent power plant. However, construction of the power plant did not proceed due to economic issues that occurred in Indonesia at that time. We have been involved in protracted negotiations to establish a natural gas contract and an extension to the production sharing contract and expect to conclude these arrangements in 2007. Production is expected to come on stream approximately three years after these agreements are negotiated.

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46

Shatirah, Libya

Husky has a non-operated interest in a small crude oil production operation in the Shatirah field, onshore Libya.

DISTRIBUTION OF OIL AND GAS PRODUCTION

Crude Oil and NGL

Husky provides heavy crude oil feedstock to its upgrader and its asphalt refinery, which are located at Lloydminster Alberta/Saskatchewan. The combined dry crude feedstock requirements of the upgrader and asphalt refinery are equal to approximately 75% of Husky’s heavy crude oil production from the Lloydminster area. Husky also markets heavy crude oil production directly to refiners located in the mid-west and eastern United States and Canada. Husky markets its light and synthetic crude oil production to third party refiners in Canada, the United States and Asia. Natural gas liquids are sold to local petrochemical end users, retail and wholesale distributors and to refiners in North America.

Husky markets third party volumes of light crude oil, heavy crude oil and NGL in addition to its own production.

Natural Gas

The following table shows the distribution of Husky’s gross average daily natural gas production for the years indicated:

	Years ended December 31,
	2006		2005		2004
	(mmcf/day)
Sales to end users
United States		335		357		407
Canada		231		212		187
		566		569		594
Sales to aggregators		26		31		34
Internal use (1)		80		80		61
		672		680		689

Note:

(1)  Husky consumes natural gas for fuel at several of its facilities.

We also market third party natural gas production in addition to our own production.

     Delivery Commitments

The following table shows the future commitments to deliver natural gas from our reserves. Our proved developed reserves of natural gas in Western Canada are more than adequate to meet future delivery commitments.

	Fixed Price				Market Price
	Bcf		$/mmbtu		Bcf
2007		20		4.64		47
2008		19		4.89		24
2009		19		5.15		8
2010		19		5.44		1
2011		19		5.75		—
2012		19		6.02		—
2013		18		5.83		—
2014		10		3.80		—

MIDSTREAM OPERATIONS

Overview

The midstream operations include:

•  Upgrading — the upgrading of heavy crude oil into synthetic light crude oil;

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•  Infrastructure — pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent, and natural gas, extraction of NGL from natural gas, cogeneration of electrical and thermal energy; and

•  Commodity Marketing — the purchase and marketing of Husky’s and other producers’ crude oil, natural gas, NGL, sulphur, petroleum coke and electrical power.

Upgrading Operations

Husky owns and operates the Husky Lloydminster Upgrader (“Upgrader”), which is a heavy oil upgrading facility located in Lloydminster, Saskatchewan.

The Upgrader is designed to process blended heavy crude oil feedstock into high quality, low sulphur synthetic crude oil. Synthetic crude oil is used as feedstock for the refining of premium transportation fuels in Canada and the United States. In addition, the Upgrader recovers the diluent, which facilitates pipeline transportation of heavy crude oil, and returns it to the field to be reused.

The Upgrader provides heavy crude oil access to a new market, which we believe has facilitated, and will continue to stimulate heavy oil production in the area. The market for heavy crude oil previously was either as feedstock for asphalt production or it was sold as blended heavy crude oil for feedstock for specific refineries designed to process or upgrade heavier crude oils. The Upgrader was commissioned in 1992 with an original design capacity of 46 mbbls/day of synthetic crude oil. Actual production has ranged considerably higher than the original design rate capacity as a result of throughput modifications and improved reliability. The Upgrader’s current rated capacity exceeds 67 mbbls/day of synthetic crude oil. Production at the Upgrader averaged 62.5 mbbls/day of synthetic crude oil and 12.5 mbbls/day of diluent in 2006 compared with 57.5.2 mbbls/day of synthetic crude oil and 9.1 mbbls/day of diluent in 2005. Throughput at the Upgrader in 2006 was higher than 2005 due to improved plant reliability. In addition to synthetic crude oil and diluent, the Upgrader also produced, as by-products of its upgrading operations, approximately 326 lt/day of sulphur and 384 lt/day of petroleum coke during 2006. These products are sold in local and international markets. During 2006, we commenced a low sulphur diesel project where, upon completion, the Upgrader will take 0.6 weight% sulphur diesel from the our Lloydminster asphalt refinery and remove additional sulphur from the stream to meet the June 2007 locomotive fuel requirements of 500 weight parts per million of sulphur content.

Infrastructure

Husky has been involved in the gathering, transporting and storage of heavy crude oil in the Lloydminster area since the early 1960s. Our crude oil pipeline systems include approximately 2,050 kilometres of pipeline and are capable of transporting in excess of 575 mbbls/day of blended heavy crude oil, diluent and synthetic crude oil. The pipeline systems transport blended heavy crude oil to Lloydminster, accessing markets through the Upgrader and our asphalt refinery in Lloydminster. Blended heavy crude oil from the field and synthetic crude oil from the upgrading operations are moved south to Hardisty, Alberta to a connection of the Enbridge Pipeline system and the Express Pipeline system. The crude oil is transported to eastern and southern markets on these pipelines. Our crude oil pipeline systems also have feeder pipeline interconnections with the Cold Lake Partnership Pipeline, the Enbridge Athabasca Pipeline and the Talisman Chauvin Pipeline.

The following table shows the average daily pipeline throughput for the periods indicated:

	Years ended December 31,
	2006		2005		2004
	(mbbls/day)
Combined pipeline throughput		475		474		492

In recent years Husky has expanded and expects to further expand its heavy crude pipeline systems to capitalize on anticipated increases in heavy oil production from the Lloydminster and Cold Lake areas.

We consider the expansion and optimization of our pipeline systems in the Lloydminster area to be necessary to further our own development objectives in the area. As a result of recent expansion of mainline pipeline systems in the area, competition for throughput volumes has increased.

We operate 16 heavy crude oil processing facilities located throughout the Lloydminster area. These facilities process Husky’s and other producers’ raw heavy crude oil from the field by removing sand, water and other impurities to produce clean dry heavy crude oil. The heavy crude oil is then blended with a diluent to meet pipeline specifications for transportation.

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Heavy Oil Pipeline Systems

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Cogeneration

Husky has a 50% interest in a 215 MW natural gas fired cogeneration facility at the site of the Upgrader. The plant was commissioned in December 1999. Electricity produced at the facility is being sold to Saskatchewan Power Corporation under a 25 year power purchase agreement effective in 1999. Thermal energy (steam) is sold to the Upgrader.

Husky has a 50% interest in a 90 MW natural gas fired cogeneration facility adjacent to Husky’s Rainbow Lake processing plant. The cogeneration plant produces electricity for the Alberta Power Pool and thermal energy (steam) for the Rainbow Lake processing plant. It provides power directly to the Alberta Power Pool under an agreement with the Alberta Transmission Administrator to provide additional electricity generating capacity and system stability for north-western Alberta. The power plant has the capability of being expanded to approximately 110 MW in total. Husky is the operator of the facility.

Natural Gas Storage Facilities

Husky has been operating a natural gas storage facility at Hussar, Alberta since April 2000. The facility has a working storage capacity of 17 bcf of natural gas. Husky is continuing to evaluate additional storage opportunities within Western Canada.

Commodity Marketing

Husky is a marketer of both its own and third party production of crude oil, synthetic crude oil, NGL, natural gas and sulphur. We also market petroleum coke, a by-product from the Lloydminster Upgrader. We supply feedstock to our Upgrader and asphalt refinery from our own and third party heavy oil production sourced from the Lloydminster and Cold Lake areas. We also sell blended heavy crude oil directly to refiners based in the United States and Canada. Our extensive infrastructure in the Lloydminster area supports its heavy crude oil refining and marketing operations.

We market light and medium crude oil and NGL sourced from our own production and third party production. Light crude oil is acquired for processing by third party refiners at Edmonton, Alberta and by our refinery at Prince George, British Columbia. We market the synthetic crude oil produced at our Upgrader in Lloydminster to refiners in Canada and the United States.

We market natural gas sourced from our own production and third party production. We are currently committed to gas sales contracts with third parties, which in aggregate do not exceed amounts forecast to be deliverable from our reserves. Our contracts are with customers located in eastern Canada/north-eastern United States (26%), mid-west United States (25%), Western Canada (47%) and west coast United States (2%). The natural gas volumes sales contracted are primarily at market prices (92%). At December 31, 2006, our natural gas sales contracts totalled 223 bcf over eight years. The natural gas is deliverable at the rate of 30% of the total 223 bcf in 2007, 19% in 2008, 12% in 2009, 9% in 2010, 9% in 2011, 9% in 2012, 8% in 2013 and 4% in 2014. Husky has acquired rights to firm pipeline capacity to transport the natural gas to most of these markets.

We have developed our commodity marketing operations to include the acquisition of third party volumes in order to increase volumes and enhance the value of our midstream assets. We plan to expand our marketing operations by continuing to increase marketing activities. We believe that this increase will generate synergies with the marketing of our own production volumes and the optimization of our assets. At December 31, 2006, we estimate approximately $712 million in natural gas purchases, 93% of which is to be purchased in 2007.

REFINED PRODUCTS

Overview

Husky’s refined products operations include refining of light crude oil, manufacturing of fuel and industrial grade ethanol, manufacturing of asphalt products from heavy crude oil, acquisition by purchase and exchange of refined petroleum products. Our retail network provides a platform for substantial non-fuel related businesses.

Light oil refined products are produced at our refinery at Prince George, British Columbia and are also acquired from third party refiners and marketed through Husky and Mohawk branded retail and commercial petroleum outlets and through direct marketing to third party dealers and end users. Asphalt and residual products are produced at Husky’s asphalt refinery at Lloydminster and are marketed directly or through Husky’s eight emulsion plants, four of which are also asphalt terminals located throughout Western Canada.

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Branded Petroleum Product Outlets and Commercial Distribution

     Distribution

As of December 31, 2006, there were 505 independently operated Husky and Mohawk branded petroleum product outlets. These petroleum product outlets include service stations, travel centres and bulk distribution facilities located from the Ontario/Quebec border to the West Coast. The travel centre network is strategically located on major highways and serves the retail market and commercial transporters 24 hours per day, 365 days a year with quality products and full service Husky House restaurants. At most locations, the travel centre network also features the proprietary “Route Commander” cardlock system that enables commercial users to purchase products using a card system that will electronically process transactions and provide detailed billing, sales tax and other information. A variety of full and self serve retail locations under the Mohawk and Husky brand names serve urban and rural markets, while Husky and Mohawk bulk distributors offer direct sales to commercial and farm markets in Western Canada.

Our strategy in respect of our petroleum product outlets includes continuing to increase profits and sales through the strategic location of new outlets, the enhancement of ancillary non-fuel income streams, the modernization, automation and upgrading of existing petroleum product outlets, expanding customer loyalty programs and the sale of non-core locations. We also plan to continue to enter into strategic alliances with third parties to sell various consumer products at Husky and Mohawk branded petroleum outlets in order to generate revenue and increase demand for other products and services provided at those outlets. We are pursuing acquisitions and joint venture opportunities to further enhance our existing distribution network.

Branded Petroleum Product Outlets

Branded Petroleum Outlets

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Independent retailers or agents operate all Husky and Mohawk branded petroleum product outlets. Branded outlets feature varying services such as 24 hour service, convenience stores, service bays, car washes, Husky House full service family style restaurants, proprietary and co-branded quick serve restaurants, bank machines and alternate fuels such as propane and compressed natural gas. In addition to conventional gasolines, ethanol blended fuels branded as “Mother Nature’s Fuel” and additive enhanced “Diesel Max” are offered in all markets together with Chevron lubricants. Husky supplies refined petroleum products to its branded independent retailers on an exclusive basis and provides financial and other assistance for location improvements, marketing support and related services. Husky’s brands are promoted through the Husky Snowstars Program, various national and university athletic sponsorships as well as advertising designed to reach both national and regional audiences.

The following table shows the number of Husky and Mohawk branded petroleum outlets by class of trade and by province as of December 31, 2006:

	British
	Columbia &										2006		2005
Retail Owned Outlets	Yukon		Alberta		Sask.		Manitoba		Ontario		Total		Total
Travel Centres		10		8		4		2		13		37		36
Full Serve		7		11		2		1		3		24		31
Full/Self Serve		21		31		8		13		9		82		61
Self Serve		22		12		1		1		5		41		33
Bulk Distributor		1		7		3		1		1		13		14
Other Service Facilities		2		7		0		1		1		11		10
		63		76		18		19		32		208		185
Leased
Travel Centres		1		0		0		0		0		1		1
Full Serve		2		6		3		5		0		16		20
Full/Self Serve		30		21		4		4		0		41		46
Self Serve		0		21		0		1		0		52		54
Bulk Distributor		2		0		0		0		0		2		3
Other Service Facilities		2		4		0		3		2		11		10
		49		52		7		13		2		123		134
Independent Retailers
Travel Centres		1		1		0		0		4		6		6
Full Serve		18		10		6		9		9		52		66
Full/Self Serve		18		5		3		1		1		28		29
Self Serve		26		41		3		2		1		73		83
Bulk Distributor		3		4		2		0		0		6		7
Other Service Facilities		1		2		0		0		3		6		5
		—		—		—		—		—		—		—
		67		63		14		12		18		174		196
Total
Travel Centres		12		9		4		2		17		44		43
Full Serve		27		27		11		15		12		92		117
Full/Self Serve		51		57		15		18		10		151		136
Self Serve		87		74		4		4		6		166		170
Bulk Distributor		6		11		5		1		1		24		24
Other Service Facilities		5		13		0		4		6		28		25
		179		191		39		44		52		505		515
Cardlocks(1)		26		18		4		6		21		73		73
Convenience Stores(1)		183		185		40		44		50		502		479
Restaurants		11		13		4		2		16		46		45

Note:

(1)  All of these are located at branded petroleum outlets.

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We also market refined petroleum products directly to various commercial markets, including independent dealers, national rail companies and major industrial and commercial customers in Western Canada and the north-western United States.

The following table shows our average daily sales volumes of light refined petroleum products for the periods indicated:

	Years ended December 31,
	2006		2005		2004
	(mbbls/day)
Gasoline		27.5		28.3		28.3
Diesel fuel		26.4		26.5		23.9
Liquefied petroleum gas		0.9		0.9		1.1
		54.8		55.7		53.3

Prince George Refinery

The Prince George refinery production is equal to approximately 22% of our total refined product supply requirements and is the source of our lowest cost refined products. The refinery produces all grades of unleaded gasoline, seasonal diesel fuels, a mixed propane and butane stream, and heavy oil products.

Lloydminster Asphalt Refinery

Our Lloydminster refinery processes heavy crude into asphalt products used in road construction and maintenance, manufactured building products, locomotive blendstock and specialty oil field products. The refinery has a throughput capacity of 28,000 barrels per day of heavy crude oil. It also produces a distillate stream used by the Upgrader, and a condensate stream used to blend with heavy oil production.

Ethanol Manufacturing

Husky currently produces 10 million litres per year of fuel and industrial ethanol at our plant in Minnedosa, Manitoba. A second ethanol facility in Lloydminster, Saskatchewan, was completed and commissioned in September 2006. This plant has an annual capacity of 130 million litres, making it the largest ethanol plant in Western Canada. Minnedosa will be further expanded in 2007 to reach a production level of 130 million litres per year.

Husky’s ethanol production supports our “Mother Nature’s Fuel” ethanol-blended gasoline marketing program. When added to gasoline, ethanol improves fuel combustion, raises octane levels and prevents fuel line freezing, carbon monoxide emissions, ozone precursors and net emissions of greenhouse gases. Environment Canada has designated ethanol-blended gasoline as an Environmental Choice product.

Husky’s Refined Products group continues to position themselves as the leaders in ethanol blended fuels in Western Canada.

Other Supply Arrangements

In addition to the refined petroleum products supplied by the Prince George refinery, Husky has established processing arrangements and rack based pricing refined product purchase agreements with all major refiners. Husky’s crude oil production and some third party purchased crude oil is delivered or sold to major refiners, who process the crude oil into refined products, which are then marketed by us through our retail networks and to our wholesale customers. During 2006, these refiners processed an average of approximately 27.7 mbbls/day of crude oil for us, yielding approximately 25.5 mbbls/day of refined petroleum products. During 2006, we also purchased approximately 20.6 mbbls/day of refined petroleum products from refiners and acquired approximately 9.1 mbbls/day of refined petroleum products pursuant to exchange agreements with third party refiners.

Asphalt Products

Husky produces asphalt and residual products at our 28,000 bbls/day asphalt refinery at Lloydminster and markets these products to customers across Western Canada and the northwestern and midwestern United States.

Husky has 38% of the market for paving asphalt sold in Western Canada. Our Pounder Emulsions division has a 50% market share in Western Canada for road application emulsion products. Additional non-asphalt based road maintenance

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products are marketed and distributed through Western Road Management, a division of Husky. We have increased sales to the United States and Eastern Canada, with 46% of production in 2006 exported to the United States and products shipped as far as Texas, Florida and New Brunswick.

Husky also sells in excess of 5 mmbbls of asphalt cements per year. In addition, we produce and sell straight run distillates, and residuals. The distillates are hydrogen deficient and are sold directly to the Upgrader and blended into the Husky Synthetic Blend stream. The stream is removed and re-circulated into the heavy oil pipeline network as pipeline diluent. Residuals are a blend of medium and light gas oil streams which we sell directly to customers

Husky’s asphalt distribution network consists of four emulsion/asphalt terminals located at Kamloops, British Columbia; Lethbridge, Alberta; Yorkton, Saskatchewan; and Winnipeg, Manitoba and four emulsion plants located at Edmonton, Alberta; Watson Lake, Yukon; Lloydminster and Saskatoon, Saskatchewan. Husky also utilizes an independently operated terminal at Langley, British Columbia.

All of our asphalt requirements are supplied by our Lloydminster, Alberta asphalt refinery. The refinery had an original design rate throughput capacity of 25 mbbls/day. Debottlenecking has allowed us to increase that to 28 mbbls/day. The crude oil feedstock for the Lloydminster refinery is supplied through Husky’s pipeline systems from the supply of heavy crude oil in the region, including Husky’s heavy crude oil.

The following table shows our average daily sales volumes of products produced at the Lloydminster refinery, for the years indicated:

	Years ended December 31,
	2006		2005		2004
	(mbbls/day)
Asphalt		14.0		13.8		14.0
Residual and other		9.4		8.7		8.8
		23.4		22.5		22.8

Refinery throughput averaged 27.1 mbbls/day of blended heavy crude oil feedstock during 2006.

Due to the seasonal demand for asphalt products the refinery historically has operated at full capacity only during the normal paving season in Canada and the northern United States. We have implemented various plans to increase refinery throughput during the other months of the year, such as producing low sulphur diesel, entering into custom processing arrangements and developing other U.S. and international markets for asphalt products. This has allowed us to run at or near full capacity year round.

Our strategy with respect to our asphalt marketing business is to increase sales volumes by increasing asphalt supply and developing new product streams, to enhance margins by soliciting industry for Husky ideal specifications, to minimize costs and expand our income base through new products and new markets and to pursue mergers, acquisitions, brokering and processing opportunities within our niche markets.

In 2007, we will direct our efforts to identifying acquisition, merger, brokering, terminalling, and processing opportunities, increase residual sales relative to diluents and bulk distillates to enhance margins, concentrate on sales of higher quality products with larger margins, develop new sales tools and programs to improve customer service and satisfaction and develop new products and improve existing products.

HUMAN RESOURCES

The number of employees in each business segment was as follows:

	December 31,
	2006		2005
Upstream		2,357		2,172
Midstream		375		345
Refined Products		480		442
Corporate and business support		358		330
		3,570		3,289

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DIVIDENDS

The following table shows the aggregate amount of the cash dividends declared per common share of the Company and paid in respect of its last three years ended December 31:

	2006		2005		2004
Cash dividends declared per common share	$	1.50	$	1.65	$	1.00

Dividend Policy and Restrictions

The Board of Directors of Husky have established a dividend policy that pays quarterly dividends. From August 2000 to July 2003, Husky paid a quarterly dividend of $0.09 ($0.36 annually) per common share. From August 2003 to April 2004, Husky paid $0.10 ($0.40 annually) per common share. The dividend policy was reviewed by the Board in April 2004 and the quarterly dividend was increased to $0.12 ($0.48 annually) per common share. The dividend policy was reviewed in April 2005 and increased to $0.14 ($0.56 annually) per common share and again in October 2005 when it was increased to $0.25 ($1.00 annually) per common share. The dividend policy was reviewed in July 2006 and was increased to $0.50 ($2.00 annually) per common share. The Board declared special cash dividends in the amount of $1.00 per common share in July 2003 and $0.54 per common share in November 2004. In October 2005 the Board declared a special dividend of $1.00 per common share. In February 2007, the Board declared a special dividend of $0.50 per common share. Husky’s dividend policy will continue to be reviewed and there can be no assurance that further dividends will be declared.

The declaration and payment of dividends will be at the discretion of the Board, which will consider earnings, capital requirements and financial condition of Husky, the satisfaction of the applicable solvency test in Husky’s governing corporate statute, the Business Corporations Act (Alberta), and other relevant factors.

DESCRIPTION OF CAPITAL STRUCTURE

Common Shares

Husky is authorized to issue an unlimited number of common shares. Holders of common shares are entitled to one vote per share at meetings of shareholders of Husky, to receive such dividends as declared by the Board of Directors on the common shares and to receive pro-rata the remaining property and assets of Husky upon its dissolution or winding up, subject to any rights having priority over the common shares.

Preferred Shares

Husky is authorized to issue an unlimited number of preferred shares. Holders of preferred shares shall not be entitled to vote at meetings of Husky, are entitled to receive such dividends as and when declared by the Board of Directors in priority to common shares and shall be entitled to receive pro-rata in priority to holders of common shares the remaining property and assets of Husky upon its dissolution or winding up. There are no preferred shares currently outstanding.

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Credit Ratings Summary

	Rating	Last Review	Last Rating Change
Moody’s:
Outlook	Stable	August 29, 2005	—
Senior Unsecured Debt	Baa2	August 29, 2005	April 25, 2001
Capital Securities	Ba1	August 29, 2005	April 25, 2001
Standard and Poor’s:
Outlook	Stable	July 27, 2006	July 27, 2006
Senior Unsecured Debt	BBB+	July 27, 2006	July 27, 2006
Capital Securities	BBB−	July 27, 2006	July 27, 2006
Dominion Bond Rating Service:
Trend	Stable	September 20, 2006	—
Senior Unsecured Debt	BBB(high)	September 20, 2006	—
Capital Securities	BBB	September 20, 2006	—
Fitch:
Senior Unsecured Debt	BBB+	May 5, 2006	—
Capital Securities	BBB−	May 5, 2006	—

Credit ratings are intended to provide investors with an independent measure of credit quality of any issue of securities. The credit ratings accorded to Husky’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

Moody’s

Moody’s credit rating system ranges from Aaa (highest) to C (lowest). Debt securities rated within the Baa category are considered medium grade debts; they are neither highly protected nor poorly secured. Interest payments and principal security appears to be adequate at the time of the rating however they are subject to potential adverse circumstances over time. As a result these debt securities possess some speculative characteristics. The addition of a 1, 2 or 3 modifier indicates an additional relative standing within the general rating classification. The addition of the modifier 1 indicates the debt is positioned in the top one third of the general rating classification, 2 indicates the mid one third and 3 indicates the bottom one third.

Standard and Poor’s

Standard and Poor’s credit rating system ranges from AAA (highest) to D (lowest). Debt securities rated within the BBB category are considered to possess adequate protection parameters. However, they could potentially change subject to adverse economic conditions or other circumstances that may result in reduced capacity of the debtor to continue to meet principal and interest payments. As a result these debt securities possess some speculative characteristics. The addition of the modifier + or − indicates the debt is positioned above (+) or below (−) the mid range of the general category.

Dominion Bond Rating Service

Dominion Bond rating Service’s credit rating system ranges from AAA (highest) to D (lowest). Debt securities rated within the BBB category are considered to be of adequate credit quality. Protection of interest and principal is considered acceptable, but the debtor is susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the debtor and its rated debt. The addition of the high or low modifier denotes that the rating is either above or below the mid range or the general rating category.

Fitch

Fitch’s credit rating system ranges from AAA (highest) to D (lowest). Debt securities rated within the BBB category indicate that there is currently a low expectation of credit risk. The capacity for timely payment of financial commitments is considered adequate, but adverse changes in circumstances or in economic conditions are more likely to impair this capacity. The addition of the modifier + or − indicates the debt is positioned above (+) or below (−) the mid range of the

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general category. The A category denotes that the debtor’s capacity with regard to the rated debt is strong rather than adequate.

MARKET FOR SECURITIES

Husky’s common shares are listed and posted for trading on the Toronto Stock Exchange under the trading symbol “HSE”.

The following table discloses the trading price range and volume of Husky’s common shares traded on the Toronto Stock Exchange during Husky’s financial year ended December 31, 2006:

	High		Low		Volume
					(000’s)
January		71.56		59.63		12,680
February		74.50		65.00		14,628
March		73.15		68.92		12,236
April		75.64		64.54		10,479
May		68.58		58.00		15,243
June		71.00		62.40		13,951
July		77.94		68.67		8,555
August		83.00		74.50		9,450
September		77.44		66.31		12,782
October		72.98		66.20		17,930
November		79.05		70.40		14,428
December		80.45		74.92		9,530

DIRECTORS AND OFFICERS

The following are the names and residences of the directors and officers of Husky as of the date of this Annual Information Form, their positions and offices with Husky and their principal occupations during the past five years. The directors shall hold office until the next annual meeting of Husky shareholders or until their respective successors have been duly elected or appointed.

Directors

Name and Residence	Office or Position	Principal Occupation During Past 5 Years
LI, VICTOR T.K. Hong Kong	Co-Chairman and Director	Mr. Li is Managing Director and Deputy Chairman of Cheung Kong (Holdings) Limited (a public investment holding and project management company).
		Mr. Li is also Deputy Chairman and Executive Director of Hutchison Whampoa Limited (an investment holding company); Executive Director and Chairman of CK Life Sciences Int’l., (Holdings) Inc. (a biotechnology company) and Cheung Kong Infrastructure Holdings Limited (an infrastructure development company); Executive Director of Hongkong Electric Holdings Limited (a holding company); and a director of The Hongkong and Shanghai Banking Corporation Limited.
		Mr. Li is a member of the Standing Committee of the 10th   National Committee of the Chinese People’s Political Consultative Conference of the People’s Republic of China and he is also a member of the Executive Committee of the Commission on Strategic Development of the Hong Kong Special Administrative Region.
FOK, CANNING K.N. Hong Kong	Co-Chairman and Director	Mr. Fok is Group Managing Director and Executive Director of Hutchison Whampoa Limited.

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Name and Residence	Office or Position	Principal Occupation During Past 5 Years
		Mr. Fok is also a director and Chairman of Hutchison Telecommunications International Limited (a public investment holding company), Hutchison Harbour Ring Limited (an investment holding company), Hutchison Telecommunications (Australia) Limited (a telecommunications company), Partner Communications Company Ltd. (a telecommunications company) and Hongkong Electric Holdings Limited; Deputy Chairman and a director of Cheung Kong Infrastructure Holdings Limited; and a director of Cheung Kong (Holdings) Limited. Mr. Fok was also a Non Executive Director of Panvas Gas Holdings Limited from 2002 – 2006 and a director of Hanny Holdings Limited from 1992 – 2005.
FULLERTON, R. DONALD Toronto, Ontario, Canada	Director	Mr. Fullerton is retired and serves as a corporate director of a number of private companies. Mr. Fullerton is also a director of the Li Ka Shing (Canada) Foundation.
		Mr. Fullerton was a director of Asia Satellite Telecommunications Holdings Limited from 1996 to 2006; George Weston Limited (a holding company) from 1991 to 2005; Partner Communications Ltd. from 2003 to 2005; CIBC from 1974 to 2004; Hollinger Inc. from 1992 to 2003; and Westcoast Energy Inc. from 1993 to 2003.
GLYNN, MARTIN J.G. St. Andrews, Scotland	Director	Mr. Glynn was a director of HSBC Bank USA N.A. from 2000 and President and Chief Executive Officer from 2003 until his retirement in 2006. Mr. Glynn was a director of HSBC Bank Canada from 1999 to 2006 and President and Chief Executive Officer from 1999 to 2003.
KINNEY, BRENT D. Dubai, United Arab Emirates	Director	Mr. Kinney is a director and Chief Executive Officer of Sky Petroleum Inc. (a public petroleum company).
		Mr. Kinney is also a director of Dragon Oil plc, Western Cooper Corporation (a mineral exploration company) and Benchmark Energy Ltd. (an oil and gas exploration company). Mr. Kinney was also a director of Aurado Energy Inc. from 2003 to 2004.
KLUGE, HOLGER Toronto, Ontario, Canada	Director	Mr. Kluge is a director of Hongkong Electric Holdings Limited, Hutchison Whampoa Limited and Shoppers Drug Mart Corporation. Mr. Kluge was a director of Hutchison Telecommunications (Australia) Limited from 1999 to 2005; TOM Group Limited from 2000 to 2005; and Loring Ward International Limited (a financial planning company) from 2004 to 2005.
KOH, POH CHAN Hong Kong	Director	Ms. Koh is Finance Director, Harbour Plaza Hotel Management (International) Ltd. (a hotel management company).
KWOK, EVA L. Vancouver, British Columbia Canada	Director	Mrs. Kwok is Chairman, a director and Chief Executive Officer of Amara International Investment Corp. (a private investment holding company).
		Mrs.   Kwok is also a director of Bank of Montreal Group of

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Name and Residence	Office or Position	Principal Occupation During Past 5 Years
		Companies, CK Life Sciences Int’l., (Holdings) Inc. and Cheung Kong Infrastructure Holdings Limited. Mrs. Kwok is also a director of the Li Ka Shing (Canada) Foundation.
		Mrs.   Kwok was a director of Air   Canada from 1998 to 2003; Telesystem International Wireless Inc. from 2002 to 2003; and Shoppers Drug Mart Corporation from 2004 to 2006.
KWOK, STANLEY T.L. Vancouver, British Columbia, Canada	Director	Mr. Kwok is a director and President of Stanley Kwok Consultants (an architecture, planning and development company).
		Mr. Kwok is also a director and President of Amara International Investment Corp. and a director of Cheung Kong (Holdings) Limited.
LAU, JOHN C.S. Calgary, Alberta, Canada	President & Chief Executive Officer and Director	Mr. Lau is the President & Chief Executive Officer of Husky Energy Inc.
SHAW, WAYNE E. Toronto, Ontario, Canada	Director	Mr. Shaw is a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors. Mr. Shaw is also a director of the Li Ka Shing (Canada) Foundation.
SHURNIAK, WILLIAM Limerick, Saskatchewan, Canada	Deputy Chairman and Director	Mr. Shurniak is a Non-Executive Director of Hutchison Whampoa Limited and a director and chairman of Northern Gas Networks Limited (a private distributor of natural gas in Northern England).
		Mr. Shurniak held the following positions until his return to Canada in 2005: Director and Chairman of ETSA Utilities (a utility company) since 2000, Powercor Australia Limited (a utility company) since 2000, CitiPower Pty Ltd. (a utility company) since 2002, and a director of Envestra Limited (a natural gas distributor) since 2000, CrossCity Motorways Pty Ltd. (an infrastructure and transportation company) since 2002 and Lane Cove Tunnel Company Pty Ltd. (an infrastructure and transportation company) since 2004.
SIXT, FRANK J. Hong Kong	Director	Mr. Sixt is Group Finance Director and Executive Director of Hutchison Whampoa Limited.
		Mr. Sixt is also the Chairman and director of TOM Online Inc. and TOM Group Limited; Executive Director of Cheung Kong Infrastructure Holdings Limited and Hongkong Electric Holdings Limited; a director of Hutchison Telecommunications International Limited, Cheung Kong (Holdings) Limited, Hutchison Telecommunications (Australia) Limited and Partner Communications Company Ltd. Mr. Sixt is also a director of the Li Ka Shing (Canada) Foundation.

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Officers

Name and Residence	Office or Position	Principal Occupation During Past 5 Years
INGRAM, DONALD R. Calgary, Alberta, Canada	Senior Vice President, Midstream & Refined Products	Senior Vice President, Midstream and Refined Products of Husky since August 2000.
PEABODY, ROBERT J. Calgary, Alberta, Canada	Chief Operating Officer, Operations & Refining	Chief Operating Officer, Operations and Refining of Husky since January 2006. Prior to joining Husky, Mr. Peabody held the following positions with British Petroleum: Director Innovence Separation & Initial Public Offering Project from 2005 to 2006, President of Global Polymers, Chemicals from 2004 to 2005, Vice President, Polyester and Aromatics Americas from 2002 to 2004 and Vice President, BP Group Strategy & Planning from 1991 to 2001.
BARLOW, L. GEOFFREY Calgary, Alberta, Canada	Vice President & Chief Financial Officer	Vice President & Chief Financial Officer of Husky since March 1, 2007. Mr. Barlow was Vice President & Controller of Husky Oil Operations from 2003 to 2007 and Controller from 2000 to 2003.
GIRGULIS, JAMES D. Calgary, Alberta, Canada	Vice President, Legal & Corporate Secretary	Vice President, Legal & Corporate Secretary of Husky since August 2000.

Douglas S. Fraser served as Vice President & Chief Financial Officer from April 2006 until his departure from Husky in January 2007.

The Board of Directors has an Audit Committee (as required by the Business Corporations Act (Alberta)) currently consisting of R.D. Fullerton (Chair), M.J.G. Glynn and W.E. Shaw, a Compensation Committee currently consisting of C.K.N. Fok (Chair), H. Kluge, E.L. Kwok and F.J. Sixt, a Health, Safety and Environment Committee currently consisting of H. Kluge (Chair), B.D. Kinney, and S.T.L. Kwok and a Corporate Governance Committee currently consisting of H. Kluge (Chair), E.L. Kwok and W.E. Shaw. Husky does not have an Executive Committee.

As at February 28, 2007, the directors and officers of Husky, as a group, owned beneficially, directly or indirectly, or exercised control or direction over 397,949 common shares of Husky representing less than 1% of the issued and outstanding common shares.

Conflicts of Interest

Certain officers and directors of Husky are also officers and/or directors of other companies engaged in the oil and gas business generally and which, in certain cases, own interests in oil and gas properties in which Husky holds or may in future hold an interest. As a result, situations arise where the interests of such directors and officers conflict with their interests as directors and officers of other companies. In the case of the directors the resolution of such conflicts is governed by applicable corporate laws which require that directors act honestly, in good faith and with a view to the best interests of Husky and, in respect of the Business Corporations Act (Alberta), Husky’s governing statute, that directors declare, and refrain from voting on, any matter in which a director may have a conflict of interest.

Corporate Cease Trade Orders or Bankruptcies

None of those persons who are directors or officers of the Company is or has been within the past ten years, a director or officer of any company, including the Company, that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the Company access to any exemption under securities legislation, for a period of more than 30 consecutive days, or was subject to an event that resulted, after the director or officer ceased to be a director or officer, in the company being subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, for a period of more than 30 consecutive days, or within a year of that person ceasing to act in that capacity became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver,

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receiver manger or trustee appointed to hold its assets, other than Eva Kwok who was a director of Air Canada in 2003 at the time it became subject to creditor protection under the Companies Creditors Arrangement Act (Canada). In addition, Holger Kluge and Frank Sixt were directors until April 12, 2002 of vLinx Inc., a private Canadian company which was petitioned into bankruptcy on April 15, 2002, vLinx Inc. developed technology and software to facilitate international trade. Mr. Fok acted as a non-executive director of Peregrine Investments Holdings Limited (an investment bank) which was put into compulsory liquidation on March 18, 1998.

Individual Penalties, Sanctions or Bankruptcies

None of the persons who are directors or officers of the Company have, within the past ten years made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold his assets.

None of the persons who are directors or officers of the Company have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

AUDIT COMMITTEE

The members of Husky’s Audit Committee are R.D. Fullerton (Chair), M.J.G. Glynn and W.E. Shaw. Each of the members of the Company’s Audit Committee (the “Committee”) are independent in that each member does not have a direct or indirect material relationship with the Company. Multilateral Instrument 52-110 — Audit Committees provides that a material relationship is a relationship which could, in the view of the board of directors of Husky (the “Board”), reasonably interfere with the exercise of a member’s independent judgment.

The Committee’s Charter provides that the Committee is to be comprised of at least three (3) members of the Board, all of whom shall be independent and meet the financial literacy requirements of applicable laws and regulations. Each member of the Committee is financially literate in that each has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Company’s financial statements.

The education and experience of each Audit Committee member that is relevant to the performance of his responsibilities as an Audit Committee member is as follows.

R.D. Fullerton (Chair) — Before his retirement Mr. Fullerton served as Chief Executive Officer of CIBC and also served as a director and/or an Audit Committee member of 16 major domestic and international public companies as well as director of a number of affiliates of CIBC.

M.J.G. Glynn — Mr. Glynn was a director and President and Chief Executive Officer of HSBC Bank USA N.A. from 2000 until his recent retirement in 2006.

W.E. Shaw — Mr. Shaw is a senior partner of a major Canadian law firm and in that capacity has developed general business knowledge.

Husky’s Audit Committee Charter is attached hereto as Schedule “A.”

External Auditor Service Fees

The following table provides information about the fees billed to the Company for professional services rendered by KPMG llp, the Company’s external auditor, during fiscal years indicated:

	Aggregate fees
	billed by the
	External Auditor
	2006		2005
	($ thousands)
Audit fees		1,700		447
Audit-related fees		109		27
Tax fees		73		160
All other fees		153		476
		2,035		1,110

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Audit Fees.  Audit fees consist of fees for the audit of the Company’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings.

Audit-Related Fees.  Audit-related services included attest services not required by statute or regulation and services with respect to acquisitions and dispositions.

Tax Fees.  Tax fees included tax planning and various taxation matters.

All Other Fees.  Other services provided by the Company’s external auditor, other than audit, audit-related and tax services, included advisory services in 2006 associated with various aspects of the Sarbanes-Oxley Act of 2002.

The audit fees disclosed in the table above reflect amounts billed in the period indicated rather than the period of the audit.

The Company’s Audit Committee has the sole authority to review in advance, and grant any appropriate pre-approvals, of all non-audit services to be provided by the independent auditors and to approve fees, in connection therewith. The Audit Committee approved all of the audit-related, tax and other services provided by KPMG llp in 2006.

LEGAL PROCEEDINGS

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these or other matters or amount which may be required to pay by reason thereof would have a material adverse impact on its financial position, results of operations or liquidity.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the Company’s directors, executive officers or persons or companies that beneficially own directly or indirectly, or exercise control or direction over, more than 10% of Husky’s common shares, or their associates and affiliates, had any material interest, direct or indirect, in any transaction with the Company within the three most recently completed financial years or during the current financial year that has materially affected or would materially affect the Company except as follows.

The Corporation entered into a management agreement effective July 15, 2004 with Western Canadian Place Ltd. for general management of Western Canadian Place Ltd.’s leasehold interest in office space at 635 — 8th Avenue S.W., Calgary, Alberta. Western Canadian Place Ltd. is indirectly controlled by the Corporation’s principal shareholders. The Corporation’s President & Chief Executive Officer is also a director and officer of Western Canadian Place Ltd. The Vice President, Special Projects of the Corporation’s subsidiary, Husky Oil Operations Limited, is also a director and officer of Western Canadian Place Ltd. The Corporation was paid fees of $99,715 in 2006 and $129,547 in 2005 for providing such management services. This agreement was terminated effective August 31, 2006.

TRANSFER AGENT AND REGISTRARS

Husky’s transfer agent and registrar is Computershare Trust Company of Canada. In the United States, the transfer agent and registrar is Computershare Trust Company, Inc. The registers for transfers of the Company’s common shares are maintained by Computershare Trust Company of Canada at its principal offices in the cities of Calgary and Toronto. Queries should be directed to Computershare Trust Company at 1-888-267-6555 (toll free in North America).

INTERESTS OF EXPERTS

Certain information relating to the Company’s reserves included in this Annual Information Form has been calculated by the Company and audited and opined upon as of December 31, 2006 by McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineering consultants retained by Husky, and has been so included in reliance on the opinion and analysis of McDaniel, given upon the authority of said firm as experts in reserve engineering. The partners of McDaniel as a group beneficially own, directly or indirectly, less than 1% of the Company’s securities of any class.

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ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration, principal shareholders of Husky’s common shares and a description of options to purchase common shares is contained in Husky’s Management Information Circular dated March 13, 2007, prepared in connection with the annual and special meeting of shareholders to be held on April 19, 2007.

Additional financial information is provided in Husky’s Consolidated Financial Statements and Management’s Discussion and Analysis for the most recently completed fiscal year ended December 31, 2006, contained in Husky’s 2006 Annual Report.

Additional information relating to Husky Energy Inc. is available on SEDAR at www.sedar.com.

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ABBREVIATIONS AND GLOSSARY OF TERMS

As used in this Annual Information Form, the following terms have the meanings indicated:

Units of Measure

bbl	— barrel
bbls	— barrels
mbbls	— thousand barrels
mmbbls	— million barrels
bbls/day	— barrels per calendar day
mbbls/day	— thousand barrels per calendar day
boe	— barrels of oil equivalent
boe/day	— barrels of oil equivalent per calendar day
mcf	— thousand cubic feet
mmcf	— million cubic feet
bcf	— billion cubic feet
mmcf/day	— million cubic feet per calendar day
mcfge	— thousand cubic feet of gas equivalent
lt	— long ton
mlt	— thousand long tons
lt/day	— long tons per calendar day
mlt/day	— thousand long tons per calendar day
mmbtu	— million British thermal units
MW	— megawatts
Acronyms
AEUB	— Alberta Energy and Utilities Board
API	— American Petroleum Institute
CNOOC	— Chinese National Offshore Oil Company
COGEH	— Canadian Oil and Gas Evaluation Handbook
EIA	— Energy Information Administration
EL	— Exploration Licence
FAS	— Financial Accounting Statement
FASB	— Financial Accounting Standards Board
FPSO	— Floating production, storage and offloading vessel
LLB	— Lloydminster Blend
NGL	— Natural gas liquids
NWT	— Northwest Territories
NYMEX	— New York Mercantile Exchange
OPEC	— Organization of Petroleum Exporting Countries
PSC	— Production Sharing Contract
SAGD	— Steam assisted gravity drainage
SDL	— Significant Discovery License
SEC	— Securities and Exchange Commission of the United States
SEDAR	— System for Electronic Document Analysis and Retrieval
WCSB	— Western Canada Sedimentary Basin
WTI	— West Texas Intermediate crude oil

APIº gravity

Measure of oil density or specific gravity used in the petroleum industry. The American Petroleum Institute (API) scale expresses density such that the greater the density of the petroleum, the lower the degree of API gravity.

Barrel

A unit of volume equal to 42 U.S. gallons.

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Bitumen

A highly viscous oil which is too thick to flow in its native state, and which cannot be produced without altering its viscosity. The density of bitumen is generally less than 10 degrees API.

Bulk Terminal

A facility used primarily for the storage and/or marketing of petroleum products.

CoalBed Methane

The primary energy source of natural gas is methane (CH(4)). Coal bed methane is methane found and recovered from coal bed seams. The methane is normally trapped in the coal by water that is under pressure. When the water is removed the methane is released.

Cold Production

A non-thermal production process for heavy oil in unconsolidated sand formations. During the cold production process heavy oil and sand are produced simultaneously through the use of progressive cavity pumps, which produce high pressure in the reservoir.

Debottlenecking

To remove restrictions thus improving flow rates and productive capacity.

Delineation well

A well in close proximity to an oil or gas well that helps determine the areal extent of the reservoir.

Developed area

A drainage unit having a well completed thereon capable of producing oil or gas in paying quantities.

Development well

A well drilled within the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive.

Diluent

A lighter gravity liquid hydrocarbon, usually condensate or synthetic oil, added to heavy oil to improve the transmissibility of the oil through a pipeline.

Dry and abandoned well

A well found to be incapable of producing oil or gas in sufficient quantities to justify completion as a producing oil or gas well.

Enhanced recovery

The increased recovery from a crude oil pool achieved by artificial means or by the application of energy extrinsic to the pool, which artificial means or application includes pressuring, cycling, pressure maintenance or injection to the pool of a substance or form of energy but does not include the injection in a well of a substance or form of energy for the sole purpose of aiding in the lifting of fluids in the well, or stimulation of the reservoir at or near the well by mechanical, chemical, thermal or explosive means.

Exploration licence

A licence with respect to the Canadian offshore or the Northwest or Yukon Territories conferring the right to explore for, and the exclusive right to drill and test for, petroleum; the exclusive right to develop the applicable area in order to produce petroleum; and, subject to satisfying the requirements for issuance of a production licence and compliance with the terms of the licence and other provisions of the relevant legislation, the exclusive right to obtain a production licence.

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Exploratory well

A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well as those items are defined herein.

Field

An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.

Gathering System

Pipeline system and associated facilities used to gather natural gas or crude oil from various wells and deliver it to a central point where it can be moved by a single pipeline to a processing facility or sales point.

Horizontal drilling

Drilling horizontally rather than vertically through a reservoir, thereby exposing more of the well to the reservoir and increasing production.

Hydrogen sulphide

A poisonous gas which is colourless and heavier than air and is found in sour gas.

Infill Well

A well drilled on an irregular pattern disregarding normal spacing requirements. These wells are drilled to produce from parts of a reservoir that would otherwise not be recovered through existing wells drilled in accordance with normal spacing.

Liquefied petroleum gas

Liquefied propanes and butanes, separately or in mixtures.

Miscible Flood

An enhanced recovery method which requires that three fluids exist in the reservoir: the mobile oil to be recovered, a displacing fluid (NGL) injected to move as a bank behind the oil, and a fluid injected to propel the displacing fluid (chase gas) through the reservoir.

Multiple completion well

A well producing from two or more formations by means of separate tubing strings run inside the casing, each of which carry hydrocarbons from a separate and distinct producing formation.

Natural gas liquids (“NGL”)

Those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants, or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butanes and condensate, or a combination thereof.

Oil Battery

An accessible area to accommodate separators, treaters, storage tanks and other equipment necessary to process and store crude oil and other fluids prior to transportation.

Oil Sands

Sands and other rock materials which contain crude bitumen and includes all other mineral substances in association therewith.

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Overriding royalty interests

An interest acquired or withheld in the oil and gas produced (or the proceeds from the sale of such oil and gas), received free and clear of all costs of development, operation, or maintenance and in addition to the usual landowner’s royalty reserved to the lessor in an oil and gas lease.

Primary recovery

The oil and gas recovered by any method that may be employed to produce the oil or gas through a single well bore. The fluid enters the well bore by the action of native reservoir energy or gravity.

Production Sharing Contract

A contract for the development of resources under which the contractor’s costs (investment) are recoverable each year out of the production but there is a maximum amount of production which can be applied to the cost recovery in any year. This annual allocation of production is referred to as cost oil, the remainder is referred to as profit oil and is divided in accordance with the contract between the contractor and the host government.

Raw gas

Gas as produced from a well before the separation therefrom of liquefiable hydrocarbons or other substances contained therein.

Secondary recovery

Oil or gas recovered by injecting water or gas into the reservoir to force additional oil to the producing wells. Usually, but not necessarily, this is done after the primary recovery phase has passed.

Seismic (survey)

A method by which the physical attributes in the outer rock shell of the earth are determined by measuring, with a seismograph, the rate of transmission of shock waves through the various rock formations. The rate at which the waves are transmitted varies with the medium through which they pass.

Service well

A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation or injection for in-situ combustion.

Significant discovery licence

A licence issued following the declaration of a significant discovery, which is indicated by the first exploration well that demonstrates by flow testing the existence of sufficient hydrocarbons in a particular geological feature to suggest potential for sustained production. A Significant Discovery Licence confers the same rights as that of an Exploration Licence.

Sour gas

Natural gas contaminated with chemical impurities, notably hydrogen sulphide or other sulphur compounds. Such compounds must be removed before the gas can be used for commercial or domestic purposes.

Specific Gravity

The ratio between the weight of equal volumes of water and another liquid measured at standard temperature, the weight of water is assigned a value of one (1). However, the specific gravity of oil is normally expressed in degrees of API gravity as follows:

Degrees API =             141.5             
Specific gravity @ F60 degrees −131.5

Spot Price

The price for a one-time open market transaction for immediate delivery of a specific quantity of product at a specific location where the commodity is purchased “on the spot” at current market rates.

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Steam Assisted Gravity Drainage

A recovery method used to produce heavy crude oil and bitumen in-situ. Steam is injected via a horizontal well along a producing formation. The temperature in the formation increases and lowers the viscosity of the crude oil allowing it to fall to a horizontal production well beneath the steam injection well.

Step-out Well

A well drilled adjacent to a proven well but located in an unproven area; a well drilled in an effort to ascertain the extent and boundaries of a producing formation.

Stratigraphic test well

A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) “exploratory-type,” if not drilled in a proved area, or (ii) “development-type,” if drilled in a proved area.

Synthetic oil

A mixture of hydrocarbons derived by upgrading heavy crude oils, including bitumen, through a process that reduces the carbon content and increases the hydrogen content.

Tertiary recovery

The recovery of oil and gas by using exotic or complex recovery schemes involving steam, chemicals, gases or heat. Usually, but not necessarily, this is done after the secondary recovery phase has passed.

Three-D Seismic (survey)

Three dimensional seismic imaging which uses a grid of numerous cable rather than a few lines stretched in one line.

Turnaround

Perform maintenance at a plant or facility which requires the plant or facility to be shut down for the duration.

Undeveloped area

An area in which it has not been established by drilling operations whether oil and/or gas may be found in commercial quantities.

Waterflood

One method of secondary recovery in which water is injected into an oil reservoir for the purpose of forcing oil out of the reservoir and into the bore of a producing well.

Well Abandonment Costs

Costs of abandoning a well (net of any salvage value) and of disconnecting the well from the surface gathering system.

Wellhead

The structure, sometimes called the “Christmas tree,” that is positioned on the surface over a well that is used to control the flow of oil or gas as it emerges from the sub surface casinghead.

Working interest

An interest in the net revenues of an oil and gas property which is proportionate to the share of exploration and development costs borne until such costs have been recovered, and which entitles the holder to participate in a share of net revenue thereafter.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Information Form are forward-looking statements or information, collectively “forward-looking statements,” within the meaning of the applicable Canadian securities legislation and Section 21E of the United States Securities legislation Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The Company is hereby providing cautionary statements identifying important factors that could cause the Company’s actual results to differ materially from those projected in forward-looking statements made in this Annual Information Form. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “intend,” “plan,” “projection,” “could;” “vision;” “goals;” “objective” and “outlook”) are not historical facts and may be forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, reserve estimates; our production plans for the Tucker in-situ oil sands project, Lloydminster Ethanol Plant and the Minnedosa Ethanol Plant; our low sulphur diesel project for the Lloydminster Upgrader; our plans to expand our oil pipeline systems; our design plans for the Sunrise in-situ oil sands project; our exploration and development drilling plans for Western Canada, offshore East Coast Canada, South and East China Seas, Indonesia and in the oil sands regions of Alberta; our estimates of the productive capacity for White Rose, Tucker and Sunrise; our production forecasts; and statements relating to declining production in the Western Canada Sedimentary Basin, increasing non-conventional production and the volatility of commodity prices are forward-looking statements.

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements of the Company made by or on behalf of the Company, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to:

•  fluctuations in commodity prices

•  the accuracy of our oil and gas reserve estimates and estimated production levels as they are affected by our success at exploration and development drilling and related activities and estimated decline rates

•  the uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures

•  changes in general economic, market and business conditions

•  fluctuations in supply and demand for our products

•  fluctuations in the cost of borrowing

•  our use of derivative financial instruments to hedge exposure to changes in commodity prices and fluctuations in interest rates and foreign currency exchange rates

•  political and economic developments, expropriations, royalty and tax increases, retroactive tax claims and changes to import and export regulations and other foreign laws and policies in the countries in which we operate

•  our ability to receive timely regulatory approvals

•  the integrity and reliability of our capital assets

•  the cumulative impact of other resource development projects

•  the maintenance of satisfactory relationships with unions, employee associations and joint venturers

•  competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternate sources of energy

•  actions by governmental authorities, including changes in environmental and other regulations that may impose restriction in areas where we operate

•  the ability and willingness of parties with whom we have material relationships to fulfill their obligations

•  the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us and that may or may not be financially recoverable

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These and other factors are discussed throughout this Annual Information Form and under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” incorporated by reference in this Annual Information Form and available on SEDAR at www.sedar.com.

Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

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Schedule A

Husky Energy Inc.

AUDIT COMMITTEE CHARTER

The Audit Committee (the “Committee”) of the Board of Directors (the “Board”) of Husky Energy Inc. (the “Company”) will have the oversight responsibility, authority and specific duties as described below.

Composition

The Committee will be comprised of three or more directors as determined by the Board, each of whom shall satisfy the independence and financial literacy requirements of applicable securities regulatory requirements. In addition, one of the members of the Committee will be an audit committee financial expert as defined in applicable securities regulatory requirements. The members of the Committee will be elected annually at the organizational meeting of the full Board on the recommendation of the Corporate Governance Committee to the Co-Chairmen and will be listed in the annual report to shareholders. One of the members of the Committee will be elected Committee Chair by the Board.

Responsibility

The Committee is a part of the Board. Its primary function is to assist the Board in fulfilling its oversight responsibilities with respect to:

(i)	the quarterly and annual financial statements and quarterly and annual MD&A be provided to shareholders and the appropriate regulatory agencies;
(ii)	earnings press releases before the Company publicly discloses this information;
(iii)	the system of internal controls that management has established;
(iv)	the internal and external audit process;
(v)	the appointment of qualified reserves evaluators or auditors; and
(vi)	the filing of statements and reports with respect to the Company’s oil and gas reserves.

In addition, the Committee provides an avenue for communication between the Board and each of internal audit, the external auditors, financial management, external qualified reserves evaluators or auditors and internal qualified reserves evaluators. The Committee should have a clear understanding with the external auditors and the external reserve evaluators or auditors that an open and transparent relationship must be maintained with the Committee.

The Committee will make regular reports to the Board concerning its activities.

While the Audit Committee has the responsibilities and powers set forth in this Charter, the role of the Audit committee is oversight. The members of the Committee are not full time employees of the Company and may or may not be accountants or auditors by profession or experts in the fields of accounting or auditing and, in any event, do not serve in such capacity. Consequently, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company’s financial statements are complete and accurate and are in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors and, as to reserves, the external reserve evaluators or auditors. Management and the external auditors shall also have the responsibility to conduct investigations and to assure compliance with laws and regulations and the Company’s business conduct guidelines.

Authority

Subject to the prior approval of the Board, the Committee is granted the authority to investigate any matter or activity involving financial accounting and financial reporting, the internal controls of the Company and the reporting of the Company’s reserves and oil and gas activities.

The Committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and to set and pay the compensation for any advisors employed by the Committee.

In recognition of the fact that the independent auditors are ultimately accountable to the Committee, the Committee shall have the authority and responsibility to nominate for shareholder approval, evaluate and, where appropriate, replace the independent auditors and shall approve all audit engagement fees and terms and all non-audit engagements with the

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independent auditors. The Committee shall consult with management and the internal audit group but shall not delegate these responsibilities.

Meetings

The Committee is to meet at least four times annually and as many additional times as the Committee deems necessary. Committee members will strive to be present at all meetings either in person or by telephone. As necessary or desirable, but in any case at least quarterly, the Committee shall meet with members of management and representatives of the external auditors and internal audit in separate executive sessions to discuss any matters that the Committee or any of these groups believes should be discussed privately. Likewise, as necessary or desirable, but in any case at least annually, the Committee shall meet the management and representatives of the external reserve evaluators or auditors and internal reserves evaluators in separate executive sessions to discuss matters that the Committee or any of these groups believes should be discussed privately.

Specific Duties

In carrying out its oversight responsibilities, the Committee will:

1.  Review and reassess the adequacy of this Charter annually and recommend any proposed changes to the Board for approval.

2. (a)  Review with the Company’s management, internal audit and external auditors and recommend to the Board for approval the Company’s annual financial statements and annual MD&A which is to be provided to shareholders and the appropriate regulatory agencies, including any financial statement contained in a prospectus, information circular, registration statement or other similar document.

(b)  Review with the Company’s management, internal audit and external auditors and approve the Company’s quarterly financial statements and quarterly MD&A which is to be provided to shareholders and the appropriate regulatory agencies.

3.	Review with the Company’s management and approve earnings press releases before the Company publicly discloses this information.
4.	Recommend to the Board the external auditors to be nominated for the purpose of preparing or issuing an audit report or performing other audit, review or attest services and the compensation to be paid to the external auditors. The external auditors shall report directly to the Committee.
5.	Be directly responsible for the oversight of the work of the external auditors, including the resolution of disagreements between management of the Company and the external auditors regarding financial reporting.
6.	Review with the Company’s management, internal audit and external auditors the Company’s accounting and financial reporting controls. Obtain annually in writing from the external auditors their observations, if any, on significant weaknesses in internal controls as noted during the course of their work.
7.	Review with the Company’s management, internal audit and external auditor’s significant accounting and reporting principles, practices and procedures applied by the Company in preparing its financial statements. Discuss with the external auditors their judgments about the quality, not just the acceptability, of the Company’s accounting principles used in financial reporting.
8.	Review the scope of internal audit’s work plan for the year and receive a summary report of major findings by internal auditors and how management is addressing the conditions reported.
9.	Review the scope and general extent of the external auditors’ annual audit. The Committee’s review should include an explanation from the external auditors of the factors considered in determining the audit scope, including the major risk factors. The external auditors should confirm to the Committee whether or not any limitations have been placed on the scope or nature of their audit procedures.
10.	Inquire as to the independence of the external auditors and obtain from the external auditors, at least annually, a formal written statement delineating all relationships between the external auditors and the Company as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.
11.	Have a predetermined arrangement with the external auditors that they will advise the Committee, through its Chair and management of the Company, of any matters identified through procedures followed for the review

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of interim quarterly financial statements of the Company, and that such notification is to be made prior to the related press release. Also receive a written confirmation provided by the external auditors at the end of each of the first three quarters of the year that they have nothing to report to the Committee, if that is the case, or the written enumeration of required reporting issues.

12.  At the completion of the annual audit, review with management, internal audit and the external auditors the following:

•  The annual financial statements and related footnotes and financial information to be included in the Company’s annual report to shareholders.

•  Results of the audit of the financial statements and the related report thereon and, if applicable, a report on changes during the year in accounting principles and their application.

•  Significant changes to the audit plan, if any, and any serious disputes or difficulties with management encountered during the audit. Inquire about the cooperation received by the external auditors during their audit, including access to all requested records, data and information.

•  Inquire of the external auditors whether there have been any material disagreements with management, which, if not satisfactorily resolved, would have caused them to issue a non-standard report on the Company’s financial statements.

13.	Discuss with the external auditors, without management being present, (a) the quality of the Company’s financial and accounting personnel, and (b) the completeness and accuracy of the Company’s financial statements. Also, elicit the comments of management regarding the responsiveness of the external auditors to the Company’s needs.
14.	Meet with management, to discuss any relevant significant recommendations that the external auditors may have, particularly those characterized as ‘material’ or ‘serious’. Typically, such recommendations will be presented by the external auditors in the form of a Letter of Comments and Recommendations to the Committee. The Committee should review responses of management to the Letter of Comments and Recommendations from the external auditors and receive follow-up reports on action taken concerning the aforementioned recommendations.
15.	Have the sole authority to review in advance, and grant any appropriate pre-approvals, of all non-audit services to be provided by the independent auditors and, in connection therewith, to approve all fees and other terms of engagement. The Committee shall also review and approve disclosures required to be included in periodic reports filed with Canadian securities regulators and the Securities and Exchange Commission with respect to non-audit services performed by external auditors.
16.	Be satisfied that adequate procedures are in place for the review of the Company’s disclosure of financial information extracted or derived from the Company’s financial statements, and periodically assess the adequacy of those procedures.
17.	Establish procedures for (a) the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls or auditing matter, and (b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.
18.	Review and approve the Company’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors.
19.	Review the appointment and replacement of the senior internal audit executive.
20.	Review with management, internal audit and the external auditors the methods used to establish and monitor the Company’s policies with respect to unethical or illegal activities by Company employees that may have a material impact on the financial statements.
21.	Generally as part of the review of the annual financial statements, receive a report(s), at least annually, from the Company’s general counsel concerning legal, regulatory and compliance matters that may have a material impact on the financial statements.
22.	Review, with reasonable frequency, the Company’s procedures relating to the disclosure of information with respect to the Company’s oil and gas reserves, including the Company’s procedures for complying with the disclosure requirements and restrictions of applicable regulations.

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23.	Review with management the appointment of external qualified reserves evaluators or auditors, and in the case of any proposed change in such appointment, determine the reasons for the change and whether there have been disputes between the appointed external qualified reserves evaluators or auditors, and management.
24.	Review, with reasonable frequency, the Company’s procedures for providing information to the external qualified reserves evaluators or auditors who report on reserves and data for the purposes of compliance with applicable securities laws.
25.	Before the approval and the release of the Company’s reserves data and the report of the qualified reserve evaluators or auditors thereon, meet with management, the external qualified reserves evaluators or auditors and the internal qualified reserves evaluators to determine whether any restrictions affect their ability to report on reserves data without reservation and to review the reserves data and the report of the qualified reserves evaluators.
26.	Recommend to the Board for approval the content and filing of required statements and reports relating to the Company’s disclosure of reserve data as prescribed by applicable regulations.
27.	Review and approve (a) any change or waiver in the Company’s Code of Business Conduct for the chief executive officer and senior financial officers and (b) any public disclosure made regarding such change or waiver.

Calgary, Alberta, Canada

February 15, 2006

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Schedule B

Husky Energy Inc.

REPORT ON RESERVES DATA BY QUALIFIED RESERVES EVALUATOR

To the Board of Directors of

HUSKY ENERGY INC. (Husky):

1.  Our staff has evaluated Husky’s oil and gas reserves data as at December 31, 2006. The reserves data consist of the following:

(a)	proved oil and gas reserve quantities estimated as at December 31, 2006 using constant prices and costs; and
(b)	the related standardized measure of discounted future net cash flows.

2.	The oil and gas reserves data are the responsibility of Husky’s management. As the Corporate Representatives our responsibility is to certify that the reserves data has been properly calculated in accordance with generally accepted procedures for the estimation of reserves data.
3.	We carried out our evaluation in accordance with generally accepted procedures for the estimation of oil and gas reserves data and standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGEH”) with the necessary modifications to reflect definitions and standards under the applicable U.S. Financial Accounting Standards Board standards (the “FASB Standards” and the legal requirements of the U.S. Securities and Exchange Commission (“SEC Requirements”)). Our internal reserves evaluators are not independent of Husky, within the meaning of the term “independent” under those standards.
4.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the oil and gas reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGEH as modified or replaced by the FASB Standards and SEC Requirements.
5.	The following sets forth the estimated standardized measure of discounted future net cash flows (before deducting income taxes) attributed to proved oil and gas reserve quantities, estimated using constant prices and costs and calculated using a discount rate of 10%, included in the reserves data of Husky evaluated for the year ended December 31, 2006:

	Discounted Future Net Cash Flows
Location of Reserves	(before income taxes, 10% discount rate)
	($ millions)
Canada		14,219
China		596
Libya		11
		14,826

We have filed Husky’s oil and gas reserves disclosures in accordance with Financial Accounting Standards Board Statement No. 69 “Disclosures about Oil and Gas Producing Activities” concurrently with this form.

6.	In our opinion, the oil and gas reserves data evaluated by us have, in all material respects, been determined in accordance with principles and definitions presented in the COGEH as modified or replaced by the FASB Standards and SEC Requirements.
7.	We have no responsibility to update our evaluation for events and circumstances occurring after the date of this report.

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8.  Oil and gas reserves are estimates only, and not exact quantities. In addition, the oil and gas reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Calgary, Alberta

January 15, 2007

/s/  Preston Kraft
Preston Kraft, P. Eng

Manager of Reservoir Engineering

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Schedule C

Husky Energy Inc.

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Husky Energy Inc. (“Husky”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes oil and gas reserves data, which consist of the following:

(1)	proved oil and gas reserve quantities estimated as at December 31, 2006 using constant prices and costs; and
(2)	the related standardized measure of discounted future net cash flows.

Husky’s oil and gas reserves evaluation process involves applying generally accepted procedures for the estimation of oil and gas reserves data for the purposes of complying with the legal requirements of the U.S. Securities and Exchange Commission (“SEC”) and the applicable provisions of the U.S. Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69 (collectively, the “Oil and Gas Reserves Data Process”). Husky’s Internal Qualified Reserves Evaluator is the Manager of Reservoir Engineering, who is an employee of Husky and has evaluated Husky’s oil and gas reserves data and certified that the Reserves Data Process has been followed. The Report on Reserves Data of the Manager of Reservoir Engineering accompanies this report and will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the Board of Directors has:

(a)	reviewed the Company’s procedures for providing information to the internal and external qualified oil and gas reserves evaluators;
(b)	met with the internal and, if applicable, external qualified oil and gas reserves evaluator(s) to determine whether any restrictions placed by management affect the ability of the internal qualified reserves evaluator to report without reservation; and
(c)	reviewed the reserves data with management and the internal qualified oil and gas reserves evaluator.

The Audit Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has approved, on the recommendation of the Audit Committee:

(a)	the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;
(b)	the filing of the Report on Reserves Data of the Manager of Reservoir Engineering; and
(c)	the content and filing of this report.

Husky sought and was granted by the Canadian Securities Administrators an exemption from the requirement under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Disclosure” to involve independent qualified oil and gas reserves evaluators or auditors. Notwithstanding this exemption, we involve independent qualified reserve auditors as part of Husky’s corporate governance practices. Their involvement helps assure that our internal oil and gas reserves estimates are materially correct.

In Husky’s view, the reliability of Husky’s internally generated oil and gas reserves data is not materially different than would be afforded by Husky involving independent qualified reserves evaluators or independent qualified reserves auditors to evaluate or audit and review the reserves data. Husky is therefore relying on an exemption, which it sought and was granted by securities regulatory authorities, from the requirement under securities legislation to involve independent qualified reserves evaluators or independent qualified reserves auditors.

The primary factors supporting the involvement of independent qualified reserves evaluators or independent qualified reserves auditors apply when (i) their knowledge of, and experience with, a reporting issuer’s reserves data are superior to that of the internal evaluators and (ii) the work of the independent qualified reserves evaluator or independent qualified reserves auditors is significantly less likely to be adversely influenced by self-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In Husky’s view, neither of these factors applies in Husky’s circumstances.

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Husky’s view is based in large part on the following. Our reserves data were developed in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook. Husky’s procedures, records and controls relating to the accumulation of source data and preparation of reserves data by Husky’s internal reserves evaluation staff have been established, refined and documented over many years. Husky’s internal reserves evaluation staff includes 114 individuals, including support staff, of whom 61 individuals are qualified reserves evaluators as defined in the Canadian Oil and Gas Evaluation Handbook, with an average of 13 years of relevant experience in evaluating reserves. Husky’s internal reserves evaluation management personnel includes 23 individuals with an average of 14 years of relevant experience in evaluating oil and gas and managing the evaluation process.

Reserves data are estimates only, and are not exact quantities. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

/s/  John C. S. Lau John C. S. Lau President & Chief Executive Officer	March 13, 2007
/s/  James D. Girgulis James D. Girgulis Vice President, Legal & Corporate Secretary	March 13, 2007
/s/  R. Donald Fullerton R. Donald Fullerton Director	March 13, 2007
/s/  Wayne E. Shaw Wayne E. Shaw Director	March 13, 2007

78

Schedule D

Husky Energy Inc.

INDEPENDENT ENGINEER’S AUDIT OPINION

January 23, 2007

Husky Energy Inc.

707 — 8th Avenue S.W.

Calgary, Alberta

T2P 3G7

Gentlemen:

Pursuant to Husky’s request we have conducted an audit of the reserves estimates and the respective present worth value of these reserves of Husky Energy Inc., as at December 31, 2006. The Company’s detailed reserves information was provided to us for this audit. Our responsibility is to express an independent opinion on the reserves and respective present worth value estimates, in aggregate, based on our audit tests and procedures.

We conducted our audit in accordance with Canadian generally accepted standards as described in the Canadian Oil and Gas Evaluation Handbook (COGEH) and auditing standards generally accepted in the United States of America. Those standards require that we review and assess the policies, procedures, documentation and guidelines of the Company with respect to the estimation, review and approval of Husky’s reserves information. An audit includes examining, on a test basis, to confirm that there is adherence on the part of Husky’s internal reserve evaluators and other employees to the reserves management and administration policies and procedures established by the Company. An audit also includes conducting reserves evaluation on sufficient number of Company properties as considered necessary to express an opinion.

Based on the results of our audit, it is our opinion that Husky’s internally generated proved and probable reserves and net present values based on forecast and constant price assumptions are, in aggregate, reasonable and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices in the United States and as set out in the Canadian Oil and Gas Evaluation Handbook.

Sincerely,

MCDANIEL & ASSOCIATES CONSULTANTS LTD.

/s/  P.A. Welch
P.A. Welch

President & Managing Director

79

Document B

Form 40-F

CONSOLIDATED FINANCIAL STATEMENTS AND

AUDITORS’ REPORT TO SHAREHOLDERS

For the Year Ended December 31, 2006

MANAGEMENT’S REPORT

The management of Husky Energy Inc. is responsible for the financial information and operating data presented in this financial document.

The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise as they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this financial document has been prepared on a basis consistent with that in the consolidated financial statements.

Husky Energy Inc. maintains systems of internal accounting and administrative controls. These systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are properly accounted for and adequately safeguarded. Management evaluation concluded that our internal control over financial reporting was effective as of December 31, 2006. The system of internal controls is further supported by an internal audit function.

The Audit Committee of the Board of Directors, composed of independent non-management directors, meets regularly with management, as well as the external auditors, to discuss auditing (external, internal and joint venture), internal controls, accounting policy, financial reporting matters and reserves determination process. The Committee reviews the annual consolidated financial statements with both management and the independent auditors and reports its findings to the Board of Directors before such statements are approved by the Board. The Committee is also responsible for the appointment of the external auditors for the Company.

The consolidated financial statements have been audited by KPMG llp, the independent auditors, in accordance with Canadian generally accepted auditing standards on behalf of the shareholders. KPMG llp has full and free access to the Audit Committee.

/s/  John C. S. Lau
John C. S. Lau
President & Chief Executive Officer

Calgary, Alberta, Canada

February 5, 2007

1

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of Husky Energy Inc. (“the Company”) as at December 31, 2006, 2005 and 2004 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. With respect to the consolidated financial statements for the year ended December 31, 2006, we also conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2006 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2006 in accordance with Canadian generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 5, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/  KPMG llp
KPMG llp
Chartered Accountants

Calgary, Alberta, Canada
February 5, 2007

Comments by Auditor for US Readers on Canada/US Reporting Differences

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principle that has a material effect on the comparability of the Company’s financial statements, such as the changes in respect of FAS 123R “Share-Based Payment” and FAS 158 “Employers’ Accounting for Defined Benefit Pension Plans and Other Postretirement Plans” described in Note 19 “Reconciliation to Accounting Principles Generally Accepted in the United States” — to the consolidated financial statements as at December 31, 2006, 2005 and 2004, and for each of the years in the three-year period ended December 31, 2006. Our report to the shareholders dated February 5, 2007 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

/s/  KPMG llp
KPMG llp
Chartered Accountants

Calgary, Alberta, Canada
February 5, 2007

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Husky Energy Inc.

We have audited management’s assessment, included in the accompanying Management’s Report, that Husky Energy Inc. (“the Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have conducted our audits on the consolidated financial statements in accordance with Canadian generally accepted auditing standards. With respect to the year ended December 31, 2006, we also have conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated February 5, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/  KPMG llp
KPMG llp
Chartered Accountants

Calgary, Alberta, Canada
February 5, 2007

3

CONSOLIDATED BALANCE SHEETS

	As at December 31
	2006		2005		2004
	(millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	442	$	168	$	—
Accounts receivable (note 4)		1,284		856		446
Inventories (note 5)		428		471		274
Prepaid expenses		25		40		52
		2,179		1,535		772
Property, plant and equipment, net (notes 1, 6)		15,550		13,959		12,193
Goodwill (note 7)		160		160		160
Other assets (note 11)		44		62		108
	$	17,933	$	15,716	$	13,233
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Bank operating loans (note 9)	$	—	$	—	$	101
Accounts payable and accrued liabilities (note 10)		2,574		2,310		1,439
Long-term debt due within one year (note 11)		100		274		56
		2,674		2,584		1,596
Long-term debt (note 11)		1,511		1,612		2,047
Other long-term liabilities (note 12)		756		730		632
Future income taxes (note 13)		3,372		3,270		2,758
Commitments and contingencies (note 14)
Shareholders’ equity
Common shares (note 15)		3,533		3,523		3,506
Retained earnings		6,087		3,997		2,694
		9,620		7,520		6,200
	$	17,933	$	15,716	$	13,233

On behalf of the Board:

/s/ John C. S. Lau	/s/ R.D. Fullerton
John C. S. Lau	R.D. Fullerton
Director	Director

The accompanying notes to the consolidated financial statements are an integral part of these statements.

4

CONSOLIDATED STATEMENTS OF EARNINGS

	Year ended December 31
	2006			2005			2004
	(millions of dollars,
	except per share amounts)
Sales and operating revenues, net of royalties	$	12,664		$	10,245		$	8,440
Costs and expenses
Cost of sales and operating expenses (note 12)		7,169			5,917			5,706
Selling and administration expenses		162			138			135
Stock-based compensation (note 15)		138			171			67
Depletion, depreciation and amortization (notes 1, 6)		1,599			1,256			1,179
Interest — net (note 11)		92			32			60
Foreign exchange (note 11)		(24	)		(31	)		(120	)
Other — net		22			(50	)		8
		9,158			7,433			7,035
Earnings before income taxes		3,506			2,812			1,405
Income taxes (note 13)
Current		678			297			302
Future		102			512			97
		780			809			399
Net earnings	$	2,726		$	2,003		$	1,006
Earnings per share (note 15) Basic and diluted	$	6.43		$	4.72		$	2.37

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

	Year ended December 31
	2006			2005			2004
	(millions of dollars)
Beginning of year	$	3,997		$	2,694		$	2,156
Net earnings		2,726			2,003			1,006
Dividends on common shares (note 15)
Ordinary		(636	)		(276	)		(195	)
Special		—			(424	)		(229	)
Stock-based compensation — retroactive adoption (note 15)		—			—			(44	)
End of year	$	6,087		$	3,997		$	2,694

The accompanying notes to the consolidated financial statements are an integral part of these statements.

5

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31
	2006			2005			2004
	(millions of dollars)
Operating activities
Net earnings	$	2,726		$	2,003		$	1,006
Items not affecting cash
Accretion (note 12)		45			33			27
Depletion, depreciation and amortization		1,599			1,256			1,179
Future income taxes		102			512			97
Foreign exchange		(3	)		(37	)		(124	)
Other		32			18			12
Settlement of asset retirement obligations		(36	)		(41	)		(40	)
Change in non-cash working capital (note 8)		544			(94	)		147
Cash flow — operating activities		5,009			3,650			2,304
Financing activities
Bank operating loans financing — net		—			(101	)		(4	)
Long-term debt issue		1,226			3,235			2,200
Long-term debt repayment		(1,493	)		(3,401	)		(1,937	)
Settlement of cross currency swap		(47	)		—			—
Debt issue costs		—			—			(5	)
Proceeds from exercise of stock options		3			6			18
Proceeds from monetization of financial instruments		—			39			8
Dividends on common shares		(636	)		(700	)		(424	)
Other		(1	)		(1	)		—
Change in non-cash working capital (note 8)		(678	)		255			337
Cash flow — financing activities		(1,626	)		(668	)		193
Available for investing		3,383			2,982			2,497
Investing activities Capital expenditures		(3,171	)		(3,068	)		(2,349	)
Corporate acquisitions		—			—			(102	)
Asset sales		34			74			36
Other		(12	)		(31	)		(19	)
Change in non-cash working capital (note 8)		40			211			(63	)
Cash flow — investing activities		(3,109	)		(2,814	)		(2,497	)
Increase in cash and cash equivalents		274			168			—
Cash and cash equivalents at beginning of year		168			—			—
Cash and cash equivalents at end of year	$	442		$	168		$	—

The accompanying notes to the consolidated financial statements are an integral part of these statements.

6

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Except where indicated and per share amounts, all dollar amounts are in millions.

Note 1  Segmented Financial Information

	Upstream						Midstream
													Infrastructure
							Upgrading						and Marketing
	2006		2005		2004		2006		2005		2004		2006		2005			2004
Year ended December 31
Sales and operating revenues, net of royalties	$	5,772	$	4,367	$	3,120	$	1,679	$	1,488	$	1,058	$	9,559	$	7,383		$	6,126
Costs and expenses
Operating, cost of sales, selling and general		1,321		1,050		967		1,273		1,018		884		9,258		7,084			5,914
Depletion, depreciation and amortization		1,476		1,144		1,077		24		21		19		24		21			21
Interest — net		—		—		—		—		—		—		—		—			—
Foreign exchange		—		—		—		—		—		—		—		—			—
		2,797		2,194		2,044		1,297		1,039		903		9,282		7,105			5,935
Earnings (loss) before income taxes		2,975		2,173		1,076		382		449		155		277		278			191
Current income taxes		519		215		211		53		16		—		79		(14	)		31
Future income taxes		161		434		152		44		120		43		1		110			32
Net earnings (loss)	$	2,295	$	1,524	$	713	$	285	$	313	$	112	$	197	$	182		$	128
Capital employed — As at December 31(2)	$	9,482	$	8,741	$	7,628	$	553	$	510	$	481	$	843	$	390		$	426
Property, plant and equipment — As at December 31
Cost
Canada	$	21,019	$	18,512	$	16,023	$	1,390	$	1,205	$	1,084	$	750	$	683		$	647
International		751		655		587		—		—		—		—		—			—
	$	21,770	$	19,167	$	16,610	$	1,390	$	1,205	$	1,084	$	750	$	683		$	647
Accumulated depletion, depreciation and amortization
Canada	$	8,141	$	6,729	$	5,722	$	455	$	430	$	409	$	270	$	247		$	226
International		404		354		311		—		—		—		—		—			—
	$	8,545	$	7,083	$	6,033	$	455	$	430	$	409	$	270	$	247		$	226
Net
Canada	$	12,878	$	11,783	$	10,301	$	935	$	775	$	675	$	480	$	436		$	421
International		347		301		276		—		—		—		—		—			—
	$	13,225	$	12,084	$	10,577	$	935	$	775	$	675	$	480	$	436		$	421
Capital expenditures — Year ended December 31(3)	$	2,627	$	2,730	$	2,157	$	184	$	120	$	62	$	68	$	37		$	31
Total assets — As at December 31(4)
Canada	$	13,540	$	12,559	$	10,750	$	992	$	844	$	708	$	1,329	$	866		$	746
International		380		328		275		—		—		—		—		—			—
	$	13,920	$	12,887	$	11,025	$	992	$	844	$	708	$	1,329	$	866		$	746

(1)	Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventories.
(2)	Defined as short- and long-term debt and shareholders’ equity.
(3)	Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions.
(4)	Includes goodwill on corporate acquisitions related to Upstream.

7

	Refined Products							Corporate and Eliminations(1)									Total
	2006		2005			2004		2006			2005			2004			2006			2005			2004
Year ended December 31
Sales and operating revenues, net of royalties	$	2,575	$	2,345		$	1,797	$	(6,921	)	$	(5,338	)	$	(3,661	)	$	12,664		$	10,245		$	8,440
Costs and expenses
Operating, cost of sales, selling and general		2,381		2,169			1,694		(6,742	)		(5,145	)		(3,543	)		7,491			6,176			5,916
Depletion, depreciation and amortization		48		47			38		27			23			24			1,599			1,256			1,179
Interest — net		—		—			—		92			32			60			92			32			60
Foreign exchange		—		—			—		(24	)		(31	)		(120	)		(24	)		(31	)		(120	)
		2,429		2,216			1,732		(6,647	)		(5,121	)		(3,579	)		9,158			7,433			7,035
Earnings (loss) before income taxes		146		129			65		(274	)		(217	)		(82	)		3,506			2,812			1,405
Current income taxes		19		(3	)		11		8			83			49			678			297			302
Future income taxes		21		50			13		(125	)		(202	)		(143	)		102			512			97
Net earnings (loss)	$	106	$	82		$	41	$	(157	)	$	(98	)	$	12		$	2,726		$	2,003		$	1,006
Capital employed — As at December 31(2)	$	561	$	481		$	360	$	(208	)	$	(716	)	$	(491	)	$	11,231		$	9,406		$	8,404
Property, plant and equipment — As at December 31
Cost
Canada	$	1,344	$	1,063		$	878	$	298		$	257		$	232		$	24,801		$	21,720		$	18,864
International		—		—			—		—			—			—			751			655			587
	$	1,344	$	1,063		$	878	$	298		$	257		$	232		$	25,552		$	22,375		$	19,451
Accumulated depletion, depreciation and amortization
Canada	$	525	$	476		$	432	$	207		$	180		$	158		$	9,598		$	8,062		$	6,947
International		—		—			—		—			—			—			404			354			311
	$	525	$	476		$	432	$	207		$	180		$	158		$	10,002		$	8,416		$	7,258
Net
Canada	$	819	$	587		$	446	$	91		$	77		$	74		$	15,203		$	13,658		$	11,917
International		—		—			—		—			—			—			347			301			276
	$	819	$	587		$	446	$	91		$	77		$	74		$	15,550		$	13,959		$	12,193
Capital expenditures — Year ended December 31(3)	$	285	$	191		$	106	$	37		$	21		$	23		$	3,201		$	3,099		$	2,379
Total assets — As at December 31(4)
Canada	$	1,114	$	834		$	625	$	578		$	285		$	129		$	17,553		$	15,388		$	12,958
International		—		—			—		—			—			—			380			328			275
	$	1,114	$	834		$	625	$	578		$	285		$	129		$	17,933		$	15,716		$	13,233

8

Note 2

Nature of Operations and Organization

Husky Energy Inc. (“Husky” or “the Company”) is a publicly traded, integrated energy and energy-related company headquartered in Calgary, Alberta, Canada.

Management has segmented the Company’s business based on differences in products and services and management responsibility. The Company’s business is conducted predominantly through three major business segments — upstream, midstream and refined products.

Upstream includes exploration for, development and production of crude oil, natural gas and natural gas liquids. The Company’s upstream operations are located primarily in Western Canada, offshore Eastern Canada, offshore China and offshore Indonesia.

Midstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (upgrading); marketing of the Company’s and other producers’ crude oil, natural gas, natural gas liquids, sulphur and petroleum coke; and pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and natural gas and cogeneration of electrical and thermal energy (infrastructure and marketing).

Refined products include refining of crude oil and marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products.

Note 3

Significant Accounting Policies

a) Principles of Consolidation and the Preparation of Financial Statements

These financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) which, in the case of the Company, differ in certain respects from those in the United States. These differences are described in note 19, Reconciliation to Accounting Principles Generally Accepted in the United States.

The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from these estimates.

The consolidated financial statements include the accounts of the Company and its subsidiaries.

Substantially all of the Company’s upstream activities are conducted jointly with third parties and accordingly the accounts reflect the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flow from these activities.

b) Cash and Cash Equivalents

Cash and cash equivalents consist of cash on hand less outstanding cheques and deposits with a maturity of less than three months at the time of purchase. When outstanding cheques are in excess of cash on hand, the excess is reported in bank operating loans.

c) Inventory Valuation

Crude oil, natural gas, refined petroleum products and purchased sulphur inventories are valued at the lower of cost or net realizable value. Cost is determined using average cost or on a first-in, first-out basis, as appropriate. Materials and supplies are valued at the lower of average cost or net realizable value. Cost consists of raw material, labour, direct overhead and transportation. Intersegment profits are eliminated.

d) Property, Plant and Equipment

i) Oil and Gas

The Company employs the full cost method of accounting for oil and gas interests whereby all costs of acquisition, exploration for and development of oil and gas reserves are capitalized and accumulated within cost centres on a country-by-country basis. Such costs include land acquisition, geological and geophysical activity, drilling of productive and non-productive wells, carrying costs directly related to unproved properties and administrative costs directly related to exploration and development activities.

The provision for depletion of oil and gas properties and depreciation of associated production facilities is calculated using the unit of production method, based on gross proved oil and gas reserves as estimated by the Company’s engineers, for each cost centre. Depreciation of gas plants and certain other oil and gas facilities is provided using the straight-line method based on their estimated useful lives. Costs subject to depletion and depreciation include both the estimated costs required to develop proved undeveloped reserves and the associated addition to the asset retirement obligations. In the normal course of operations, retirements of oil and gas interests are accounted for by charging the asset cost, net of any proceeds, to accumulated depletion or depreciation. Gains or losses on the disposition of oil and gas properties are not recognized unless the gain or loss changes the depletion rate by 20% or more.

Costs of acquiring and evaluating significant unproved oil and gas interests are excluded from costs subject to depletion and depreciation until it is determined that proved oil and gas reserves are attributable to such interests or until impairment occurs. Costs of major development projects are excluded from costs subject to depletion and depreciation until proved developed reserves have been attributed to a portion of the property or the property is determined to be impaired.

Impairment losses are recognized when the carrying amount of a cost centre exceeds the sum of:

•  the undiscounted cash flow expected to result from production from proved reserves based on forecast oil and gas prices and costs;

•  the costs of unproved properties, less impairment; and

•  the costs of major development projects, less impairment.

9

The amount of impairment loss is determined to be the amount by which the carrying amount of the cost centre exceeds the sum of:

•  the fair value of proved and probable reserves; and

•  the cost, less impairment, of unproved properties and major development projects that do not have probable reserves attributed to them.

ii) Other Plant and Equipment

Depreciation for substantially all other plant and equipment, except upgrading assets, is provided using the straight-line method based on estimated useful lives of assets which range from five to 25 years. Depreciation for upgrading assets is provided using the unit of production method, based on the plant’s estimated productive life. Repairs and maintenance costs, other than major turnaround costs, are charged to earnings as incurred. Certain turnaround costs are deferred to other assets when incurred and amortized over the estimated period of time to the next scheduled turnaround. At the time of disposition of plant and equipment, accounts are relieved of the asset values and accumulated depreciation and any resulting gain or loss is reflected in earnings.

iii) Asset Retirement Obligations

The recognition of the fair value of obligations associated with the retirement of tangible long-lived assets is recorded in the period that the asset is put into use, with a corresponding increase to the carrying value of the related asset. The obligations recognized are legal obligations. The liability is accreted over time for changes in the fair value of the liability through charges to accretion, which is included in cost of sales and operating expenses. The liability will also be adjusted to reflect revisions to the previous estimates of the undiscounted obligation. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion, depreciation and amortization of the underlying asset. Retirement expenditures are charged to the accumulated liability as incurred.

iv) Capitalized Interest

Interest is capitalized on significant major capital projects based on the Company’s long-term cost of borrowing.

e) Impairment or Disposal of Long-lived Assets

An impairment loss is recognized when the carrying value of a long-lived asset is not recoverable and exceeds its fair value. Testing for recoverability uses the undiscounted cash flows expected from the asset’s use and disposition. To test for and measure impairment, long-lived assets are grouped at the lowest level for which identifiable cash flows are largely independent.

A long-lived asset that meets the conditions as held for sale is measured at the lower of its carrying amount or fair value less costs to sell. Such assets are not amortized while they are classified as held for sale. The results of operations of a component of an entity that has been disposed of, or is classified as held for sale, are reported in discontinued operations if: i) the operations and cash flows of the component have been or will be eliminated as a result of the disposal transaction; and, ii) the entity will not have a significant continuing involvement in the operations of the component after the disposal transaction.

f) Goodwill

Goodwill is the excess of the purchase price paid over the fair value of net assets acquired. Goodwill is subject to impairment tests on at least an annual basis or sooner if there are indicators of impairment. The Company tests impairment annually in the fourth quarter of each year. To assess impairment, the fair value of the reporting unit is compared with its carrying amount. If any potential impairment is indicated, then it is quantified by comparing the carrying value of goodwill to its fair value, determined based on the fair value of the assets and liabilities of the reporting unit. Impairment losses would be recognized in current period earnings.

g) Derivative Financial Instruments

Derivative financial instruments are utilized by the Company to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative financial instruments for speculative purposes. The Company may choose to designate derivative financial instruments as hedges for accounting purposes.

When designated, at the inception of the hedge, the Company formally documents the designation of the hedge, the risk management objectives, the hedging relationships between hedged items and hedging items and the method for testing the effectiveness of the hedge which must be reasonably assured over the term of the hedge. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company formally assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.

The Company may enter into commodity price contracts to hedge anticipated sales of oil and natural gas production to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream oil and gas revenues as the related sales occur.

The Company may enter into commodity price contracts to offset fixed price contracts entered into with customers and suppliers in order to retain market prices while meeting customer or supplier pricing requirements. Gains and losses from these contracts are recognized in midstream revenues or cost of sales as the related sales or purchases occur.

The Company may enter into power price contracts to hedge anticipated purchases of electricity to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream operating expenses as the related purchases occur.

The Company may enter into interest rate swap agreements to hedge its fixed and floating interest rate mix on long-term debt. Gains and losses from these contracts are recognized as an adjustment to the interest expense on the hedged debt instrument. The related amount payable or receivable from the counterparties is recorded as an adjustment to accrued interest.

10

The Company may enter into foreign exchange contracts to hedge its foreign currency exposures on U.S. dollar denominated long-term debt. Gains and losses on these instruments are accrued under current or non-current assets or liabilities on the balance sheet and recognized in foreign exchange in the period to which they relate, offsetting the respective foreign exchange gains and losses recognized on the underlying foreign currency long-term debt. The forward premium or discount on the foreign exchange contract is amortized as an adjustment to interest expense over the term of the contract.

The Company may enter into foreign exchange forwards and foreign exchange collars to hedge anticipated U.S. dollar denominated oil and natural gas sales. Gains and losses on these instruments are recognized as an adjustment to upstream oil and gas revenues when the sale is recorded.

Realized and unrealized gains or losses associated with derivative financial instruments which have been terminated or cease to be effective as a hedge prior to maturity are deferred under current or non-current assets or liabilities on the balance sheet and recognized into income in the period in which the underlying hedged transaction is recognized in income. In the event that a designated hedged item is sold, extinguishes or matures prior to the termination of the related derivative financial instrument, any realized or unrealized gain or loss is recognized in earnings.

Fair values of the financial instruments are based on quoted market prices where available. The fair values of swaps and forwards are based on forward market prices. If a forward price is not available for a commodity based forward, a forward price is estimated using an existing forward price adjusted for quality or location.

h) Employee Future Benefits

The Company provides a defined contribution pension plan and a post-retirement health and dental care plan to qualified employees. The Company also maintains a defined benefit pension plan for a small number of employees who did not choose to join the defined contribution pension plan in 1991. The cost of the pension benefits earned by employees in the defined contribution pension plan is paid and expensed when incurred. The cost of the benefits earned by employees in the post-retirement health and dental care plan and defined benefit pension plan is charged to earnings as services are rendered using the projected benefit method prorated on service. The cost of the post-retirement health and dental care plan and defined benefit pension plan reflects a number of assumptions that affect the expected future benefit payments. These assumptions include, but are not limited to, attrition, mortality, the rate of return on pension plan assets and salary escalations for the defined benefit pension plan and expected health care cost trends for the post-retirement health and dental care plan. The plan assets are valued at fair value for the purposes of calculating the expected return on plan assets.

Adjustments arising out of plan amendments, changes in assumptions and experience gains and losses are normally amortized over the expected remaining average service life of the employee group.

i) Future Income Taxes

The Company follows the liability method of accounting for income taxes. Future income tax assets and liabilities are recognized at expected tax rates in effect when temporary differences between the tax basis and the carrying value of the Company’s assets and liabilities reverse. The effect of a change to the tax rate on the future tax assets and liabilities is recognized in earnings when substantively enacted.

j) Non-monetary Transactions

Non-monetary transactions are measured based on fair value unless the transaction lacks commercial substance or is an exchange of product or property held for sale in the ordinary course of business.

k) Revenue Recognition

Revenues from the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are recorded when title passes to an external party. Sales between the business segments of the Company are eliminated from sales and operating revenues and cost of sales. Revenues associated with the sale of transportation, processing and natural gas storage services are recognized when the services are provided.

l) Foreign Currency Translation

Results of foreign operations, all of which are considered financially and operationally integrated, are translated to Canadian dollars at the monthly average exchange rates for revenue and expenses, except for depreciation and depletion which are translated at the rate of exchange applicable to the related assets. Monetary assets and liabilities are translated at current exchange rates and non-monetary assets and liabilities are translated using historical rates of exchange. Gains or losses resulting from these translation adjustments are included in earnings.

m) Stock-based Compensation

The Company adopted the Canadian Institute of Chartered Accountants (“CICA”) section 3870, “Stock-based Compensation and Other Stock-based Payments,” retroactively without restatement of prior periods. In accordance with the Company’s stock option plan, common share options may be granted to directors, officers and certain other employees. The recommendations require the Company to record compensation expense over the vesting period based on the fair value of options granted.

The Company’s stock option plan is a tandem plan that provides the stock option holder with the right to exercise the stock option or surrender the option for a cash payment. A liability for expected cash settlements is accrued over the vesting period of the stock options based on the difference between the exercise price of the stock options and the market price of the Company’s common shares. The liability is revalued to reflect changes in the market price of the Company’s common shares and the net change is recognized in earnings. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares, consideration paid by the stock option holders and the previously recognized liability associated with the stock options are recorded as share capital. Accrued compensation for an option that is forfeited is adjusted to earnings by decreasing the compensation cost in the period of forfeiture.

11

n) Earnings per Share

Basic common shares outstanding are the weighted average number of common shares outstanding for each period. The calculation of basic earnings per common share is based on net earnings divided by the weighted average number of common shares outstanding.

Diluted common shares outstanding are calculated using the treasury stock method, which assumes that any proceeds received from in-the-money options would be used to buy back common shares at the average market price for the period. However, since the Company has a tandem stock option plan and accrues a liability for expected cash settlements, the potential common shares issuable upon exercise associated with the stock options are not included in diluted common shares outstanding. Shares potentially issuable on the settlement of the capital securities have not been included in the determination of diluted earnings per common share, as the Company has neither the obligation nor intention to settle amounts due through the issuance of shares.

o) Reclassification

Certain prior years’ amounts have been reclassified to conform with current presentation.

Note 4

Accounts Receivable

	2006			2005			2004
Trade receivables	$	1,286		$	854		$	448
Allowance for doubtful accounts		(10	)		(10	)		(10	)
Other		8			12			8
	$	1,284		$	856		$	446

Sale of Accounts Receivable

As at December 31, 2006, the Company’s ceiling on its securitization program to sell, on a revolving basis, accounts receivable to a third party was $350 million. As at December 31, 2006, no accounts receivable had been sold under the program (2005 and 2004 — $350 million). The agreement includes a program fee. The average effective rate for 2006 was approximately 4.1% (2005 — 3.0%; 2004 — 2.6%).

Proceeds from revolving sales between the third party and the Company in 2006 totalled approximately $3.1 billion (2005 — $3.4 billion; 2004 — $2.5 billion).

Note 5

Inventories

	2006		2005		2004
Crude oil and refined petroleum products	$	208	$	241	$	159
Natural gas		193		207		100
Materials, supplies and other		27		23		15
	$	428	$	471	$	274

Note 6

Property, Plant and Equipment

Refer to note 1, Segmented Financial Information, which presents the Company’s property, plant and equipment by segment.

Administrative costs related to exploration and development activities capitalized in 2006 were $68 million (2005 — $61 million; 2004 — $40 million).

Costs of oil and gas properties, including major development projects, excluded from costs subject to depletion and depreciation at December 31 were as follows:

	2006		2005		2004
Canada	$	1,932	$	2,317	$	2,399
International		165		127		129
	$	2,097	$	2,444	$	2,528

The prices used in the ceiling test evaluation of the Company’s crude oil and natural gas reserves at December 31, 2006 were:

											Price increase
Canada	2007		2008		2009		2010		2011		2011 to 2026
											(percent)
Crude oil ($/bbl)	$	56.91	$	51.90	$	44.90	$	41.60	$	42.58		68
Natural gas ($/mcf)		7.71		7.70		7.18		6.86		6.87		35

Subsequent to December 31, 2006, the Company entered into an agreement to dispose of certain non-core properties in Western Canada for total proceeds of $339 million. This transaction is expected to close in the first quarter of 2007.

12

Note 7

Corporate Acquisition

Effective July 15, 2004, the Company acquired all of the issued and outstanding shares of Temple Exploration Inc. (“Temple”) for total cash consideration of $102 million. The results of Temple are included in the consolidated financial statements of the Company from its acquisition date.

The allocation of the aggregate purchase price based on the estimated fair values of the net assets of Temple on its acquisition date was as follows:

Net assets acquired
Working capital	$	(17	)
Property, plant and equipment		138
Goodwill (1)		20
Future income taxes		(39	)
	$	102

(1)  Allocated to the Company’s upstream segment and not deductible for income tax purposes. Refer to note 1, Segmented Financial Information.

Note 8

Cash Flows — Change in Non-cash Working Capital

a) Change in non-cash working capital was as follows:

	2006			2005			2004
Decrease (increase) in non-cash working capital
Accounts receivable	$	(428	)	$	(410	)	$	209
Inventories		43			(197	)		(77	)
Prepaid expenses		14			17			(12	)
Accounts payable and accrued liabilities		277			962			301
Change in non-cash working capital	$	(94	)	$	372		$	421
Relating to:
Operating activities	$	544		$	(94	)	$	147
Financing activities		(678	)		255			337
Investing activities		40			211			(63	)

b) Other cash flow information:

	2006		2005		2004
Cash taxes paid	$	215	$	154	$	213
Cash interest paid		147		147		143

Note 9

Bank Operating Loans

At December 31, 2006, the Company had unsecured short-term borrowing lines of credit with banks totalling $220 million (2005 and 2004 — $195 million). As at December 31, 2006, bank operating loans (excluding reclassified outstanding cheques) were nil (2005 — $0.4 million; 2004 — $49 million) and letters of credit under these lines of credit totalled $19 million (2005 — $18 million; 2004 — $23 million). Interest payable is based on Bankers’ Acceptance, U.S. LIBOR or prime rates. During 2006, the weighted average interest rate on short-term borrowings was approximately 5.8% (2005 — 3.9%; 2004 — 3.4%).

Note 10

Accounts Payable and Accrued Liabilities

	2006		2005		2004
Trade payables	$	74	$	7	$	51
Accrued liabilities		1,221		1,247		760
Dividend payable		212		530		280
Commodity contract settlements		—		—		50
Stock-based compensation		234		130		49
Current income taxes		615		164		119
Other		218		232		130
	$	2,574	$	2,310	$	1,439

13

Note 11

Long-term Debt

			Cdn $ Amount									U.S. $ Denominated
	Maturity		2006			2005			2004			2006		2005		2004
Long-term debt
Syndicated credit facility			$	—		$	—		$	70		$	—	$	—	$	—
Bilateral credit facilities				—			—			40			—		—		—
6.85% medium-term notes — Series B		2007		100			100			100			—		—		—
6.95% medium-term notes — Series E		2009		200			200			200			—		—		—
6.25% notes		2012		466			467			481			400		400		400
7.55% debentures		2016		233			233			241			200		200		200
6.15% notes		2019		350			350			361			300		300		300
8.90% capital securities		2028		262			262			271			225		225		225
7.125% notes				—			175			181			—		150		150
8.45% senior secured bonds				—			99			140			—		85		117
Private placement notes				—			—			18			—		—		15
Total long-term debt				1,611			1,886			2,103		$	1,125	$	1,360	$	1,407
Amount due within one year				(100	)		(274	)		(56	)
			$	1,511		$	1,612		$	2,047

Interest — net for the years ended December 31 was as follows:

	2006			2005			2004
Long-term debt	$	130		$	144		$	133
Short-term debt		5			4			3
		135			148			136
Amount capitalized		(33	)		(114	)		(75	)
		102			34			61
Interest income		(10	)		(2	)		(1	)
	$	92		$	32		$	60

Foreign exchange for the years ended December 31 was as follows:

	2006			2005			2004
Gain on translation of U.S. dollar denominated long-term debt	$	(7	)	$	(51	)	$	(150	)
Cross currency swaps		4			14			27
Other losses		(21	)		6			3
	$	(24	)	$	(31	)	$	(120	)

As at December 31, 2006, other assets included $12 million (2005 - $21 million; 2004 — $24 million) of deferred debt issue costs.

Credit Facilities

The revolving syndicated credit facility allows the Company to borrow up to $1 billion in either Canadian or U.S. currency from a group of banks on an unsecured basis. The facility is structured as a five-year committed revolving credit facility. Interest rates vary based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected and credit ratings assigned by certain credit rating agencies to the Company’s rated senior unsecured debt.

The Company’s $150 million revolving bilateral credit facilities have substantially the same terms as the syndicated credit facility.

Notes and Debentures

On September 21, 2006, Husky filed a shelf prospectus, which replaces the Company’s shelf prospectus dated August 11, 2004, and enables Husky to offer up to U.S. $1.0 billion of debt securities in the United States until October 21, 2008. During the 25-month period that the prospectus remains effective, debt securities may be offered in amounts, at prices and on terms to be determined based on market conditions at the time of sale and set forth in an accompanying prospectus supplement. As at December 31, 2006, no debt securities were issued under this new shelf prospectus.

The medium-term notes Series B and Series E represent unsecured securities issued under trust indentures dated February 3, 1997 and May 4, 1999, respectively. Interest is payable semi-annually on both series.

The 6.25% and the 6.15% notes represent unsecured securities issued under a trust indenture dated June 14, 2002. Interest is payable semi-annually.

The 7.55% debentures represent unsecured securities issued under a trust indenture dated October 31, 1996 and mature in 2016. Interest is payable semi-annually.

14

The 8.90% capital securities represent unsecured securities under an indenture dated August 10, 1998. Such securities rank junior to all senior debt and other financial debt of the Company. The 8.90% interest is payable semi-annually until August 15, 2008. The capital securities mature in 2028. They are redeemable, in whole or in part, by the Company at any time prior to August 15, 2008 at a redemption price equal to the greater of the par value of the securities and the sum of the present values of the remaining scheduled payments discounted at a rate calculated using a comparable U.S. Treasury Bond rate plus an applicable spread. They are redeemable at par, in whole but not in part, by the Company on or after August 15, 2008. If not redeemed in whole, commencing on August 15, 2008, the interest rate changes to a floating rate equal to U.S. LIBOR plus 5.50% payable semi-annually. The Company has the right at any time prior to maturity, subject to certain conditions, to defer payment of interest for up to five years. The Company also has the unrestricted ability to settle its deferred interest, principal and redemption obligations through the issuance of common or preferred shares.

The 7.125% notes represented unsecured securities issued under a trust indenture dated October 31, 1996 and matured in 2006. Interest was payable semi-annually.

The 8.45% senior secured bonds represented securities issued by a subsidiary under a trust indenture dated July 20, 1999 and were redeemed in full on February 1, 2006. Such securities were issued in connection with the financing of the Company’s share of the costs for the exploration and development of the Terra Nova oil field located off the East Coast of Canada. Interest was payable semi-annually. Certain related financial obligations required collateral of letters of credit and/or cash equivalents. As at December 31, 2005 and 2004, letters of credit totalling $41 million and $54 million, respectively, were outstanding.

The notes and debentures disclosed above are redeemable (unless otherwise stated) at the option of the Company, at any time, at a redemption price equal to the greater of the par value of the securities and the sum of the present values of the remaining scheduled payments discounted at a rate calculated using a comparable U.S. Treasury Bond rate (for U.S. dollar denominated securities) or Government of Canada Bond rate (for Canadian dollar denominated securities) plus an applicable spread.

Note 12

Other Long-term Liabilities

	2006		2005		2004
Asset retirement obligations	$	622	$	557	$	509
Cross currency swaps		40		40		68
Interest rate swaps		37		42		18
Employee future benefits		30		27		23
Stock-based compensation		4		46		14
Other		23		18		—
	$	756	$	730	$	632

Asset Retirement Obligations

At December 31, 2006, the estimated total undiscounted inflation adjusted amount required to settle the asset retirement obligations was $3.8 billion. These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 30 years into the future. This amount has been discounted using credit adjusted risk free rates ranging from 6.2% to 6.5%.

Changes to the asset retirement obligations were as follows:

	2006			2005			2004
Asset retirement obligations at beginning of year	$	557		$	509		$	432
Liabilities incurred		35			63			13
Liabilities disposed		(1	)		(7	)		—
Liabilities settled		(36	)		(41	)		(40	)
Revisions		22			—			77
Accretion		45			33			27
Asset retirement obligations at end of year	$	622		$	557		$	509

15

Note 13

Income Taxes

The provision for income taxes in the Consolidated Statements of Earnings reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31 were accounted for as follows:

	2006			2005			2004
Earnings before income taxes
Canadian	$	3,276		$	2,553		$	1,165
Foreign jurisdictions		230			259			240
		3,506			2,812			1,405
Statutory income tax rate (percent)		35.7			38.4			39.3
Expected income tax		1,252			1,080			552
Effect on income tax of:
Royalties, lease rentals and mineral taxes payable to the crown		10			105			153
Resource allowance on Canadian production income		(35	)		(133	)		(156	)
Rate benefit on partnership earnings		(97	)		(69	)		(42	)
Change in statutory tax rate		(328	)		(4	)		(40	)
Non-deductible capital taxes		(17	)		15			20
Capital gains and losses		(1	)		(140	)		(23	)
Foreign jurisdictions		(6	)		(14	)		(13	)
Other — net		2			(31	)		(52	)
Income tax expense	$	780		$	809		$	399

The future income tax liability at December 31 comprised the tax effect of temporary differences as follows:

	2006		2005		2004
Future tax liabilities
Property, plant and equipment	$	3,607	$	3,487	$	2,949
Foreign exchange gains taxable on realization		48		60		56
Other temporary differences		1		2		5
		3,656		3,549		3,010
Future tax assets
Asset retirement obligations		194		195		180
Loss carry forwards		2		—		11
Provincial royalty rebates		2		7		14
Other temporary differences		86		77		47
		284		279		252
	$	3,372	$	3,270	$	2,758

Note 14

Commitments and Contingencies

Certain former owners of interests in the upgrading assets retained a 20-year upside financial interest expiring in 2014 which requires payments to them when the average differential between heavy crude oil feedstock and synthetic crude oil exceeds $6.50 per barrel. The calculation is based on a two-year rolling average of the differential. During 2006, the Company capitalized $85 million (2005 — $68 million; 2004 — $27 million) of payments under this arrangement.

At December 31, 2006, the Company had commitments for non-cancellable operating leases and other long-term agreements that require the following minimum future payments:

											After
	2007		2008		2009		2010		2011		2011		Total
Operating leases	$	93	$	208	$	286	$	283	$	167	$	96	$	1,133
Firm transportation agreements		169		122		80		62		46		147		626
Unconditional purchase obligations (1)		2,144		970		938		74		62		13		4,201
Lease rentals and exploration work agreements		148		74		73		108		70		167		640
Engineering and construction commitments		140		—		—		—		—		—		140
	$	2,694	$	1,374	$	1,377	$	527	$	345	$	423	$	6,740

(1)  Approximately 72% of the total unconditional purchase obligations are in respect of processing and refined product purchase contracts.

16

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position, results of operations or liquidity. In 2005 a lawsuit was settled with proceeds received and the resulting gain was recognized in earnings and recorded in other — net.

The Company has income tax filings that are subject to audit and potential reassessment. The findings may impact the tax liability of the Company. The final results are not reasonably determinable at this time and management believes that it has adequately provided for current and future income taxes.

Note 15

Share Capital

The Company’s authorized share capital is as follows:

Common shares — an unlimited number of no par value.

Preferred shares — an unlimited number of no par value, none outstanding.

Common Shares

Changes to issued share capital were as follows:

	Number of Shares		Amount
December 31, 2003		422,175,742	$	3,457
Stock-based compensation — adoption		—		23
Options and warrants exercised		1,560,672		26
December 31, 2004		423,736,414		3,506
Options and warrants exercised		388,664		17
December 31, 2005		424,125,078		3,523
Options exercised		143,431		10
December 31, 2006		424,268,509	$	3,533

Stock Options

At December 31, 2006, 18.3 million common shares were reserved for issuance under the Company stock option plan. As described in note 3 m), on June 1, 2004, the Company modified its stock option plan to a tandem plan that provides the stock option holder with the right to exercise the option or surrender the option for a cash payment. The exercise price of the option is equal to the average market price of the Company’s common shares during the five trading days prior to the date of the award. When the option is surrendered for cash, the cash payment is the difference between the average market price of the Company’s common shares on the trading day prior to the surrender date and the exercise price of the option. Under the stock option plan the options awarded have a maximum term of five years and vest over three years on the basis of one-third per year.

A downward adjustment of $0.55 was made to the exercise price of all outstanding stock options effective December 1, 2005, pursuant to the terms of the stock option plan under which the options were issued as a result of the special $1.00 per share dividend that was declared in November 2005. In 2004 a similar downward adjustment of $0.48 was made to the exercise price of all outstanding stock options as a result of a special dividend declared in that year.

The following options to purchase common shares have been awarded to directors, officers and certain other employees:

	Number of			Weighted		Weighted Average		Options
	Options			Average		Contractual		Exercisable
	(thousands)			Exercise Prices		Life (years)		(thousands)
December 31, 2003		4,597		$	13.88		2		3,564
Granted		8,200		$	25.10		4
Exercised for common shares		(1,350	)	$	13.11		1
Surrendered for cash		(1,269	)	$	13.32		1
Forfeited		(214	)	$	22.73		4
December 31, 2004		9,964		$	22.61		4		1,417
Granted		670		$	48.14		5
Exercised for common shares		(359	)	$	15.84		1
Surrendered for cash		(2,443	)	$	19.05		2
Forfeited		(547	)	$	24.10		3
December 31, 2005		7,285		$	25.81		3		1,533
Granted		902		$	71.42		4
Exercised for common shares		(144	)	$	22.31		2
Surrendered for cash		(1,951	)	$	23.95		2
Forfeited		(264	)	$	42.82		3
December 31, 2006		5,828		$	32.81		3		2,232

17

As at December 31, 2006	Outstanding Options						Options Exercisable
			Weighted		Weighted				Weighted
	Number of		Average		Average		Number of		Average
	Options		Exercise		Contractual		Options		Exercise
Range of Exercise Price	(thousands)		Prices		Life (years)		(thousands)		Prices
$13.96 - $14.99		64	$	14.60		1		64	$	14.60
$15.00 - $22.99		96	$	19.87		2		96	$	19.87
$23.00 - $23.99		4,164	$	23.83		2		1,882	$	23.83
$24.00 - $39.99		294	$	32.22		3		95	$	31.69
$40.00 - $55.99		378	$	52.17		4		95	$	52.90
$56.00 - $76.74		832	$	72.04		4		—	$	—
		5,828	$	32.81		3		2,232	$	24.96

Warrants

In 2000, the Company granted 1.4 million Renaissance Energy Ltd. (“Renaissance”) replacement options to purchase common shares of Husky in exchange for certain share purchase options to purchase common shares of Renaissance previously held by employees of Renaissance. The former shareholders of Husky Oil Limited were also granted warrants to acquire, for no additional consideration, 1.86 common shares of the Company for each common share issued on the exercise of a Renaissance replacement option. As at December 31, 2006 and 2005, there were no Renaissance replacement options or warrants outstanding. During 2005 and 2004, 16,000 and 113,600 warrants were exercised respectively.

Earnings per Common Share

	2006		2005		2004
Net earnings	$	2,726	$	2,003	$	1,006
Weighted average number of common shares outstanding
Basic (millions)		424.2		424.0		423.4
Effect of dilutive stock options and warrants		—		—		0.9
Weighted average number of common shares outstanding
Diluted (millions)		424.2		424.0		424.3
Earnings per share
Basic and diluted	$	6.43	$	4.72	$	2.37

Stock-based Compensation

Beginning January 1, 2004, stock-based compensation is being recognized in earnings. This change was adopted retroactively without restatement of prior periods and resulted in a decrease to retained earnings of $44 million, an increase to contributed surplus of $21 million and an increase to share capital of $23 million on January 1, 2004.

Effective June 1, 2004, the Company modified the stock option plan to a tandem plan. Prior to the modification, the fair values of all common share options granted were estimated on the date of grant using the Black-Scholes option-pricing model. The grant date fair values and assumptions used prior to June 1, 2004 were:

	2004
Weighted average fair value per option	$	5.67
Risk-free interest rate (percent)		3.1
Volatility (percent)		21
Expected life (years)		5
Expected annual dividend per share	$	0.44

Dividends

During 2006, the Company declared dividends of $1.50 per common share (2005 — $1.65 per common share; 2004 — $1.00 per common share), including special dividends of $1.00 per common share in 2005 and $0.54 per common share in 2004.

18

Contributed Surplus

Changes to contributed surplus were as follows:

	2004
December 31, 2003	$	—
Stock-based compensation — adoption		21
Stock-based compensation cost		1
Stock options exercised		(6	)
Modification of stock option plan — June 1, 2004		(16	)
December 31, 2004	$	—

Note 16

Employee Future Benefits

The Company currently provides a defined contribution pension plan for all qualified employees. The Company also maintains a defined benefit pension plan, which is closed to new entrants, and all current participants are vested. The Company also provides certain health and dental coverage to its retirees, which is accrued over the expected average remaining service life of the employees.

Defined Benefit Pension Plan

Weighted average long-term assumptions are based on independent historical and projected references and are noted below:

	2006		2005		2004
Discount rate (percent)		5.0		5.8		6.0
Long-term rate of increase in compensation levels (percent)		5.0		5.0		5.0
Long-term rate of return on plan assets (percent)		7.5		7.5		8.0

The discount rate used at the end of 2006 to determine the accrued benefit obligation was 5%.

The long-term rate of return on the assets was determined based on management’s best estimate and the historical rates of return, adjusted periodically. The rate at the end of 2006 was 7.5%.

The status of the defined benefit pension plan at December 31 was as follows:

Benefit Obligation

	2006			2005			2004
Benefit obligation, beginning of year	$	138		$	124		$	118
Current service cost		3			2			2
Interest cost		7			7			7
Benefits paid		(7	)		(6	)		(6	)
Actuarial losses		8			11			3
Benefit obligation, end of year	$	149		$	138		$	124

Fair Value of Plan Assets

	2006			2005			2004
Fair value of plan assets, beginning of year	$	108		$	96		$	85
Contributions		13			11			10
Benefits paid		(7	)		(6	)		(6	)
Expected return on plan assets		8			7			7
Gain on plan assets		10			—			1
Foreign exchange losses		—			—			(1	)
Fair value of plan assets, end of year	$	132		$	108		$	96

Funded Status of Plan

	2006			2005			2004
Fair value of plan assets	$	132		$	108		$	96
Benefit obligation		(149	)		(138	)		(124	)
Excess obligation		(17	)		(30	)		(28	)
Unrecognized past service costs		3			1			1
Unrecognized losses		33			40			32
Accrued benefit asset	$	19		$	11		$	5

19

Husky adheres to a Statement of Investment Policies and Procedures (the “Policy”). The assets are allocated in accordance with the long-term nature of the obligation and comprise a balanced investment based on interest rate and inflation sensitivities. The Policy explicitly prescribes diversification parameters for all classes of investment.

The Company’s actuaries perform valuations as at December 31 for the defined benefit pension plan. The last actuarial valuation was conducted in 2006 and the next valuation will be conducted in 2007.

The composition of the defined benefit pension plan assets was as follows:

	2006			2005			2004
U.S. common equities		1	%		—	%		15	%
Canadian common equities		30			29			25
International equity mutual funds		30			28			11
Canadian government bonds		16			18			25
Canadian corporate bonds		3			3			16
Canadian fixed income mutual funds		19			20			—
Cash and receivables		1			2			8
Total		100	%		100	%		100	%

During 2006, Husky contributed $13 million to the defined benefit pension plan assets, $11 million of which was in respect of additional contributions as a result of the plan’s deficiency. Husky currently plans to contribute $13 million in 2007.

The Company amortizes the portion of the unrecognized actuarial gains or losses that exceed 10% of the greater of the accrued benefit obligation or the market-related value of pension plan assets. The market-related value of pension plan assets is the fair value of the assets. The gains or losses that are in excess of 10% are amortized over the expected future years of service, which is currently seven years.

The past service costs are amortized over the expected future years of service.

Post-retirement Health and Dental Care Plan

The discount rate used in the calculation of the benefit obligation was 5%. The average health care cost trend used was 9.5% which is reduced by 0.50% until 2015. The average dental care cost trend used was 4%, which remains constant.

The status of the post-retirement health and dental care plan at December 31 was as follows:

Benefit Obligation

	2006		2005		2004
Benefit obligation, beginning of year	$	33	$	25	$	23
Current service cost		2		2		2
Interest cost		2		1		1
Benefits paid		—		—		(1	)
Actuarial losses		12		5		—
Benefit obligation, end of year	$	49	$	33	$	25

Funded Status of Plan

	2006			2005			2004
Benefit obligation	$	(49)		$	(33)		$	(25)
Unrecognized losses		19			6			2
Accrued benefit liability	$	(30	)	$	(27	)	$	(23	)

The assumed health care cost trend can have a significant effect on the amounts reported for Husky’s post-retirement health and dental care plan. A one percent increase and decrease in the assumed trend rate would have the following effect:

	1%		1%
	Increase		Decrease
Effect on total service and interest cost components	$	1	$	(1)
Effect on post-retirement benefit obligation	$	11	$	(8	)

20

Pension Expense and Post-retirement Health and Dental Care Expense

The expenses for the years ended December 31 were as follows:

Pension Expense

	2006			2005			2004
Defined benefit pension plan
Employer current service cost	$	3		$	2		$	2
Interest cost		7			7			7
Expected return on plan assets		(8	)		(7	)		(7	)
Amortization of net actuarial losses		3			3			2
		5			5			4
Defined contribution pension plan		16			14			12
Total expense	$	21		$	19		$	16

Post-retirement Health and Dental Care Expense

	2006		2005		2004
Employer current service cost	$	2	$	2	$	2
Interest cost		2		1		1
Total expense	$	4	$	3	$	3

Future Benefit Payments

The following table discloses the current estimate of future benefit payments:

	Defined Benefit		Post-retirement Health
	Pension Plan		and Dental Care Plan
2007	$	8	$	1
2008		8		1
2009		9		1
2010		10		1
2011		9		1
2012 - 2016		51		9

Note 17

Related Party Transactions

Husky, in the ordinary course of business, was party to a lease agreement with Western Canadian Place Ltd. The terms of the lease provided for the lease of office space at Western Canadian Place, management services and operating costs at commercial rates. Effective July 13, 2004, Western Canadian Place Ltd. sold Western Canadian Place to an unrelated party. Western Canadian Place Ltd. is indirectly controlled by Husky’s principal shareholders. Prior to the sale, Husky paid approximately $10 million for office space in Western Canadian Place during 2004.

Note 18

Financial Instruments and Risk Management

Carrying Values and Estimated Fair Values of Financial Assets and Liabilities

The carrying value of cash and cash equivalents, accounts receivable, bank operating loans, accounts payable and accrued liabilities approximates their fair value due to the short-term maturity of these instruments.

The fair value of the long-term debt is the present value of future cash flows associated with the debt. Market information such as treasury rates and credit spreads is used to determine the appropriate discount rates. The estimated fair value of the long-term debt at December 31 was as follows:

	2006				2005				2004
	Carrying		Fair		Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value		Value		Value
Long-term debt	$	1,611	$	1,671	$	1,886	$	1,995	$	2,103	$	2,296

21

Recognized Gains (Losses) on Derivative Instruments

Recognized gains (losses) for the years ended December 31 were as follows:

	2006			2005			2004
Commodity price risk management
Power consumption	$	6		$	4		$	3
Natural gas		—			(17	)		(1	)
Crude oil		—			—			(560	)
Interest rate risk management		1			13			22
Foreign exchange risk management		(3	)		1			(13	)

Unrecognized Gains (Losses) on Derivative Instruments

	2006			2005			2004
Commodity price risk management
Power consumption	$	—		$	—		$	(1	)
Natural gas		—			—			(9	)
Interest rate risk management
Interest rate swaps		5			7			52
Foreign currency risk management Foreign exchange contracts		(26	)		(32	)		(30	)

Commodity Price Risk Management

Natural Gas and Crude Oil Production

The Company did not have a natural gas hedge program in 2006 or a crude oil hedge program in 2005 and 2006.

Power Consumption

At December 31, 2006, the Company had hedged power consumption as follows:

	Notional Volumes
	(MW)		Term		Price
Fixed price purchase		20.0		Apr. to Jun. 2007	$	63.63/MWh

Natural Gas Contracts

The Company has a portfolio of fixed and basis price offsetting physical forward purchase and sale natural gas contracts relating to marketing of other producers’ natural gas. The objective of these contracts is to “lock in” a positive spread between the physical purchase and sale contract prices. At December 31, 2006, the Company had the following offsetting physical purchase and sale contracts:

	Volumes			Unrecognized
	(mmcf)			Gain (Loss)
Physical purchase contracts		25,509		$	5
Physical sale contracts		(25,509	)	$	1

Interest Rate Risk Management

The majority of the Company’s long-term debt has fixed interest rates and various maturities. The Company periodically uses interest rate swaps to manage its financing costs. At December 31, 2006, the Company had entered into interest rate swap arrangements whereby the fixed interest rate coupon on certain debt was swapped to floating rates with the following terms:

Debt	Amount		Swap Maturity		Swap Rate (percent)
6.95% medium-term notes	$	200		July 14, 2009		CDOR + 175 bps

In 2005 the Company unwound interest rate swaps for proceeds of $37 million. The proceeds have been deferred and are being amortized to income over the remaining term of the underlying debt.

Foreign Currency Risk Management

The Company manages its exposure to foreign exchange rate fluctuations by balancing the U.S. dollar denominated cash flows with U.S. dollar denominated borrowings and other financial instruments. Husky utilizes spot and forward sales to convert cash flows to or from U.S. or Canadian currency.

22

At December 31, 2006, the Company had the following cross currency debt swaps:

			Canadian
Debt	Swap Amount		Equivalent		Swap Maturity		Interest Rate
							(percent)
6.25% notes	U.S. $	150	$	212		June 15, 2012		7.41
6.25% notes	U.S. $	75	$	90		June 15, 2012		5.65
6.25% notes	U.S. $	50	$	59		June 15, 2012		5.67
6.25% notes	U.S. $	75	$	88		June 15, 2012		5.61

The Company hedged U.S. dollar revenues for various amounts and maturities through 2006 using foreign exchange forwards. On November 10, 2004, the Company unwound its long-dated forwards, which resulted in a gain of $8 million that was deferred and was recognized into income during 2005 on the dates that the underlying hedged transactions took place.

Credit Risk

Accounts receivable are predominantly with customers in the energy industry and are subject to normal industry credit risks.

In addition, the Company is exposed to credit related losses in the event of non-performance by counterparties to its derivative financial instruments. The Company’s policy is to primarily deal with major financial institutions and investment grade rated entities to mitigate these risks.

Husky did not have any customers that constituted more than 10% of total sales and operating revenues during 2006.

New CICA Handbook Sections for Financial Instruments

In April 2005, the Accounting Standards Board issued three new CICA Handbook Sections: CICA section 3855, “Financial Instruments - Recognition and Measurement,” CICA section 3865, “Hedges;” and, CICA section 1530, “Comprehensive Income.”

Effective January 1, 2007 all financial instruments, including derivatives, must initially be recognized at fair value on the balance sheet. Subsequent measurement and classification of gains or losses related to the financial instrument depend on its classification.

Hedge accounting continues to be optional and the new section gives detailed guidance on the application of hedge accounting and the required disclosures. The current hedging requirements have been expanded and specific guidance has been provided on how to apply hedge accounting, including recognition in the financial statements.

Accumulated other comprehensive income is a new equity category where certain revenues, expenses, gains and losses are temporarily presented outside of net earnings but included in comprehensive income and reclassified to net earnings when required by GAAP. A new financial statement is required entitled the “Statement of Comprehensive Income,” which combines net earnings and the changes in other comprehensive income and will have the same prominence as the Company’s other financial statements.

Adoption is required prospectively and the following represents the required adoption changes for January 1, 2007:

	December 31, 2006					January 1, 2007
	(As Reported)		Adoption Adjustment			(As Restated)
Consolidated Balance Sheets
Assets
Accounts receivable	$	1,284	$	6		$	1,290
Prepaid expenses		25		(2	)		23
Other assets		44		(7	)		37
Liabilities and Shareholders’ Equity
Accounts payable and accrued liabilities		2,574		(5	)		2,569
Long-term debt due within one year		100		(2	)		98
Long-term debt		1,511		34			1,545
Other long-term liabilities		756		(10	)		746
Future income taxes		3,372		(6	)		3,366
Retained earnings		6,087		4			6,091
Accumulated other comprehensive income		—		(18	)		(18	)

23

Note 19

Reconciliation to Accounting Principles Generally Accepted in the United States

The Company’s consolidated financial statements have been prepared in accordance with GAAP in Canada, which differ in some respects from those in the United States. Any differences in accounting principles as they pertain to the accompanying consolidated financial statements were insignificant except as described below:

Consolidated Statements of Earnings

	2006			2005			2004
Net earnings under Canadian GAAP	$	2,726		$	2,003		$	1,006
Adjustments:
Full cost accounting (a)		64			66			37
Related income taxes		(20	)		(23	)		(13	)
Energy trading contracts (c)		4			—			(1	)
Related income taxes		(1	)		—			—
Stock-based compensation (d)		(10	)		—			2
Related income taxes		3			—			—
Earnings before cumulative effect of change in accounting principle under U.S. GAAP		2,766			2,046			1,031
Cumulative effect of change in accounting principle, net of tax (d)		11			—			—
Net earnings under U.S. GAAP	$	2,777		$	2,046		$	1,031
Weighted average number of common shares outstanding under U.S. GAAP (millions)
Basic		424.2			424.0			423.4
Diluted		424.2			424.0			424.3
Earnings per share before cumulative effect of change in accounting principle under U.S. GAAP
Basic	$	6.52		$	4.83		$	2.44
Diluted	$	6.52		$	4.83		$	2.43
Earnings per share under U.S. GAAP
Basic	$	6.55		$	4.83		$	2.44
Diluted	$	6.55		$	4.83		$	2.43

Condensed Consolidated Balance Sheets

	2006					2005					2004
	Canadian		U.S.			Canadian		U.S.			Canadian		U.S.
	GAAP		GAAP			GAAP		GAAP			GAAP		GAAP
Current assets (b)(c)	$	2,179	$	2,190		$	1,535	$	1,591		$	772	$	830
Property, plant and equipment, net (a)		15,550		15,120			13,959		13,465			12,193		11,633
Other assets (g)		204		185			222		223			268		269
	$	17,933	$	17,495		$	15,716	$	15,279		$	13,233	$	12,732
Current liabilities (b)(c)(g)	$	2,674	$	2,696		$	2,584	$	2,685		$	1,596	$	1,649
Long-term debt (b)		1,511		1,557			1,612		1,670			2,047		2,124
Other long-term liabilities (b)(g)		756		749			730		688			632		614
Future income taxes (a)(b)(c) (g)		3,372		3,210			3,270		3,089			2,758		2,555
Share capital (d)(e)(f)		3,533		3,767			3,523		3,757			3,506		3,740
Retained earnings		6,087		5,572			3,997		3,431			2,694		2,085
Accumulated other comprehensive income Cash flow hedges, net of tax (b)		—		(18	)		—		(21	)		—		(20	)
Minimum pension liability, net of tax (g)		—		—			—		(20	)		—		(15	)
Pension accounting — adoption of FAS 158 (g)		—		(38	)		—		—			—		—
	$	17,933	$	17,495		$	15,716	$	15,279		$	13,233	$	12,732

24

Condensed Consolidated Statements of Retained Earnings and Accumulated Other Comprehensive Income

	2006						2005						2004
	Canadian			U.S.			Canadian			U.S.			Canadian			U.S.
	GAAP			GAAP			GAAP			GAAP			GAAP			GAAP
Retained earnings, beginning of year	$	3,997		$	3,431		$	2,694		$	2,085		$	2,156		$	1,478
Net earnings		2,726			2,777			2,003			2,046			1,006			1,031
Dividends on common shares		(636	)		(636	)		(700	)		(700	)		(424	)		(424	)
Stock-based compensation — retroactive adoption (d)		—			—			—			—			(44	)		—
Retained earnings, end of year	$	6,087		$	5,572		$	3,997		$	3,431		$	2,694		$	2,085
Accumulated other comprehensive income, beginning of year	$	—		$	(41	)	$	—		$	(35	)	$	—		$	(91	)
Cash flow hedges, net of tax (b)		—			3			—			(1	)		—			56
Minimum pension liability, net of tax (g)		—			(5	)		—			(5	)		—			—
Reversal of minimum pension liability, net of tax — adoption of FAS 158 (g)		—			25			—			—			—			—
Pension accounting — adoption of FAS 158 (g)		—			(38	)		—			—			—			—
Accumulated other comprehensive income, end of year	$	—		$	(56	)	$	—		$	(41	)	$	—		$	(35	)

Condensed Consolidated Statements of Earnings and Comprehensive Income

	2006				2005				2004
	Canadian		U.S.		Canadian		U.S.		Canadian		U.S.
	GAAP		GAAP		GAAP		GAAP		GAAP		GAAP
Sales and operating revenues (b)(c)	$	12,664	$	10,790	$	10,245	$	8,445	$	8,440	$	7,038
Costs and expenses (excluding depletion, depreciation and amortization) (b)(c) (d)		7,422		5,554		6,112		4,312		5,769		4,366
Accretion expense		45		45		33		33		27		27
Depletion, depreciation and amortization (a)		1,599		1,535		1,256		1,190		1,179		1,142
Interest — net		92		92		32		32		60		60
Earnings before income taxes		3,506		3,564		2,812		2,878		1,405		1,443
Income taxes (a)(b)(c)		780		798		809		832		399		412
Earnings before cumulative effect of change in accounting principle		2,726		2,766		2,003		2,046		1,006		1,031
Cumulative effect of change in accounting principle, net of tax (d)		—		11		—		—		—		—
Net earnings		2,726		2,777		2,003		2,046		1,006		1,031
Other comprehensive income (b)(g)		—		2		—		6		—		(56	)
Comprehensive income	$	2,726	$	2,779	$	2,003	$	2,052	$	1,006	$	975

The increases or decreases noted above refer to the following differences between U.S. GAAP and Canadian GAAP:

(a)  Under Canadian GAAP the ceiling test is performed by comparing the carrying value of the cost centre based on the sum of the undiscounted cash flows expected from the cost centre’s use and eventual disposition. If the carrying value is unrecoverable the cost centre is written down to its fair value using the expected present value approach of proved plus probable reserves using future prices. Under U.S. GAAP, companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and gas reserves using a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable year-end. At December 31, 2001, the Company recognized a U.S. GAAP ceiling test write down of $334 million after tax. Depletion expense for U.S. GAAP is reduced by $60 million (2005 — $62 million; 2004 — $76 million), before tax of $19 million (2005 — $21 million; 2004 — $27 million).

Under U.S. GAAP, prices used in the reserve determination were those in effect at the applicable year-end. For Canadian GAAP, forecast prices are used in the reserve determination. The different prices result in a lower reserve base for U.S. GAAP. Additional depletion of $39 million, net of tax of $14 million, was recorded under U.S. GAAP in December 2004. As of the first quarter of 2005 these reserves have become economical again. Depletion expense for U.S. GAAP is reduced by $4 million (2005 — $4 million), before tax of $1 million (2005 — $2 million).

(b)  The Company records all derivative instruments as assets and liabilities on the balance sheet based on their fair values as required under Statement of Financial Accounting Standards (“FAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” At December 31, 2006, the Company recorded additional assets and liabilities for U.S. GAAP purposes of $5 million (2005 — $7 million; 2004 — $52 million) and $31 million (2005 — $39 million; 2004 — $93 million), respectively, for the fair values of derivative financial instruments. The Company also recorded a gain of nil, net of tax (2005 — gain of less than $1 million; 2004 — loss of less than $1 million), in revenue for U.S. GAAP purposes with respect to derivatives designated as fair value hedges relating to commodity price risk. In addition, the amount included in other comprehensive income was decreased by $3 million net of tax (2005 — increased by $1 million; 2004 — decreased by $51 million), for changes in the fair values of the derivatives designated as hedges of cash flows relating to commodity price risk, foreign exchange risk and the transfer to income of amounts applicable to cash flows occurring in 2006. In 2004, the Company unwound its long-dated foreign exchange forwards. The unrealized gain of $5 million, before tax was deferred in other comprehensive income and recognized in 2005 when the underlying transactions

25

took place. In 2005 and 2003 the Company unwound interest rate swaps that were fair value hedges of debt for proceeds of $37 million and $44 million, respectively. Under Canadian GAAP, the proceeds received have been recorded to current and long-term liabilities and are being deferred over the life of the debt. For U.S. GAAP purposes, the balance in the current and long-term liabilities has been reclassified to long-term debt consistent with fair value hedge treatment.

(c)

Under U.S. GAAP, natural gas purchase and sale contracts related to energy trading activities are recorded at fair value in accordance with Emerging Issues Task Force (“EITF”) 02-03, “Issues Involved in Accounting for Derivative Contracts held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” Under Canadian GAAP, the impact of energy trading contracts is recorded as they settle. Under U.S. GAAP, at December 31, 2006, the Company recorded additional assets and liabilities of $6 million (2005 — $49 million; 2004 — $4 million) and nil (2005 — $48 million; 2004 — $3 million), respectively, and included the resulting unrealized gain, net of tax of $3 million (2005 — gain of less than $1 million; 2004 — loss of $1 million), in earnings for the year. Under U.S. GAAP, gains and losses on energy trading contracts have been netted against sales and operating revenues.

(d)

Effective January 1, 2004, under Canadian GAAP, the Company adopted fair value accounting for stock-based compensation retroactively without restatement, which is consistent with the recommendations in FAS 123, “Accounting for Stock-based Compensation — Transition and Disclosure.”

In January 2006, the Company adopted the fair value accounting provisions under FAS 123(R), “Share-Based Payment.” Under FAS 123(R) awards that are classified as liabilities are re-measured based on the award’s fair value at each reporting date until settlement. Under FAS 123 awards classified as liabilities were measured at their intrinsic value. FAS 123(R) was adopted using the modified prospective application method. The related cumulative effect of the change in accounting principle to net earnings at December 31, 2005 was an increase of $16 million, before tax of $5 million. The change resulted in a decrease to current liabilities of $12 million and long-term liabilities of $4 million and an increase to future income tax liability of $5 million. There was no impact on the Company’s cash flow as a result of adoption of FAS 123(R).

At December 31, 2006, for U.S. GAAP purposes the Company recorded a decrease to current liabilities of $7 million and an increase to long-term liabilities of $1 million. The Company also recorded an increase to net earnings of $6 million, before tax of $2 million.

Under FAS 123(R), the Company is using the Black-Scholes option pricing model to estimate the fair value of the liability related to the options issued under the Company’s tandem plan. The assumptions used in calculating fair value were:

	2006
Initial expected life (years)		3.5
Expected annual dividend per share	$	2.00

At December 31, 2006, the total intrinsic value of options exercised during the year was $7 million, the share-based liability paid for the year was $97 million and the total fair value of options vested during the year was $87 million.

The weighted average remaining contractual term of options fully vested and currently exercisable is 2.4 years. The aggregate intrinsic value of options fully vested and currently exercisable is $120 million and the aggregate intrinsic value of options fully vested and expected to vest is $267 million. The unrecognized compensation cost for 2006 related to non-vested awards is $30 million and the weighted average period that these costs will be recognized over is 0.9 years.

(e)	As a result of the reorganization of the capital structure which occurred in 2000, the deficit of Husky Oil Limited of $160 million was eliminated. Elimination of the deficit would not be permitted under U.S. GAAP.
(f)	Until 1997 the Company recorded interest waived on subordinated shareholders’ loans and dividends waived on Class C shares as a reduction of ownership charges. Under U.S. GAAP, waived interest and dividends in those years would be recorded as interest on subordinated shareholders’ loans and dividends on Class C shares and as capital contributions.
(g)	Under FAS 87, “Employers’ Accounting for Pensions,” the Company amortized the portion of the unrecognized gains or losses that exceeded 10% of the greater of the projected benefit obligation or the market-related value of pension plan assets. The market-related value of pension plan assets is the fair value of the assets or a calculated value that recognizes changes in fair value over not more than five years. An additional minimum liability was recognized if the unfunded accumulated benefit obligation exceeded the unfunded pension cost already recognized. If an additional minimum liability was recognized, an amount equal to the unrecognized prior service cost was recognized as an intangible asset and any excess was reported in other comprehensive income.

At December 31, 2006, the additional minimum liability was increased by $6 million (2005 — increase of $6 million; 2004 — decrease of $1 million) with a decrease to other comprehensive income of $5 million (2005 — decrease of $5 million; 2004 — decrease of less than $1 million), net of tax.

In December 2006, the Company adopted FAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This standard requires the Company to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability. The funded status is measured as the difference between the fair value of a plan’s assets and its benefit obligations. Changes in this funded status are recognized through comprehensive income in the year in which the change occurs. The additional minimum liability previously recorded under FAS 87 has been eliminated. There is no impact to earnings recognition under the new requirement.

26

The following is the impact of initially applying FAS 158:

	Before						After
	FAS 158			Adoption			FAS 158
	Adoption			Adjustment			Adoption
Consolidated Balance Sheets
Assets
Other assets — prepaid pension asset	$	19		$	(19	)	$	—
Liabilities and Shareholders’ Equity Additional minimum liability		36			(36	)		—
Long-term liability — pension payable		30			(30	)		—
Current liability — unfunded status of plan		—			8			8
Long-term liability — unfunded status of plan		—			58			58
Future income taxes		3,216			(6	)		3,210
Accumulated other comprehensive income		(43	)		(13	)		(56	)

The amounts reported in accumulated other comprehensive income at December 31, 2006 are comprised of experience gains and losses from prior periods and $5 million is expected to be recognized as a component of net periodic benefit cost over the next year. The Company does not expect to return any of the plan assets to the Company within the next year.

Additional U.S. GAAP Disclosures

Corporate Acquisitions

As described in note 7, Corporate Acquisition, the Company purchased all of the outstanding shares of Temple Exploration Inc. This transaction increased the reserve base and created cost efficiencies, increasing shareholder value.

Accounting for Derivative Instruments and Hedging Activities

Effective January 1, 2001, the Company adopted the provisions of FAS 133, which require that all derivatives be recognized as assets and liabilities on the balance sheet and measured at fair value. Gains or losses, including unrealized amounts, on derivatives that have not been designated as hedges are included in earnings as they arise.

For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with equal or lesser amounts of changes in the fair value of the hedged item. No portion of the fair value of the derivatives related to time value has been excluded from the assessment of hedge effectiveness in these hedging relationships.

For derivatives designated as cash flow hedges, the portion of the changes in the fair value of the derivatives that are effective in hedging the changes in future cash flows are recognized in other comprehensive income until the hedged items are recognized in earnings. Any portion of the change in the fair value of the derivatives that is not effective in hedging the changes in future cash flows is included in earnings. No portion of the fair value of the derivatives related to time value has been excluded from the assessment of hedge effectiveness in these hedging relationships.

Stock Option Plan

In December 2004, the Financial Accounting Standards Board (“FASB”) issued FAS 123(R), which replaces FAS 123 and supersedes Accounting Principles Board (“APB”) Opinion 25. FAS 123(R) requires compensation cost related to share-based payments be recognized in the financial statements and that the cost must be measured based on the fair value of the equity or liability instruments issued. Under FAS 123(R) all share-based payment plans must be valued using option-pricing models. For U.S. GAAP, the liability related to the options issued under the Company’s tandem plan is measured at fair value using an option pricing model. Under Canadian GAAP, the liability is measured based on the intrinsic value of the option. Over the life of the option the amount of compensation expense recognized will differ under U.S. and Canadian GAAP, creating a temporary GAAP timing difference. At exercise or surrender of the option, the compensation expense to be recorded will be equal to the cash payment, which will be identical under U.S. and Canadian GAAP and there will no longer be a GAAP difference. FAS 123(R) was effective January 1, 2006.

Depletion, Depreciation and Amortization

Upstream depletion, depreciation and amortization per gross equivalent barrel is calculated by converting natural gas volumes to a barrel of oil equivalent (“boe”) using the ratio of 6 mcf of natural gas to 1 barrel of crude oil (sulphur volumes have been excluded from the calculation). Depletion, depreciation and amortization per boe as calculated under U.S. GAAP for the years ended December 31 were as follows:

	2006		2005		2004
Depletion, depreciation and amortization per boe	$	10.75	$	9.38	$	8.76

Accounting for Inventory Costs

In November 2004, the FASB issued FAS 151, “Inventory Costs,” which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material as they relate to inventory costing. FAS 151 requires these items to be recognized as current period expenses. Additionally, the allocation of fixed production overheads to the cost of inventory should be based on the normal capacity of the production facilities. FAS 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The application of FAS 151 did not have an impact on the financial statements.

27

Accounting for Exchanges of Nonmonetary Assets

In December 2004, the FASB issued FAS 153, “Exchanges of Nonmonetary Assets,“which deals with the accounting for the exchanges of nonmonetary assets. FAS 153 is an amendment of APB Opinion 29. APB Opinion 29 requires that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged.

FAS 153 amends APB Opinion 29 to eliminate the exception from using fair market value for nonmonetary exchanges of similar productive assets and introduces a broader exception for exchanges of nonmonetary assets that do not have commercial substance. FAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of FAS 153 did not have an impact on the financial statements.

Accounting Changes and Error Corrections

In May 2005, the FASB issued FAS 154, “Accounting Changes and Error Corrections,” which deals with all voluntary changes in accounting principles and changes required by an accounting pronouncement if that pronouncement does not include specific transition provisions. FAS 154 replaces APB Opinion 20, “Accounting Changes” and FAS 3, “Reporting Accounting Changes in Interim Financial Statements.” This Statement requires retrospective application of a change in accounting principle to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change, in which case the change in principle is applied as if it were adopted prospectively from the earliest date practicable. Corrections of an error require adjusting previously issued financial statements. FAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005.

Accounting for Certain Hybrid Financial Instruments

In February 2006, the FASB issued FAS 155, “Accounting for Certain Hybrid Financial Instruments — an Amendment of FASB Statements No. 133 and 140,” which addresses a temporary exemption from the application of the bifurcation requirements of FAS 133 to beneficial interests in securitized financial assets. Under the new standard, a requirement exists to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative which requires bifurcation. FAS 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative and would otherwise require bifurcation from the host contract. This standard eliminates the exemption from applying FAS 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. FAS 155 also eliminates the exclusion of a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. FAS 155 is effective for all financial instruments acquired or issued in fiscal years beginning after September 15, 2006. The Company does not have any material hybrid financial instruments.

Accounting for Servicing of Financial Assets

In March 2006, the FASB issued FAS 156, “Accounting for Servicing of Financial Assets — an Amendment of FASB Statement No. 140.” This Statement requires an entity to recognize a servicing asset or servicing liability each time it undergoes an obligation to service a financial asset by entering into certain servicing contracts. All separately recognized servicing assets and servicing liabilities are initially measured at fair value. For subsequent measurement of servicing assets and servicing liabilities, an entity is permitted to choose between the amortization method and the fair value measurement method. FAS 156 requires separate presentation of servicing assets and servicing liabilities subsequently measured in the balance sheet. Additional disclosures are required for separately recognized servicing assets and servicing liabilities. FAS 156 is effective for the first fiscal year beginning after September 15, 2006. The Company does not believe that the application of FAS 156 will have a material impact on the financial statements.

Fair Value Measurement

In September 2006, the FASB issued FAS 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in U.S. GAAP pronouncements and expands the disclosure requirements for fair value measurements. Prior to FAS 157, various definitions of fair value existed with limited guidance for application of these definitions in U.S. GAAP. Fair value under this standard is focused on a market-based measurement as opposed to an entity-specific measurement. This standard establishes a fair value hierarchy which distinguishes between market participant assumptions based on market data obtained from independent sources and the reporting entity’s own assumptions about the market. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The provisions of this Statement are applied prospectively with certain exceptions which require retrospective application. The Company will consider this fair value measurement framework when applying other U.S. GAAP pronouncements where fair value is a consideration.

Accounting for Uncertainty in Income Taxes

In June 2006, the FASB issued FASB Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.” This interpretation clarifies the accounting for the uncertainty in income taxes recognized in accordance with FAS 109. FIN 48 establishes a two-step process for the evaluation of a tax position taken or expected to be taken in a tax return. The first step recognizes whether or not a tax position is sustainable based on a “more-likely-than-not” determination. The second step measures the amount of tax benefit to recognize in the financial statements if the tax position meets the more-likely-than-not threshold. Under FIN 48, the tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is currently determining the impact of this issue.

Accounting for Purchases and Sales of Inventory with the Same Counterparty

In September 2005, the EITF redeliberated EITF 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” In arrangements whereby one inventory transaction is legally contingent upon the performance of another inventory transaction with the same counterparty, these transactions are considered a single exchange transaction subject to APB Opinion No. 29. EITF 04-13 clarifies that nonmonetary exchanges whereby an entity transfers finished goods inventory in exchange for the receipt of raw materials or work-in-progress inventory within the

28

same line of business is not an exchange transaction to facilitate sales to customers. These nonmonetary exchanges are required to be recognized at fair value if reasonably determinable and the transaction has commercial substance. All other nonmonetary exchanges of inventory within the same line of business are to be recognized at the carrying amount of the inventory transferred. EITF 04-13 is effective for new arrangements entered into, and modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006. The application of EITF 04-13 did not have a material impact on the financial statements.

Quantifying Financial Statement Misstatements

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) 108 on quantifying financial statement misstatements. This guidance outlines the approach that the SEC believes registrants should use in quantifying and evaluating misstatements of financial statements. SAB 108 requires registrants to adjust their financial statements if the misstatement quantified under the new approach, including prior-year effects, results in a material error in the current year. This adjustment is required even if misstatements of prior years are considered immaterial. If registrants followed an acceptable approach to quantifying financial statement misstatements in the past, the SEC will not require these registrants to restate prior years’ historical financial statements. Instead, these registrants will be able to report the cumulative effect of adopting the new approach as an adjustment to the current year’s beginning retained earnings balance. If entities correct prior-year financial statements for immaterial errors, this guidance does not require amendments to previously filed reports. Instead, this correction can be made the next time the entity files the prior year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The application of SAB 108 did not have an impact on the financial statements.

29

Document C

Form 40-F

MANAGEMENT’S DISCUSSION AND ANALYSIS

February 26, 2007

MANAGEMENT’S DISCUSSION AND ANALYSIS

February 26, 2007

TABLE OF CONTENTS

			Page
1.	Financial and Operational Overview		2
		1.1  Husky’s Business	2
		1.2  Financial Overview	3
		1.3  Selected Annual Information	4
		1.4  Selected Quarterly Information	4
		1.5  Major Events in 2006	4
2.	Capability to Deliver Results		5
		2.1  Upstream	5
		2.2  Midstream	6
		2.3  Refined Products	6
		2.4  Key Performance Drivers and Measures	6
		2.5  The Business Environment in 2006	8
3.	Strategy		10
		3.1  Strategic Imperatives	10
		3.2  Major Projects	12
4.	Results of Operations		14
		4.1  Upstream	14
		4.2  Midstream	23
		4.3  Refined Products	25
		4.4  Corporate	26
		4.5  2005 Compared with 2004	28
5.	2007 Outlook		29
		5.1  General Economy	29
		5.2  2007 Capital Program	29
		5.3  Upstream	30
		5.4  Midstream	31
		5.5  Refined Products	31
6.	Liquidity and Capital Resources		31
		6.1  Summary of Cash Flow	31
		6.2  Working Capital Components	32
		6.3  Cash Requirements	34
		6.4  Off-Balance Sheet Arrangements	35
		6.5  Transactions with Related Parties and Major Customers	35
		6.6  Financial Risk and Risk Management	35
		6.7  Outstanding Share Data	36
7.	Application of Critical Accounting Estimates		36
		7.1  Full Cost Accounting for Oil and Gas Activities	37
		7.2  Impairment of Long-lived Assets	37
		7.3  Fair Value of Derivative Instruments	37
		7.4  Asset Retirement Obligations	38
		7.5  Legal, Environmental Remediation and Other Contingent Matters	38
		7.6  Income Tax Accounting	38
		7.7  Business Combinations	38
		7.8  Goodwill	38
		7.9  Variable Interest Entities	39
8.	New Accounting Standards		39
		8.1  Canadian Accounting	39
		8.2  U.S. Accounting	39
9.	Pending Accounting Standards		40
		9.1  Canadian Accounting Pronouncements	40
		9.2  U.S. Accounting Pronouncements	41
10.	Forward-looking Statements		42
11.	Oil and Gas Reserve Reporting		43
12.	Non-GAAP Measures		43
13.	Additional Reader Advisories		44
14.	Controls and Procedures		44

1

1.  FINANCIAL AND OPERATIONAL OVERVIEW

1.1  HUSKY’S BUSINESS

Core Businesses

Husky is an energy and energy related enterprise operating in three integrated business segments:

Upstream

Exploration and development of crude oil, bitumen and natural gas in:

•  the Western Canada Sedimentary Basin;

•  the oil sands regions of Alberta;

•  the Jeanne d’Arc Basin off the East Coast of Canada;

•  the Mackenzie Valley in the Northwest Territories;

•  the South China Sea and the East China Sea; and

•  the Madura Strait and north east Java Sea, offshore Indonesia.

Midstream

•  heavy oil upgrader located at Lloydminster, Saskatchewan with a current throughput capacity of approximately 76 mbbls/day yielding 65 mbbls/day of synthetic crude oil and 11 mbbls/day of diluent;

•  pipeline systems with combined capacity in excess of 500 mbbls/day in the heavy oil producing regions between Cold Lake, Alberta south through Lloydminster to Hardisty, Alberta; and

•  crude oil and natural gas storage facilities, cogeneration and commodity marketing.

Refined Products

•  505 retail and wholesale locations from the West Coast of Canada to the eastern border of Ontario;

•  a recently upgraded 12 mbbls/day full slate refinery in Prince George, British Columbia;

2

•  a 28 mbbls/day asphalt refinery in Lloydminster, Alberta and Western Canada asphalt marketing and distribution system; and

•  ethanol plants at Lloydminster, Saskatchewan and Minnedosa, Manitoba with current combined annual capacity of 140 million litres. The Minnedosa, Manitoba ethanol plant expansion in 2007 will increase combined annual capacity to 260 million litres.

1.2  FINANCIAL OVERVIEW

Financial Position

Financial Performance

3

1.3  SELECTED ANNUAL INFORMATION

	2006			2005			2004
	($ millions, except where indicated)
Sales and operating revenues, net of royalties	$	12,664		$	10,245		$	8,440
Segmented earnings
Upstream	$	2,295		$	1,524		$	713
Midstream		482			495			240
Refined Products		106			82			41
Corporate and eliminations		(157	)		(98	)		12
Net earnings	$	2,726		$	2,003		$	1,006
Per share
Basic and diluted	$	6.43		$	4.72		$	2.37
Dividends per common share	$	1.50		$	0.65		$	0.46
Special dividend per common share	$	—		$	1.00		$	0.54
Total assets	$	17,933		$	15,716		$	13,233
Long-term debt excluding current portion	$	1,511		$	1,612		$	2,047
Return on equity (percent)		31.8			29.2			17.0
Return on average capital employed (percent)		27.0			22.8			13.0

1.4  SELECTED QUARTERLY INFORMATION

	2006								2005
	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
	($ millions, except where indicated)
Sales and operating revenues, net of royalties	$	3,084	$	3,436	$	3,040	$	3,104	$	3,207	$	2,594	$	2,350	$	2,094
Net earnings		542		682		978		524		669		556		394		384
Per share
Basic and diluted		1.28		1.61		2.31		1.24		1.58		1.31		0.93		0.91
Cash flow from operations		1,207		1,224		1,103		967		1,197		944		828		816
Per share
Basic and diluted		2.84		2.88		2.60		2.28		2.82		2.23		1.95		1.93
Share price
High		80.45		83.00		75.64		74.50		65.79		69.95		50.75		40.49
Low		66.20		66.31		58.00		59.63		50.50		47.37		35.12		32.30
Close (end of period)		78.04		71.96		70.06		70.65		59.00		64.57		48.73		36.33
Shares traded (thousands)		41,889		30,786		39,674		39,543		38,731		34,521		46,988		46,370
Dividends declared per common share		0.50		0.50		0.25		0.25		0.25		0.14		0.14		0.12
Special dividend per common share		—		—		—		—		1.00		—		—		—
Weighted average number of common shares outstanding (thousands)
Basic and diluted		424,264		424,234		424,179		424,147		424,120		424,049		423,891		423,791

1.5  MAJOR EVENTS IN 2006

East Coast

•  completed sixth production well in November 2006, which increased White Rose productive capacity to approximately 125 mbbls/day. During December 2006 total field production at White Rose averaged 116 mbbls/day (Husky’s working interest share was 85 mbbls/day), an increase of 17% from November; and

•  increased our holdings in the Jeanne d’Arc Basin with the acquisition of two exploration licences totalling 38,585 acres and increased our working interest in Significant Discovery Licences 1040 and 1008 with a farm-in.

4

Oil Sands

•  completed construction of the 100% working interest steam-assisted gravity drainage (“SAGD”) in-situ Tucker Oil Sands project. With a design rate capacity of 30 mbbls/day of bitumen, the project will be ramped up to its capacity over the next two years. Proved reserves at December 31, 2006 were 60 mmbbls of bitumen; and

•  increased our Saleski, Alberta oil sands holdings to 239,200 acres.

Ethanol

•  completed construction of Lloydminster ethanol plant. With a design rate capacity of 130 million litres of ethanol per year, the plant will participate in providing ethanol blending feedstock for the emerging market for ethanol blended gasoline.

Refining

•  completed the second phase of the Prince George refinery clean fuels project to produce low-sulphur diesel and gasoline and increased productive capacity to 12 mbbls/day.

International

•  increased our holdings in the South China Sea with an award of three exploration blocks totalling 16,871 square kilometres;

•  natural gas discovery in the South China Sea at Liwan 3-1-1; and

•  increased our holdings in the north east Java Sea with the East Bawean II block.

Corporate

•  redeemed the 8.45% senior secured bonds, due 2012, which had an outstanding balance of U.S. $85 million;

•  received an improved credit rating from Standard and Poor’s Rating Service to BBB+ with a stable outlook; and

•  renewed the shelf prospectus, which facilitates the issue of up to U.S. $1 billion of debt securities in the U.S. capital markets until October 2008.

2.  CAPABILITY TO DELIVER RESULTS

Our strategic plans involve a number of large initiatives in our upstream business that are expected to provide the means to achieve our corporate goals. We expect to reach our goals without compromising our financial capacity and flexibility. We expect to maintain our workforce through increasing investment in training, mentoring, succession and retention programs.

2.1  UPSTREAM

Upstream business strengths include:

•  a large base of producing properties in Western Canada that generally respond well to increasingly sophisticated exploitation techniques and, we expect, will continue to provide a large proportion of cash flow necessary to undertake current and future major growth projects;

•  significant natural gas potential in the deep basin, foothills and northwest plains;

•  a dominant presence and extensive experience in the heavy oil producing areas in the Lloydminster region of Alberta and Saskatchewan;

•  a recently developed SAGD oil sands project and substantial long-term growth potential in a number of the oil sands regions of Alberta;

•  two major offshore producing oil fields in the Jeanne d’Arc Basin off the East Coast of Canada, combined with a large portfolio of significant discovery licences and exploration licences;

•  significant opportunities to tie-back production from satellite fields to the existing White Rose production;

•  increasing experience and number of developable projects and potential prospects in Southeast Asia; and

•  the financial capacity to enhance our portfolio value through acquisitions.

5

Upstream business will be challenged by:

•  increasing costs driven by the high level of oil and gas industry activity;

•  labour market skills shortages;

•  a highly competitive environment for materials, equipment and services;

•  increasing difficulty and cost of managing the natural production declines of our properties in the Western Canada Sedimentary Basin;

•  susceptibility of large complex operations to reliability issues and significant loss of cash flow during down-time;

•  increasing activities of opposing special interest groups;

•  increasing political pressure to implement fiscal regimes that might divert material cash flow available for investment; and

•  increasing uncertainty of environmental issues that may delay, prevent or increase the costs of oil and gas development.

2.2  MIDSTREAM

Midstream business strengths include:

•  a modern, reliable heavy oil upgrading facility located in the Lloydminster heavy oil producing region, currently completing a number of debottlenecking projects and capable of major expansion;

•  reliable heavy oil pipeline systems in the Lloydminster heavy oil producing region currently being expanded;

•  participation in electrical/thermal cogeneration that can be utilized in our plant operations; and

•  a commodity marketer capable of acting as a market balancer to both customer and supplier.

Midstream business will be challenged by:

•  increasingly heavier crude feedstock requiring expansion and modification of our upgrader; and

•  competition for pipeline capacity in heavy crude oil producing regions.

2.3  REFINED PRODUCTS

Refined products business strengths include:

•  an established niche market with prime marketing outlet locations and strategic land position;

•  recently upgraded low sulphur gasoline and diesel fuel refinery in north central British Columbia;

•  growing economies of scale for our increasing ethanol production;

•  position as largest manufacturer of paving asphalt in Western Canada; and

•  modern asphalt manufacturing facilities at Lloydminster, Alberta.

Refined products business will be challenged by:

•  limited access to refining facilities sufficient to supply our refined product requirements;

•  increased competition as motor fuel and related products are increasingly being offered by other industry retailers; and

•  higher asphalt distribution costs as a result of plant locations and lack of asphalt distribution network in the United States and Eastern Canada.

2.4  KEY PERFORMANCE DRIVERS AND MEASURES

In order to achieve our mission of maximizing returns to our shareholders in a socially responsible manner we must, in the medium and long-term:

•  find and develop proved reserves of crude oil and natural gas at a cost that is competitive with the industry; and

•  acquire developed and undeveloped properties which complement our portfolio and provide enhanced potential for future sustainable growth.

6

In the short-term we must:

•  competitively optimize production through effective exploitation techniques;

•  make selective acquisitions and divestitures;

•  maintain costs among the industry’s lowest cost quartile performers;

•  manage our operations in a safe and environmentally responsible manner;

•  continue to proceed with the development of our major expansion projects in the Jeanne d’Arc Basin, the Alberta oil sands, the Madura Strait natural gas and NGL project;

•  delineate our oil discovery in the Mackenzie Valley region of the Northwest Territories;

•  delineate our natural gas prospect in the South China Sea; and

•  complete the optimization and expansion assessment of the Lloydminster Upgrader.

In addition to the metrics presented by financial statements, which are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), we prepare a number of additional performance indicators. Although these metrics may not be comparable with other companies, they are comparable from period to period within Husky and are important decision making tools for management.

The overall corporate performance metrics that we monitor with respect to achieving return to our shareholders’ goals are return on equity and return on average capital employed and are in Section 1.3, “Selected Annual Information.”

The following table shows the total shareholder return compared with the Standard and Poor’s and the Toronto Stock Exchange energy and composite indices.

	Husky Common Shares		S&P/TSX Energy Index			S&P/TSX Composite Index
	(%)		(%)			(%)
2002		0.00		(14.00	)		11.00
2003		43.00		24.42			24.32
2004		45.45		12.15			28.26
2005		72.12		22.50			59.89
2006		32.40		14.59			1.14
Five-year average		36.51		10.93			23.47
Five-year return		374.00		68.00			187.00

Revenue Performance

Our revenues are sensitive primarily to changes in the commodity prices we receive for the products we sell, particularly for our production of crude oil and natural gas. Changes in these prices are caused by many factors that are outside of our control. As a result we must focus on increasing the volume of the commodities that we produce. All plans to increase production must be expected to achieve minimum rates of return before capital is allocated. Production is subsequently measured against expected results.

Cost Performance

Cost of sales and operating expenses comprise many components such as energy and crude oil feedstock costs for refining and upgrading operations and refined product purchase costs for the majority of our refined products marketing operations. Our focus is on optimizing our costs to achieve a competitive position in the industry.

Capital Performance

Before capital is allocated to a project, its expected benefits must achieve an appropriate rate of return. Capital expenditures are monitored on a project-by-project basis and requirements for capital supplements are approved only by senior executive management. Upstream capital, which generally accounts for the majority of our capital budget, is monitored in detail to ensure that it achieves the desired result, which is to increase production, optimize operating expenses or increase reserves.

People Performance

We continually monitor the effectiveness of our work environment and corporate culture. To help us foster the development of a value-based culture, we monitor attrition rates as well as the results of exit interviews and training

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statistics. We facilitate and maintain a workplace that is respectful, inclusive, safe and socially responsible. We also keep informed of industry trends to ensure that we are well placed in the market with respect to being an employer of choice.

Health, Safety and Environmental Performance

We monitor all recordable accidents and all reportable environmental events that involve our operations. In addition, we conduct root cause investigations subsequent to events and regular audits to ensure full compliance.

2.5  THE BUSINESS ENVIRONMENT IN 2006

Our financial results are significantly influenced by the global and domestic business and operating environment. Some factors are entirely beyond our control and others can be strategically managed. Salient factors include:

•  crude oil and natural gas prices;

•  the price differential between light and discounted heavy crude oil and demand related to various crude oil qualities;

•  the cost to find, develop, produce and deliver crude oil and natural gas;

•  the availability of new proved reserves of oil and gas, sourced from exploration, improved recovery and acquisitions;

•  potential actions of governments and regulatory authorities in the jurisdictions where we have operations;

•  prevailing climatic conditions in our operating and marketing locations; and

•  the exchange rate between the Canadian and U.S. dollar.

Average Benchmark Prices and U.S. Exchange Rate	2006		2005		2004
WTI crude oil  (U.S. $/bbl)		66.22		56.56		41.40
Brent crude oil  (U.S. $/bbl)		65.14		54.38		38.21
Canadian par light crude 0.3% sulphur  ($/bbl)		73.29		69.28		52.91
Lloyd heavy crude oil @ Lloydminster  ($/bbl)		39.92		31.07		28.75
NYMEX natural gas  (U.S. $/mmbtu)		7.23		8.62		6.14
NIT natural gas  ($/GJ)		6.62		8.04		6.44
WTI/Lloyd crude blend differential  (U.S. $/bbl)		22.00		21.01		13.65
U.S./Canadian dollar exchange rate  (U.S. $)		0.882		0.826		0.769

Profitability is largely determined by the prices realized for crude oil and natural gas. All of our crude oil production and the majority of our natural gas production receives the prevailing market price. The price for crude oil is determined largely by global factors and is beyond our control. The price for natural gas is determined more by the environment in North America, since virtually all natural gas production in North America is consumed by North American customers, predominantly in the United States. The price of natural gas, within its market area, is also subject to the supply and demand equation. Weather conditions may also exert a dramatic effect on short-term supply and demand.

The global decline in the supply of light crude oil has increased prices in line with demand from refineries that are limited to a light crude oil feedstock. The price of heavy crude oil has historically traded at a discount since light crude oil produces a higher yield of light refined products such as gasoline and heavy crude oil requires more complex refining processes for cracking, desulphurization and coking. Although the differential between light and heavy crude oil typically widens when light crude oil prices increase, heavy crude oil prices have increased as well. The higher prices for heavy crude oil encourage increased development and production of heavy oil consequently increasing the supply in the market. The market often becomes over supplied with heavy crude oil and in turn light/heavy differentials widen at the expense of heavy oil prices. Most refiners need higher discounts to use heavy oil to maintain a refining margins. Our upgrader, which is located in the Lloydminster heavy oil region, produces a synthetic light crude oil from heavy oil feedstock that will yield a high proportion of high value light products from light oil refining processes.

The majority of our crude oil and natural gas production is marketed in North America.

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Crude Oil

WTI and Husky Average Crude Oil Prices

($/bbl)

In 2006, the main benchmark crude oil, West Texas Intermediate, repeated the same pattern as it did in 2005, but at a higher price level. That pattern saw prices run up to the beginning of the hurricane season around August/September, reaching U.S. $77 and then decline to the end of the year when hurricanes did not cause any damage to the oil and gas infrastructure in the U.S. Gulf of Mexico. In addition, during 2006 crude oil prices fell much faster, leveling below U.S. $60/bbl by mid-October, a time when crude oil inventories in the United States reached 114% of five-year averages. The high crude oil inventories tended to mitigate the effect of any other threatened supply disruption such as the continued social unrest in Nigeria and Iraq. Prices rose only briefly after cold weather arrived in December.

Natural Gas

NYMEX Natural Gas, NIT Natural Gas and Husky Average Natural Gas Prices

(US$)

Natural gas prices declined during the first quarter of 2006 from January delivery contract highs over U.S. $14/mmbtu, which resulted from devastating hurricane damage to oil and gas infrastructure along the Gulf Coast, to near month contracts below U.S. $7/mmbtu at the end of March. Natural gas prices continued to fluctuate in the U.S. $7/mmbtu to U.S. $6/mmbtu range until August, when widespread hot weather increased cooling demand and induced a short lived

9

spike to the U.S. $8/mmbtu range. Prices then fell to just above U.S. $4/mmbtu as the Gulf of Mexico remained free of significant tropical storm activity and cooler temperatures prevailed. During the fourth quarter, natural gas prices first rose as a result of both hot weather in the southern states and cold weather in the north, then fell through December as temperatures moderated and natural gas inventories remained markedly higher than five-year averages.

SENSITIVITIES BY SEGMENT FOR 2006 RESULTS

The following table is indicative of the relative annualized effect on pre-tax cash flow and net earnings from changes in certain key variables in 2006. In essence, the disclosure shows what the effect would have been on 2006 financial results had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2006. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.

	2006					Effect on Pre-tax						Effect on
Sensitivity Analysis	Average			Increase		Cash Flow						Net Earnings
						($ millions)			($/share)(5)			($ millions)			($/share)(5)
Upstream and Midstream
WTI benchmark crude oil price	$	66.22		U.S. $	1.00/bbl		90			0.21			60			0.14
NYMEX benchmark natural gas price(1)	$	7.23		U.S. $	0.20/mmbtu		37			0.09			24			0.06
WTI/Lloyd crude blend differential(2)	$	19.95		U.S. $	1.00/bbl		(30	)		(0.07	)		(20	)		(0.05	)
Exchange rate (U.S. $ per Cdn $)(3)	$	0.882		U.S. $	0.01		(69	)		(0.16	)		(47	)		(0.11	)
Refined Products
Light oil margins	$	0.04		Cdn $	0.005/litre		16			0.04			11			0.02
Asphalt margins	$	9.88		Cdn $	1.00/bbl		9			0.02			6			0.01
Consolidated
Year-end translation of U.S. $ debt (U.S. $ per Cdn $)	$	0.858	(4)	U.S. $	0.01								9			0.02

(1)	Includes decrease in earnings related to natural gas consumption.
(2)	Includes impact of upstream and upgrading operations only.
(3)	Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items.
(4)	U.S./Canadian dollar exchange rate at December 31, 2006.
(5)	Based on December 31, 2006 common shares outstanding of 424.3 million.

3.  STRATEGY

3.1  STRATEGIC IMPERATIVES

Strategic Objective and Measures

Our strategy is to continue exploiting our oil and gas asset base in the Western Canada Sedimentary Basin while expanding into large scale sustainable areas including the Alberta oil sands, Canada’s East Coast and northern basins and highly prospective basins offshore Southeast Asia. In the global energy business environment, which has many risks, commodity prices being primary among them, we must maintain our financial discipline to successfully maintain this strategy.

Strategic Plans

Our ultimate success in achieving long-term objectives rests on the effective execution of a number of operational and financial strategies. In this regard we employ a planning process that provides critical consideration to our stated strategies and their possible outcomes.

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Upstream Strategies

•  manage declining production in Western Canada through field and facility optimization, increased multi-zone development, increase applications of enhanced oil recovery techniques, property consolidation, development of new core areas and exploitation of non-conventional natural gas reservoirs;

•  continue to explore for liquid rich natural gas reserves in the less mature, high-impact but technically challenging areas in the foothills, deep basin and northern plains;

•  continue with exploration in the Central Mackenzie Valley and complete delineation and evaluation of the Stewart Creek natural gas discovery in conjunction with the Summit Creek natural gas and liquids discovery 26 kilometres northwest of Stewart Creek;

•  continued delineation and development of the White Rose area satellite prospects and on our portfolio of significant discovery licences off the East Coast and also continue to explore for oil and gas on our large portfolio of exploration licences in the Jeanne d’Arc Basin offshore Newfoundland and Labrador;

•  expand the productive capacity of the SeaRose FPSO to 140 mbbls/day;

•  continue to study development options for natural gas export from the Jeanne d’Arc Basin;

•  continue to explore for oil and gas offshore China, delineate and evaluate the Liwan natural gas discovery on Block 29/26 in the Pearl River Mouth Basin;

•  development of our Indonesian natural gas and NGL BD field in the East Java Sea and exploration on the Madura Strait and East Bawean II blocks;

•  continue development of our large holdings in the Alberta oil sands area through in-situ recovery methods such as SAGD and other thermally based recovery techniques; and

•  take advantage of acquisition opportunities to enhance our current core properties and create new ones.

Midstream Strategies

•  continue to enhance performance of our upgrader and integrate the operation of the upgrader, asphalt refinery, cogeneration and ethanol facilities;

•  complete front-end engineering design to expand the upgrader to 150 mbbls/day;

•  further expansion and integration of pipelines and facilities;

•  expand natural gas storage capacity; and

•  development of an integrated CO₂ strategy.

Refined Products Strategies

•  continue to integrate Lloydminster asphalt refinery output with the upgrader;

•  expand ethanol production in Western Canada;

•  continue to pursue initiatives that promote asphalt standards and thereby recognize Husky’s asphalt quality; and

•  increase throughput per outlet through technology, new products and services.

Financial Objective and Strategies

Our financial objective and strategies are intended to maintain our financial condition and facilitate corporate acquisitions to leverage our core portfolio of assets. Strategies are:

•  maintain debt to capitalization ratio of less than 40%; and

•  maintain debt to cash flow from operations of less than two times.

We believe that the execution of these strategic plans will attain our primary objectives. We will also continue to act on acquisition opportunities that are strategic to our operations.

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3.2  MAJOR PROJECTS

UPSTREAM

Western Canada Enhanced Oil Recovery

During 2006, an alkaline surfactant polymer enhanced recovery project was implemented to extend the productive life of the Taber South Manville B Pool in Southern Alberta.

East Coast Canada Exploration and Delineation

•  In November 2006, we completed drilling of the North Amethyst K-15 delineation well in the Significant Discovery Licence (“SDL”) 1044 southwest of White Rose. The results were encouraging and analysis is continuing on this reservoir. Our working interest in SDL 1044 is 72.5%.

•  In October 2006, we completed drilling of the West Bonne Bay F-12 delineation well and the F-12Z side track well in the SDL 1040 block, which is adjacent to the Terra Nova field. Preliminary results indicate hydrocarbons in the Upper Hibernia Reservoir. Further analysis will determine more about the resources in this reservoir. Our working interest in SDL 1040 is 27.78%.

•  In June 2006, we completed drilling of the White Rose O-28 delineation well and the O-28X side track well in the SDL 1024 adjacent to the western border of the White Rose South Avalon field. The results were encouraging and an additional delineation well to determine the areal extent of the reservoir is planned for 2007. Our working interest in SDL 1024 is 72.5%.

•  A 3-D seismic program was shot on Exploration Licence 1067, northwest of the White Rose oil field, covering 270 square kilometres and on Exploration Licence 1011 in the Fortune area, southwest of White Rose, covering 625 square kilometres. Our 2007 exploration and delineation drilling program currently includes three locations in the Jeanne d’Arc Basin.

•  At Terra Nova, we are currently participating in a delineation well in the Far East Block.

White Rose

In November 2006, a sixth production well was completed at the White Rose South Avalon field, which has increased productive capacity to 125 mbbls/day.

Tucker Oil Sands Project

At Tucker, the first five wells of the total 32 completed well pairs were producing at the end of December and steaming of the other wells continued. Tucker will continue to ramp up production through the next two years to achieve its design rate of 30 mbbls/day of bitumen.

Sunrise Oil Sands Project

The conceptual design for the upstream development at the Sunrise Oil Sands project was completed in late 2006. This aspect of the project includes options for field development, oil treatment and steam generation. Front-end engineering design for Sunrise has commenced and is scheduled to be complete by the third quarter of 2007.

Five water source wells were drilled and evaluated in the fourth quarter of 2006 and an additional five water source wells and 29 stratigraphic test wells are planned for the current winter drilling season. Additional seismic data will be acquired over the initial development area this winter to enhance the geological interpretation and enable better well placement. Collaboration with various industry participants continued on regional infrastructure issues, including an access highway and airport.

Caribou Lake and Saleski

During 2006, we participated in three land sales in the Saleski area and acquired leases totalling 84,320 acres. We now hold leases totalling 239,200 acres in the Saleski area. In December, we submitted an application to the Alberta Energy and Utilities Board and Alberta Environment for the first phase of the Caribou Lake project.

Conceptual development planning continued with water source and disposal well studies for both Saleski and Caribou Lake and determination of an appropriate bitumen recovery process for Saleski. At Caribou Lake, we completed the selection of 44 stratigraphic well locations to be drilled during the 2006/2007 winter drilling season.

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Northwest Territories Exploration

A seismic program was completed during September 2006 that included our newly acquired Exploration Licence 441, which is contiguous with the eastern boundary of our Exploration Licence 397 containing the Stewart D-57 natural gas discovery. Based on the timing of this seismic program and subsequent analytical work we, with our partners, have decided to defer further exploration drilling until the winter of 2007/2008. This will allow for full incorporation of new seismic data into the prospect mapping that is currently underway.

China Exploration

During August 2006, we acquired three exploration blocks offshore China that in aggregate total 16,871 square kilometres. Block 29/06 is 9,265 square kilometres and located in the Pearl River Mouth Basin adjacent to Block 29/26, the location of the June 2006 Liwan natural gas discovery. Block 35/18 is 4,469 square kilometres and Block 50/14 is 3,137 square kilometres; both are located in the Yinggehai Basin west of Hainan Island. Under the terms of the agreement we will pay 100% of the costs to drill two wells on Block 29/06 and one well on each of the other two blocks. The China National Offshore Oil Corporation (“CNOOC”) has the option to participate in up to 51% of any future development.

At the Liwan natural gas discovery a side track well confirmed the pay zones in the original well. We also completed shooting 400 square kilometres of 3-D seismic over the Liwan discovery and it is currently being analyzed in preparation for delineation drilling. We are currently seeking tenders to drill an exploration well on Block 04/35 in the East China Sea and expect a spud date in the first half of 2007.

In the fourth quarter of 2006, the CNOOC agreed to a 3-D seismic program on Block 29/26, on which the Liwan natural gas discovery is located and also on the adjacent Block 29/06. The program will investigate several structures with characteristics similar to those of Liwan.

A deep water rig has been secured for a three-year term commencing in mid-2008 and will initially be deployed in the South China Sea.

Indonesia Natural Gas Development

At Madura, negotiations for a natural gas sales agreement are continuing. Development of the BD natural gas field is contingent on receiving government approval. In September 2006, Husky signed the Production Sharing Contract for the 4,254 square kilometre East Bawean II Block and is currently planning to commence a 3-D seismic program in the second half of 2007.

MIDSTREAM

Lloydminster Upgrader

The front-end engineering design for the major expansion of the Lloydminster Upgrader to 150 mbbls/day is approximately 25% complete. Completion of this engineering design is scheduled for the end of 2007.

Lloydminster Pipeline

The Lloydminster to Hardisty, Alberta pipeline expansion project phase one is currently underway and is nearing completion. Phase two is expected to be completed by September 2007. The additional 24-inch pipeline will facilitate the movement of heavy crude oil. Ultimately, this project will also facilitate movement of a higher volume of synthetic crude oil from our upgrader.

REFINED PRODUCTS

Lloydminster and Minnedosa Ethanol Plants

To meet the increasing demand for ethanol blended gasoline, we commenced construction of two motor fuel grade ethanol plants. One plant is located adjacent to our Upgrader at Lloydminster, Saskatchewan and was commissioned in September 2006. The other is at Minnedosa, Manitoba, the site of our existing ethanol plant. Construction of the new plant at Minnedosa is expected to be completed during the third quarter of 2007 and planned to be fully operational in the fourth quarter of 2007. Each plant is designed to have throughput capacity of 130 million litres of ethanol per year.

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4.  RESULTS OF OPERATIONS

Earnings from our three business segments increased each year from 2004 to 2006 and in each year our upstream business provided the majority of earnings. Midstream earnings were driven primarily by the upgrading operations, which reflect the wide differential between heavy and light crude oil.

Segmented Earnings

4.1  UPSTREAM

2006 EARNINGS $2,295 MILLION, UP $771 MILLION FROM 2005

Earnings Summary and 2006 Variance Analysis

Upstream earnings were $771 million higher in 2006 than in 2005 due to:

•  higher sales volume of light crude oil from White Rose;

•  higher crude oil prices; and

•  lower natural gas royalties.

Partially offset by:

•  lower natural gas prices and sales volume;

•  lower sales volume of light crude oil from Terra Nova and Wenchang;

•  higher operating costs;

•  higher depletion, depreciation and amortization; and

•  higher income taxes.

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Upstream Earnings Summary	2006		2005		2004
	($ millions)
Gross revenues	$	6,586	$	5,207	$	4,392
Royalties		814		840		711
Hedging loss		—		—		561
Net revenues		5,772		4,367		3,120
Operating and administration expenses		1,321		1,050		967
Depletion, depreciation and amortization		1,476		1,144		1,077
Income taxes		680		649		363
Earnings	$	2,295	$	1,524	$	713

Operating costs

Total upstream operating costs averaged $8.77/boe in 2006 compared with $8.12/boe in 2005.

Operating costs in Western Canada averaged $9.79/boe in 2006 compared with $8.59/boe in 2005. Increasing operating costs in Western Canada are related to the nature of exploitation necessary to manage production from maturing fields and new, more extensive, but less prolific, reservoirs. Western Canada operations require increasing amounts of infrastructure including equipping of more wells, more extensive pipeline systems and crude trucking and increased costs associated with operating larger and more extensive natural gas compression systems. These factors in turn require higher energy consumption, workovers and generally more material costs. In addition, higher levels of industry activity lead naturally to competition for resources and consequential higher service rates and unit costs.

Operating costs at the East Coast offshore operations averaged $5.48/bbl in 2006 compared with $5.14/bbl in 2005. Unit operating costs increased as a result of maintenance costs combined with low production volume at Terra Nova, partially offset by lower unit operating costs at White Rose, which benefited by higher production and reliable asset performance. Unit operating costs at White Rose averaged $4.22/bbl in 2006.

Operating costs at the South China Sea offshore operations averaged $3.61/bbl compared with $2.92/bbl in 2005. Increased unit operating costs are due to natural production declines.

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Depletion, Depreciation and Amortization (“DD&A”)

DD&A under the full cost method of accounting for oil and gas activities is calculated on a country-by-country basis. The DD&A rate is calculated by dividing the capital costs subject to DD&A by the proved oil and gas reserves expressed as equivalent barrels or boe. The resultant dollar per boe is assigned to each boe of production to determine the DD&A expense for the period.

Total DD&A averaged $11.24/boe in 2006 compared with $9.95/boe in 2005.

DD&A in Canada averaged $11.24/boe in 2006 compared with $10.10/boe in 2005. The increase in DD&A is mainly due to higher capital. Increasing capital is due to increased drilling and associated infrastructure in Western Canada and large capital investment required to develop offshore reserves off the East Coast of Canada.

DD&A in China averaged $11.22/boe in 2006 compared with $7.23/boe in 2005. Increasing unit DD&A results from lower reserves due to reservoir depletion.

Production

Daily Production, before Royalties	2006		2005		2004
Light crude oil & NGL (mbbls/day)		111.0		64.6		66.2
Medium crude oil (mbbls/day)		28.5		31.1		35.0
Heavy crude oil & bitumen (mbbls/day)		108.1		106.0		108.9
Total crude oil & NGL (mbbls/day)		247.6		201.7		210.1
Natural gas (mmcf/day)		672.3		680.0		689.2
Barrels of oil equivalent (6:1) (mboe/day)		359.7		315.0		325.0

Average Sales Prices	2006		2005		2004
Crude oil ($/bbl)
Light crude oil & NGL	$	69.06	$	61.56	$	48.34
Medium crude oil		49.48		43.44		36.13
Heavy crude oil		39.92		31.09		28.66
Total average		54.08		42.75		36.07
Total average after hedging		54.08		42.75		28.43
Natural gas ($/mcf)
Average	$	6.47	$	7.96	$	6.25
Average after hedging		6.47		7.96		6.24

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Upstream Revenue Mix (1)	2006		2005		2004
Percentage of upstream sales revenues, after royalties
Light crude oil & NGL		45		29		27
Medium crude oil		7		9		11
Heavy crude oil & bitumen		24		24		27
Natural gas		24		38		35
Total		100		100		100

Effective Royalty Rates (1)	2006		2005		2004
Percentage of upstream sales revenues, after royalties
Light crude oil & NGL		8		14		13
Medium crude oil		18		18		18
Heavy crude oil		13		12		12
Bitumen		1		—		—
Natural gas		18		20		22
Total		13		16		16

(1)  Before commodity hedging.

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Operating Netbacks

	Western Canada						East Coast						International						Total
	2006		2005		2004		2006		2005		2004		2006		2005		2004		2006		2005		2004
Light Crude Oil
(per boe) (1)
Sales price	$	59.89	$	60.74	$	46.12	$	71.18	$	62.61	$	47.87	$	73.60	$	63.15	$	47.66	$	68.51	$	61.86	$	46.95
Royalties		7.34		8.66		7.76		1.95		5.91		1.80		12.17		5.93		4.91		4.49		7.22		5.71
Operating costs		11.89		9.86		8.94		5.48		5.14		3.28		3.81		2.92		2.16		6.96		6.88		5.82
		40.66		42.22		29.42		63.75		51.56		42.79		57.62		54.30		40.59		57.06		47.76		35.42
Medium Crude Oil
(per boe) (1)
Sales price		48.97		43.67		36.20														48.97		43.67		36.20
Royalties		8.61		7.77		6.10														8.61		7.77		6.10
Operating costs		13.09		10.97		10.07														13.09		10.97		10.07
		27.27		24.93		20.03														27.27		24.93		20.03
Heavy Crude Oil
(per boe) (1)
Sales price		39.91		31.22		28.73														39.91		31.22		28.73
Royalties		5.16		3.75		3.38														5.16		3.75		3.38
Operating costs		11.10		9.90		9.33														11.10		9.90		9.33
		23.65		17.57		16.02														23.65		17.57		16.02
Total Crude Oil
(per boe) (1)
Sales price		44.90		38.91		33.48		71.18		62.61		47.87		73.60		63.15		47.66		53.55		42.83		35.72
Royalties		6.14		5.41		4.75		1.95		5.91		1.80		12.17		5.93		4.91		5.28		5.49		4.58
Operating costs		11.60		10.10		9.41		5.48		5.14		3.28		3.81		2.92		2.16		9.53		9.13		8.36
		27.16		23.40		19.32		63.75		51.56		42.79		57.62		54.30		40.59		38.74		28.21		22.78
Natural Gas
(per mcfge) (2)
Sales price		6.65		8.02		6.25														6.65		8.02		6.25
Royalties		1.37		1.76		1.44														1.37		1.76		1.44
Operating costs		1.18		1.04		0.89														1.18		1.04		0.89
		4.10		5.22		3.92														4.10		5.22		3.92
Equivalent Unit
(per boe) (1)
Sales price		42.91		42.53		35.01		71.18		62.61		47.87		73.60		63.15		47.66		49.34		44.69		36.34
Royalties		6.97		7.45		6.22		1.95		5.91		1.80		12.17		5.93		4.91		6.19		7.29		5.96
Operating costs		9.79		8.59		7.85		5.48		5.14		3.28		3.81		2.92		2.16		8.77		8.12		7.32
	$	26.15	$	26.49	$	20.94	$	63.75	$	51.56	$	42.79	$	57.62	$	54.30	$	40.59	$	34.38	$	29.28	$	23.06

(1)	Includes associated co-products converted to boe.
(2)	Includes associated co-products converted to mcfge.

Oil and Gas Reserves

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Husky applied for and was granted an exemption from Canada’s National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” and provides oil and gas reserves disclosures in accordance with the United States SEC guidelines and the United States Financial Accounting Standards Board (“FASB”) disclosure standards. The information disclosed may differ from information prepared in accordance with National Instrument 51-101.

For more detail on our oil and gas reserves and the disclosures with respect to the FASB’s Statement No. 69, “Disclosures about Oil and Gas Producing Activities” and the differences between our disclosures and those prescribed by National Instrument 51-101, refer to our Annual Information Form available at www.sedar.com or our Form 40-F available at www.sec.gov or on our website at www.huskyenergy.ca.

McDaniel & Associates Consultants Ltd., an independent firm of oil and gas reserves evaluation engineers, was engaged to conduct an audit of Husky’s crude oil, natural gas and natural gas products reserves. McDaniel & Associates Consultants Ltd. issued an audit opinion stating that Husky’s internally generated proved and probable reserves and net present values are, in aggregate, reasonable, and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices in the United States and as set out in the Canadian Oil and Gas Evaluation Handbook.

Crude Oil and
Natural Gas	Proved Developed						Proved Undeveloped						Total Proved						Proved and Probable
Reserves Summary(1)	2006		2005		2004		2006		2005		2004		2006		2005		2004		2006		2005		2004
	(constant prices and costs before royalties)
Crude oil (mmbbls)
Light & NGL		257		226		191		30		47		47		287		273		238		428		462		465
Medium		79		80		80		8		11		6		87		91		86		102		105		96
Heavy		135		140		91		78		77		14		213		217		105		289		291		150
Bitumen		47		—		—		13		48		—		60		48		—		1,187		951		79
		518		446		362		129		183		67		647		629		429		2,006		1,809		790
Natural gas (bcf)		1,703		1,710		1,745		440		426		424		2,143		2,136		2,169		2,626		2,709		2,724
Total (mmboe)		802		731		653		202		254		138		1,004		985		791		2,444		2,260		1,244

(1)  Refer to Section 13 for Oil and Gas Reserves definitions.

     2006 Reserve Additions

Our proved oil and gas reserves are estimated in accordance with the regulations and guidance of the SEC and the FASB which, among other things, require proved reserves to be evaluated using prices in effect on the date of the reserve report.

     Additions of Crude Oil and NGL

The additions to crude oil and NGL proved reserves in 2006 amounted to 108 mmbbls and were largely from the White Rose oil field, heavy oil properties located in the Lloydminster area and the Tucker Oil Sands project. The change in proved reserves from net acquisition/divestiture activity was minor in 2006, resulting in additions of approximately one mmbbls of crude oil and NGL.

At the White Rose oil field, offshore Newfoundland and Labrador, proved reserve additions resulted from a combination of technical revisions and improved recovery based on the better than expected performance of the reservoir and the pressure maintenance scheme being utilized. Additions of proved reserves of light crude oil totalled 41 mmbbls at White Rose. White Rose produced 23 mmbbls in 2006.

At the Tucker Oil Sands project, located in the Cold Lake Oil Sands Deposits, proved reserve additions amounted to 13 mmbbls of bitumen bringing the total proved reserves at Tucker to 60 mmbbls at December 31, 2006. These proved reserves are attributable to the first phase of the Tucker SAGD project, which comprises 1.5 sections or approximately 3.9 square kilometres, and are expected to be recovered by 40 well pairs, of which 32 are complete. An additional 100 well pairs are currently contemplated to complete development at Tucker.

     Additions of Natural Gas

The additions to natural gas proved reserves from discoveries, extensions and improved recovery amounted to 317 bcf and acquisitions of 25 bcf, which were partially offset by net technical revisions of negative 87 bcf and divestitures of three bcf. The additions from discoveries, extensions and improved recovery were primarily from natural gas properties throughout the Western Canada Sedimentary Basin; approximately 38% of this class of change was attributable to four properties and 44% of the additions were located in the foothills/deep basin region of the basin. Approximately 22% of the

19

net negative revision of proved natural gas was due to low natural gas prices at December 31, 2006, a change that is expected to reverse when natural gas prices recover. The remaining negative revisions were due, for the most part, to more rapid production decline rates than expected.

	Canada																		International					Total
	Western Canada															East
	Light															Coast
	Crude			Medium			Heavy									Light			Light					Crude
	Oil &			Crude			Crude						Natural			Crude			Crude			Natural		Oil &			Natural			Equivalent
Reconciliation of Proved Reserves	NGL			Oil			Oil			Bitumen			Gas			Oil			Oil			Gas		NGL			Gas			Units
	(mmbbls)			(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(mmbbls)			(bcf)		(mmbbls)			(bcf)			(mmboe)
	(constant prices and costs before royalties)
Proved reserves at December 31, 2005		167			91			217			48			2,136			89			17			—		629			2,136			985
Technical revisions		(3	)		(1	)		(2	)		(1	)		(87	)		31			2			—		26			(87	)		11
Purchase of reserves in place		1			1			—			—			25			—			—			—		2			25			6
Sale of reserves in place		(1	)		—			—			—			(3	)		—			—			—		(1	)		(3	)		(1	)
Discoveries, extensions and improved recovery		13			6			37			13			317			12			—			—		81			317			134
Production		(11	)		(10	)		(39	)		—			(245	)		(25	)		(5	)		—		(90	)		(245	)		(131	)
Proved reserves at December 31, 2006		166			87			213			60			2,143			107			14			—		647			2,143			1,004
Proved and probable reserves
At December 31, 2006		219			102			289			1,187			2,533			186			23			93		2,006			2,626			2,444
At December 31, 2005		225			105			291			951			2,542			207			30			167		1,809			2,709			2,260

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	Canada																	International			Total
															East
	Western Canada														Coast
	Light
	Crude			Medium			Heavy								Light			Light			Crude
	Oil &			Crude			Crude					Natural			Crude			Crude			Oil &			Natural			Equivalent
Reconciliation of Proved Developed Reserves	NGL			Oil			Oil			Bitumen		Gas			Oil			Oil			NGL			Gas			Units
	(mmbbls)			(mmbbls)			(mmbbls)			(mmbbls)		(bcf)			(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmboe)
	(constant prices and costs before royalties)
Proved developed reserves at December 31, 2005		151			80			140			—		1,710			59			16			446			1,710			731
Revision of previous estimate		2			6			17			47		63			58			2			132			63			142
Purchase of reserves in place		1			1			—			—		14			—			—			2			14			4
Sale of reserves in place		(1	)		—			—			—		(3	)		—			—			(1	)		(3	)		(1	)
Improved recovery		5			2			17			—		164			5			—			29			164			57
Production		(11	)		(10	)		(39	)		—		(245	)		(25	)		(5	)		(90	)		(245	)		(131	)
Proved developed reserves at December 31, 2006		147			79			135			47		1,703			97			13			518			1,703			802

Upstream Capital Expenditures

Capital Expenditures(1)	2006		2005		2004
	($ millions)
Exploration
Western Canada	$	497	$	389	$	322
East Coast Canada and Frontier		79		66		24
International		77		55		18
		653		510		364
Development
Western Canada		1,675		1,618		1,211
East Coast Canada		279		579		515
International		20		23		67
		1,974		2,220		1,793
	$	2,627	$	2,730	$	2,157

(1)  Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions.

	2006				2005				2004
Western Canada Drilling	Gross		Net		Gross		Net		Gross		Net
	(wells)
Exploration
Oil		101		99		89		85		45		39
Gas		330		192		392		196		234		180
Dry		26		24		36		36		34		33
		457		315		517		317		313		252
Development
Oil		590		543		466		433		552		499
Gas		565		490		610		551		807		740
Dry		25		22		42		39		57		53
		1,180		1,055		1,118		1,023		1,416		1,292
Total		1,637		1,370		1,635		1,340		1,729		1,544

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Canada

In 2006, upstream capital spending in Canada amounted to $2,530 million, down from $2,652 million in 2005. Capital spending in 2006 comprised $1,443 million on Western Canada conventional areas, $453 million in the Lloydminster heavy oil region, $276 million in the Alberta oil sands regions, $313 million for East Coast development and $45 million for East Coast and Northwest Territories exploration.

In 2006, spending on exploration activities comprised $236 million in the foothills and deep basin regions, $81 million in the Lloydminster heavy oil region, $98 million in the Alberta oil sands regions and $82 million in the remainder of the conventional Western Canada Sedimentary Basin.

In the Lloydminster heavy oil production region, capital spending amounted to $453 million in 2006, $81 million of which was classified as exploration. Spending in this area is focused mainly on SAGD, cyclic steam and cold production techniques that are utilized to produce the 10 to 14 degree API heavy crude oil. Production of heavy crude oil is more capital intensive due to the extensive infrastructure and also for facilities required for thermal recovery techniques.

Exploration spending in the foothills and deep portion of the greater Western Canada Sedimentary Basin amounted to $236 million in 2006, up from $213 million in 2005. Exploration in this region, which extends along the eastern slopes of the Rocky Mountains in Alberta and into northeastern British Columbia, involves drilling deep wells into high pressure natural gas formations.

Spending on oil sands projects amounted to $276 million in 2006, down from $366 million in 2005. Our Tucker SAGD oil sands project was commissioned during October 2006 and operations for the remainder of the year were largely concentrated on steaming the formation. We spent $178 million on the Tucker project in 2006. At the Sunrise Oil Sands project, the front-end engineering design commenced. During 2006, we spent $43 million on Sunrise and $55 million on other oil sands prospects.

At White Rose, production continued to ramp up through 2006 with the drilling of two additional production wells in the year.

During 2006, exploration activities offshore the East Coast involved three delineation wells, one on Significant Discovery Licence 1024 to the north west of White Rose, one at West Bonne Bay on Significant Discovery Licence 1040 and one at North Amethyst on Significant Discovery Licence 1044 to the south west of White Rose. In 2006, capital spending for exploration and development activities in this region amounted to $358 million, down from $645 million in 2005.

International

Exploration spending in China involved the drilling of an exploration well and a side track well at Liwan in the South China Sea. The well encountered a large natural gas reservoir and the results are being evaluated. Approximately 400 square kilometres of 3-D seismic was shot during 2006 on the Liwan discovery area.

In Indonesia, front-end engineering design for the Madura Strait natural gas and NGL project is underway. However, field development is contingent on the negotiation of a natural gas sales contract, which is ongoing.

Total capital spending on international activities amounted to $97 million.

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4.2  MIDSTREAM

2006 EARNINGS $482 MILLION, DOWN $13 MILLION FROM 2005

The midstream business is dominated by upgrading operations, which is a margin business that adds value to heavy crude oil through its conversion to synthetic light crude oil.

Upgrader

Upgrading earnings in 2006 were $28 million less than 2005 due to narrower differentials and increased electrical energy costs offset by higher sales volume of synthetic crude, lower costs for natural gas and thermal energy and lower income taxes.

Upgrading Earnings Summary and 2006 Variance Analysis

Upgrading Earnings Summary	2006			2005			2004
	($ millions, except
	where indicated)
Gross margin	$	624		$	692		$	383
Operating costs		224			228			214
Other recoveries		(6	)		(6	)		(5	)
Depreciation and amortization		24			21			19
Income taxes		97			136			43
Earnings	$	285		$	313		$	112
Upgrader throughput(1)  (mbbls/day)		71.0			66.6			64.6
Synthetic crude oil sales  (mbbls/day)		62.5			57.5			53.7
Upgrading differential  ($/bbl)	$	26.16		$	30.70		$	17.79
Unit margin  ($/bbl)	$	27.35		$	33.01		$	19.48
Unit operating cost(2)  ($/bbl)	$	8.65		$	9.38		$	9.07

(1)	Throughput includes diluent returned to the field.
(2)	Based on throughput.

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Upgrading Earnings Variance Analysis

($ millions)

Upgrading Differential

The profitability of Husky’s heavy oil upgrading operations is dependent upon the amount by which revenues from the synthetic crude oil produced exceed the costs of the heavy oil feedstock plus the related upgrading costs. An increase in the price of blended heavy crude oil feedstock that is not accompanied by an equivalent increase in the sales price of synthetic crude oil would reduce the profitability of our upgrading operations. We have significant crude oil production volumes that trade at a discount to light crude oil, and any negative effect of a narrower differential on upgrading operations, caused by higher heavy crude pricing, would be more than offset by a positive effect on revenues in the upstream segment from heavy oil production.

Infrastructure and Marketing Earnings Summary and 2006 Variance Analysis

Infrastructure and marketing earnings in 2006 increased by $15 million compared with 2005 due to higher crude oil pipeline margins, higher natural gas marketing earnings, higher cogeneration earnings and lower income taxes, partially offset by lower earnings from blended heavy crude oil marketing.

Infrastructure and Marketing Earnings Summary	2006		2005		2004
	($ millions, except
	where indicated)
Gross margin
Pipeline	$	104	$	92	$	84
Other infrastructure and marketing		208		217		136
		312		309		220
Other expenses		11		10		8
Depreciation and amortization		24		21		21
Income taxes		80		96		63
Earnings	$	197	$	182	$	128
Aggregate pipeline throughput  (mbbls/day)		475		474		492

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Midstream Capital Expenditures

Midstream capital expenditures of $252 million in 2006 were largely for upgrader expansion front-end engineering design, debottlenecking and reliability projects and pipeline upgrades and expansion compared with $157 million in 2005.

4.3  REFINED PRODUCTS

2006 EARNINGS $106 MILLION, UP $24 MILLION FROM 2005

The refined products business includes the light oil product marketing business that distributes motor fuel and other consumer products through retail and wholesale outlets and the asphalt products marketing business that distributes asphalt related construction products to industrial customers. The light oil products business relies primarily on acquiring refined product from other refiners either directly or through custom processing agreements and from our own regional refinery located at Prince George, British Columbia. Our supply of asphalt product comes from our asphalt plant in Lloydminster, Alberta. Both are margin businesses.

Light Oil Product Marketing Asphalt Products       

Refined Products earnings in 2006 increased by $24 million compared with 2005 due to:

•  higher margins for gasoline and distillates;

•  higher ancillary income;

•  higher sales volume of asphalt products;

•  lower administrative costs; and

•  lower income taxes.

Partially offset by:

•  higher depreciation; and

•  lower sales volume of gasoline and distillates.

25

Earnings Summary and Variance Analysis

Refined Products Earnings Summary	2006		2005		2004
	($ millions, except
	where indicated)
Gross margin
Fuel sales	$	138	$	126	$	93
Ancillary sales		36		34		30
Asphalt sales		94		91		51
		268		251		174
Operating and other expenses		74		75		71
Depreciation and amortization		48		47		38
Income taxes		40		47		24
Earnings	$	106	$	82	$	41
Number of fuel outlets		505		515		531
Refined products sales volume
Light oil products  (million litres/day)		8.7		8.9		8.4
Light oil products per outlet  (thousand litres/day)		12.9		12.7		11.7
Asphalt products  (mbbls/day)		23.4		22.5		22.8
Refinery throughput Prince George refinery  (mbbls/day)		9.0		9.7		9.8
Lloydminster refinery  (mbbls/day)		27.1		25.5		25.3
Ethanol production  (thousand litres/day)		59.7		25.6		26.0

Refined Products Margins

The margins realized by Husky for refined products are affected by crude oil price fluctuations, which in turn increase or decrease the cost of refinery feedstock and the cost of refined product purchased from third-party refiners. Our ability to maintain refined product margins in an environment of higher feedstock costs is contingent on whether the market will permit us to pass on higher costs to our customers.

Refined Products Capital Expenditures

Refined Products capital expenditures in 2006 of $285 million were primarily for marketing outlet construction and upgrades, the Prince George refinery upgrade and construction of the Lloydminster and Minnedosa ethanol plants compared with $191 million in 2005.

Integration

Husky’s production of light, medium and heavy crude oil and natural gas and the efficient operation of our upgrader, refineries and other infrastructure provide opportunities to take advantage of any fluctuation in commodity prices while assisting in managing commodity price volatility. Although we are predominantly an oil and gas producer, the nature of our integrated operations is such that the upstream business segment’s output provides input to the midstream and refined products segments.

4.4  CORPORATE

2006 EXPENSE $157 MILLION, UP $59 MILLION FROM 2005

Corporate expense increased by $59 million in 2006 compared with 2005 largely due to:

•  lower capitalized interest consistent with the commissioning of major projects;

•  2005 expenses offset by proceeds of a one-time litigation settlement, similar proceeds absent in 2006; and

•  increased administration expenses consistent with higher staff levels.

Partially offset by:

•  lower intersegment profit eliminations;

•  lower stock-based compensation; and

•  lower debt costs.

26

Corporate Earnings Summary	2006			2005			2004
	($ millions) income
	(expense)
Intersegment eliminations — net	$	20		$	(50	)	$	(14	)
Administration expenses		(35	)		(19	)		(27	)
Stock-based compensation		(138	)		(171	)		(67	)
Accretion		(3	)		(2	)		(2	)
Other — net		(23	)		49			(8	)
Depreciation and amortization		(27	)		(23	)		(24	)
Interest on debt		(125	)		(146	)		(135	)
Interest capitalized		33			114			75
Foreign exchange		24			31			120
Income taxes		117			119			94
Earnings (loss)	$	(157	)	$	(98	)	$	12

Foreign Exchange Summary	2006					2005					2004
	($ millions)
(Gain) loss on translation of U.S. dollar denominated long-term debt Realized			$	(42	)			$	(13	)			$	(10	)
Unrealized				35					(38	)				(140	)
				(7	)				(51	)				(150	)
Cross currency swaps
Realized				47					—					—
Unrealized				(43	)				14					27
				4					14					27
Other (gains) losses				(21	)				6					3
			$	(24	)			$	(31	)			$	(120	)
U.S./Canadian dollar exchange rates:
At beginning of year		U.S.	$	0.858			U.S.	$	0.831			U.S.	$	0.774
At end of year		U.S.	$	0.858			U.S.	$	0.858			U.S.	$	0.831

Foreign Exchange Risk

Our results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will effectively decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will effectively increase the revenues received from the sale of oil and gas commodities.

In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky’s U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2006, 81% or $1.3 billion of our long-term debt was denominated in U.S. dollars. The Cdn/U.S. exchange rate at the end of 2006 was $1.1653. The percentage of our long-term debt exposed to the Cdn/U.S. exchange rate decreases to 55% when cross currency swaps are included. Refer to Section 6.6, “Financial Risk and Risk Management.”

Corporate Capital Expenditures

Corporate capital expenditures of $37 million in 2006 were mostly for computer hardware, software, office furniture and equipment and compared with $21 million in 2005.

Consolidated Income Taxes

Consolidated income taxes decreased in 2006 to $780 million from $809 million in 2005 largely as a result of Federal, Alberta and Saskatchewan statutory tax rate reductions enacted in 2006.

27

In 2006, a recovery of future taxes resulted from recording non-recurring tax benefits of $328 million that arose due to changes in the tax rates for the governments of Canada ($198 million), Alberta ($90 million) and Saskatchewan ($40 million).

In 2006, current income taxes totalled $678 million and comprised $632 million of Canadian income tax, $64 million in respect of the Wenchang oil field operation and a net capital tax recovery of $18 million.

The following table shows the effect of non-recurring tax benefits for the periods noted:

	2006		2005		2004
	($ millions)
Income taxes before tax amendments	$	1,108	$	813	$	439
Canadian federal and provincial tax amendments		328		4		40
Income taxes as reported	$	780	$	809	$	399

Husky’s Canadian Tax Pools	2006		2005		2004
	($ millions)
Canadian exploration expense	$	117	$	78	$	—
Canadian development expense		2,136		2,033		1,616
Canadian oil and gas property expense		666		721		557
Foreign exploration and development expense		252		240		212
Undepreciated capital costs		4,644		4,249		3,269
Other		21		27		22
	$	7,836	$	7,348	$	5,676

4.5  2005 COMPARED WITH 2004

The following is an abbreviated analysis of the major variance in our 2005 results of operations compared with 2004.

Net earnings in 2005 were $2,003 million compared with $1,006 million in 2004. The increase of $997 million was attributable to the following:

Upstream — increase of $811 million

•  higher crude oil and natural gas prices; and

•  absence of commodity price hedging loss in 2005.

Partially offset by:

•  lower sales volume of crude oil and natural gas;

•  higher operating costs and DD&A;

•  higher royalties; and

•  higher income taxes.

Midstream — increase of $255 million

•  wider upgrading differential;

•  higher sales volume of synthetic crude oil;

•  higher income from oil and gas commodity marketing;

•  higher heavy crude oil tariffs;

•  higher Lloyd blend marketing margins;

•  higher crude oil and NGL trading; and

•  higher cogeneration income.

28

Partially offset by:

•  lower heavy crude oil pipeline throughput;

•  higher energy and non-energy related unit operating costs; and

•  higher income taxes.

Refined Products — increase of $41 million

•  higher marketing margins and sales volume for gasoline and distillates;

•  higher marketing margins of asphalt products; and

•  higher restaurant and convenience store income.

Partially offset by:

•  slightly lower sales volume of asphalt products;

•  higher depreciation and amortization; and

•  higher income taxes.

Corporate — expense increased by $110 million

•  higher intersegment profit eliminated;

•  higher stock-based compensation;

•  higher interest costs;

•  lower foreign exchange gains on translation of U.S. dollar denominated debt; and

•  provision for retrospective insurance premiums in respect of past claims on a mutual insurance consortium.

Partially offset by:

•  proceeds from a litigation settlement; and

•  higher capitalized interest resulting from a higher capital base for the White Rose and Tucker projects.

5.  2007 OUTLOOK

5.1  GENERAL ECONOMY

The expectations for the global economy in 2007 are for slightly slower growth. Crude oil price forecasters have decreased their predictions as actual current crude oil prices have fallen. History has taught us that crude oil prices are and will likely remain volatile.

5.2  2007 CAPITAL PROGRAM

Husky plans to invest capital in the following segments in 2007:

	2007 Estimate(1)
	($ millions)
Upstream
Western Canada — oil and gas	$	1,840
— oil sands		330
East Coast Canada		290
International		160
		2,620
Midstream		380
Refined Products		140
Corporate		40
	$	3,180

(1)  Excludes capitalized administrative costs and capitalized interest.

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5.3  UPSTREAM

Production Outlook	2007		2006 Actual
Light crude oil & NGL  (mbbls/day)		128 - 135		111
Medium crude oil  (mbbls/day)		28 - 30		29
Heavy crude oil & bitumen  (mbbls/day)		122 - 130		108
Total crude oil & NGL  (mbbls/day)		278 - 295		248
Natural gas  (mmcf/day)		670 - 690		672
Barrels of oil equivalent (6:1)  (mboe/day)		390 - 410		360

Western Canada Conventional

Although the ability to easily identify and produce conventional reserves is diminished for the Western Canada Sedimentary Basin, the basin still contains a vast quantity of undiscovered reserves. These are smaller accumulations dispersed throughout the undisturbed plains and accumulations in the deep basin and overthrust belt along the eastern slopes of the Rocky Mountains that are challenging to access. Exploitation of these areas will require careful attention to a number of variables including new geological tools, emerging enhanced recovery techniques and optimization of economics through maximal utilization of existing infrastructure. We will continue to exploit these conventional reserves and, at the same time, explore for and develop the large and prolific basins off the East Coast of Canada, in the offshore basins of China and Indonesia and the oil sands regions of Alberta. In addition, we will augment our natural gas production with unconventional production such as coalbed methane and tight reservoirs. We expect our conventional oil equivalent production, including primary heavy crude production, from the Western Canada Sedimentary Basin to account for approximately 64% of our production in 2007, down from 72% in 2006.

We expect to replace a large portion of our conventional production in Western Canada from development of our current oil sands projects, further exploitation in the Jeanne d’Arc basin off the East Coast of Canada and from further exploitation of Wenchang in China and development of the Madura natural gas field in Indonesia.

Capital expenditures for development and exploration on our conventional Western Canada properties are expected to account for approximately 64% of the total $2.6 billion in upstream capital expenditures in 2007, down from 70% in 2006. In 2007, capital expenditures will increase for heavy oil development, particularly for our projects utilizing thermal recovery techniques and for oil sands development.

Oil Sands

Our current schedule for oil sands development is:

•  complete a downstream solution that addresses infrastructure, upgrading and refining;

•  ramp up production at Tucker to an average of 12 to 18 mbbls/day of bitumen during 2007;

•  complete Sunrise front-end engineering design and sanction by the fourth quarter of 2007;

•  commence preliminary design and evaluation of a small project in the Caribou Lake oil sands area; and

•  commence submission of a pilot project to test various recovery techniques over the next few years in the Saleski oil sands area.

We view the full scale commercial development of Caribou Lake to be a medium-term project and Sunrise and Saleski to be long-term projects.

Canada — East Coast and Northwest Territories

On the East Coast, we will continue with the development and delineation of the White Rose field, including evaluating the economics and technical feasibility of natural gas developments off the East Coast, including the natural gas resources in the northern section of the White Rose field. In addition, we will continue to identify and evaluate new prospects off the East Coast with an emphasis on the Jeanne d’Arc Basin.

Effective January 15, 2007 we had acquired 100% working interest in an Exploration Licence totalling 61,375 acres and 50% working interest in two Exploration Licences totalling 127,457 acres.

In 2007 in the Northwest Territories, we will proceed with delineation and evaluation of the Summit Creek B-44 discovery that confirmed several productive intervals within a 180-metre zone. We and our partners hold over one million acres covering the central extent of this play.

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China and Indonesia

In China, we will continue to pursue offshore prospects and the development of the Liwan natural gas discovery.

In Indonesia, we have been involved in protracted negotiations to establish a natural gas sales contract and an extension to the production sharing agreement and we expect to conclude these arrangements in 2007. We estimate that development construction will take approximately three years following project sanction. In addition, we will commence an exploration program on the East Bawean II block acquired in 2006.

5.4  MIDSTREAM

In 2007, we will maintain and optimize infrastructure to capitalize on increasing activity in the bitumen corridor, which extends from Lloydminster north to Fort McMurray, Alberta. We will also pursue expansion of ancillary businesses including transportation, storage, cogeneration and upgrading. We will complete the second phase of the pipeline expansion between Lloydminster and Hardisty, Alberta by September 2007. We expect to complete the front-end engineering design for an expansion of the Lloydminster Heavy Oil Upgrader to a capacity of 150 mbbls/day by the end of 2007 followed by project sanction subject to satisfactory economics.

5.5  REFINED PRODUCTS

In 2007, we plan to complete the construction of the second ethanol plant at Minnedosa, Manitoba, by the third quarter and be fully operational in the fourth quarter of 2007. In addition, we will continue to improve technology, appearance and product offerings at our marketing outlets and continue to optimize the number and location of our retail facilities.

6.  LIQUIDITY AND CAPITAL RESOURCES

6.1  SUMMARY OF CASH FLOW

	2006			2005			2004
	($ millions, except
	where indicated)
Cash flow — operating activities	$	5,009		$	3,650		$	2,304
— financing activities	$	(1,626	)	$	(668	)	$	193
— investing activities	$	(3,109	)	$	(2,814	)	$	(2,497	)
Debt to capital employed (percent)		14.3			20.1			25.8
Corporate reinvestment ratio (percent)(1)		70			80			110

(1)  Reinvestment ratio is based on net capital expenditures including corporate acquisitions.

Cash Flow from Operating Activities

In 2006, cash generated by operating activities was $5,009 million, an increase of $1,359 million from the $3,650 million recorded in 2005. The higher cash from operating activities in 2006 was primarily due to higher earnings, partially offset by increased non-cash working capital associated with operating activities.

Cash Flow from (used for) Financing Activities

In 2006, cash used in financing activities amounted to $1,626 million. The cash used was composed of the repayment of long-term debt of $1,493 million and a $47 million settlement of a cross currency swap, dividends of $636 million, other costs of $1 million and a change of $678 million in non-cash working capital. Cash provided by financing activities in 2006 comprised $1,226 million issuance of long-term debt and $3 million of proceeds from the exercise of stock options. Debt issuances and repayments include multiple drawings and repayments under revolving debt facilities.

Husky’s long-term debt balances were also reduced by $7 million during 2006, which mainly resulted from the narrowing of the exchange rate between Canadian and U.S. currencies.

Cash Flow used for Investing Activities

Cash used in investing activities amounted to $3,109 million in 2006, an increase of $295 million from the $2,814 million in 2005. Cash invested in 2006 was composed of capital expenditures of $3,171 million, partially offset by $34 million of proceeds from asset sales. Change in non-cash working capital and other adjustments amounted to $28 million used in investing activities.

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6.2  WORKING CAPITAL COMPONENTS

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2006, our working capital deficiency was $495 million compared with $1.0 billion at December 31, 2005. It is not unusual for Husky to have working capital deficits at the end of a reporting period. These working capital deficits are mainly due to the large capital component in accounts payable, which is related largely to exploration and development expenditures. This is typical in the oil and gas industry, which is capital intensive. Settlement of these current liabilities is funded by cash provided by operating activities, and to the extent necessary, by bank borrowings.

	2006			2005			Change
	($ millions)
Current assets
Cash and cash equivalents	$	442		$	168		$	274		Excess cash generated by White Rose
Accounts receivable		1,284			856			428		Repaid securitization program; higher crude oil prices
Inventories		428			471			(43	)	Lower crude oil feedstock volumes in 2006
Prepaid expenses		25			40			(15	)	Primarily Tucker construction advance in 2005
		2,179			1,535			644
Current liabilities
Accounts payable		1,268			1,213			(55	)	Increased White Rose activity; refined product purchases in 2006
Accrued interest payable		27			41			14		Lower long-term debt due to repayments
Income taxes payable		615			164			(451	)	2006 White Rose earnings; 2005 deferred earnings
Other accrued liabilities		664			892			228		Special dividend in 2005; higher stock-based compensation liability in 2006
Long-term debt due within one year		100			274			174		Repayment of 7.125% notes and 8.45% bonds
		2,674			2,584			(90	)
Working capital	$	(495	)	$	(1,049	)	$	554

Sources and Uses of Cash

Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and developed reserves, to acquire strategic oil and gas assets, repay maturing debt and pay dividends. Husky’s upstream capital programs are funded principally by cash provided from operating activities. During times of low oil and gas prices part of a capital program can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining our production, it may be necessary to utilize alternative sources of capital to continue our strategic investment plan during periods of low commodity prices. As a result, we frequently evaluate our options with respect to sources of long and short-term capital resources. In addition, we frequently evaluate hedging a portion of our production to protect cash flow in the event of commodity price declines.

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Sources and Uses of Cash (continued)

The following illustrates our sources and uses of cash during the years ended December 31, 2006, 2005 and 2004:

Sources and Uses of Cash	2006			2005			2004
	($ millions)
Cash sourced
Cash flow from operations(1)	$	4,501		$	3,785		$	2,197
Debt issue		1,226			3,235			2,200
Asset sales		34			74			36
Proceeds from exercise of stock options		3			6			18
Proceeds from monetization of financial instruments		—			39			8
		5,764			7,139			4,459
Cash used
Capital expenditures		3,171			3,068			2,349
Corporate acquisitions		—			—			102
Debt repayment		1,493			3,502			1,941
Special dividend on common shares		—			424			229
Ordinary dividends on common shares		636			276			195
Settlement of asset retirement obligations		36			41			40
Settlement of cross currency swap		47			—			—
Other		13			32			24
		5,396			7,343			4,880
Net cash (deficiency)		368			(204	)		(421	)
Increase (decrease) in non-cash working capital		(94	)		372			421
Increase in cash and cash equivalents		274			168			—
Cash and cash equivalents — beginning of year		168			—			—
Cash and cash equivalents — end of year	$	442		$	168		$	—

(1)  Cash flow from operations represents net earnings plus items not affecting cash, which include accretion, depletion, depreciation and amortization, future income taxes and foreign exchange.

	December 31, 2006
	Outstanding				Available
Capital Structure	(U.S. $)		(Cdn $)		(Cdn $)
	($ millions)
Short-term bank debt	$	—	$	—	$	201
Long-term bank debt Syndicated credit facility		—		—		1,020
Bilateral credit facility		—		—		150
Medium-term notes		—		300
Capital securities		225		262
U.S. public notes		900		1,049
Total short-term and long-term debt	$	1,125	$	1,611	$	1,371
Common shares and retained earnings			$	9,620

As at December 31, 2006, our outstanding long-term debt totalled $1.6 billion, including amounts due within one year, compared with $1.9 billion at December 31, 2005.

On February 1, 2006, we redeemed our 8.45% senior secured bonds amounting to U.S. $85 million.

At December 31, 2006, we had no drawings under our $1.0 billion revolving syndicated credit facility. Interest rates under this facility vary and are based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected and credit ratings assigned by certain rating agencies to our senior unsecured debt. The syndicated credit facility requires Husky to maintain a debt to cash flow ratio of less than 3.5 times and a consolidated tangible net worth, as of December 31, 2006, of at least $5.1 billion.

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Sources and Uses of Cash (continued)

At December 31, 2006, we had no drawings under our $150 million bilateral credit facilities. The terms of these facilities are substantially the same as the syndicated credit facility.

At December 31, 2006, we used $19 million in support of letters of credit under our $220 million in short-term borrowing facilities. The interest rates applicable to these facilities vary and are based on Bankers’ Acceptance, U.S. LIBOR or prime rates. In addition, we had used $80 million under our dedicated letter of credit facilities.

Husky has an agreement to sell up to $350 million of net trade receivables on a revolving basis. The agreement calls for purchase discounts, based on Canadian commercial paper rates, plus a program fee to be paid on an ongoing basis. As at December 31, 2006, there were no sales of accounts receivable under this agreement. The arrangement matures on January 31, 2009.

Based on our 2007 commodity price forecast, we believe that our non-cancellable contractual obligations and other commercial commitments and our 2007 capital program will be funded by cash flow from operating activities and, to the extent required, by available credit facilities. In the event of significantly lower cash flow, we would be able to defer certain of our projected capital expenditures without penalty.

We declared dividends of $1.50 per share totalling $636 million in 2006. The Board of Directors of Husky has established a dividend policy that pays quarterly dividends of $0.50 ($2.00 annually) per common share. The declaration of dividends will be at the discretion of the Board of Directors, which will consider earnings, capital requirements, our financial condition and other relevant factors.

Cash and cash equivalents at December 31, 2006 totalled $442 million compared with $168 million at the beginning of the year.

Credit Ratings

Husky’s senior debt and capital securities have been rated investment grade by several rating agencies. These ratings are disclosed and explained in detail in our Annual Information Form.

6.3  CASH REQUIREMENTS

Contractual Obligations and Other Commercial Commitments

In the normal course of business, Husky is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.

Contractual Obligations
Payments due by period	Total		2007		2008-2009		2010-2011		Thereafter
	($ millions)
Long-term debt and interest	$	2,296	$	209	$	638	$	136	$	1,313
Operating leases		1,133		93		494		450		96
Firm transportation agreements		626		169		202		108		147
Unconditional purchase obligations(1)		4,201		2,144		1,908		136		13
Lease rentals and exploration work agreements		640		148		147		178		167
Engineering and construction commitments		140		140		—		—		—
	$	9,036	$	2,903	$	3,389	$	1,008	$	1,736

(1)  Includes purchase of refined petroleum products, processing services, distribution services, insurance premiums and natural gas purchases. Approximately 72% of the total unconditional purchase obligations are in respect of processing and refined product purchase contracts.

     Estimated Obligations Not Included in the Table

•	Asset retirement obligations (“ARO”)
	Husky currently includes such obligations in the amortizing base of its oil and gas properties. Effective January 1, 2004, with the adoption of the Canadian Institute of Chartered Accountants (“CICA”) section 3110, “Asset Retirement Obligations,” Husky records a separate liability for the fair value of its ARO. See Note 12 to the Consolidated Financial Statements.

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•

Employee future benefits

Husky has a defined contribution pension plan and a post-retirement health and dental care plan for its employees. In addition, Husky has a defined benefit pension plan for approximately 180 active employees and 480 retirees and beneficiaries. In 1991, admittance to the defined benefit pension plan ended after the majority of members transferred to the newly created defined contribution pension plan. See Note 16 to the Consolidated Financial Statements.

     Other Obligations

Husky is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing and financial impact of these events or rulings prevents any meaningful measurement, which is necessary to assess impact on future liquidity. Such obligations include environmental contingencies, contingent consideration and potential settlements resulting from litigation.

6.4  OFF-BALANCE SHEET ARRANGEMENTS

We do not utilize off-balance sheet arrangements with unconsolidated entities to enhance perceived liquidity.

Accounts Receivable Securitization Program

In the ordinary course of business, we engage in the securitization of accounts receivable. The securitization program permits the sale of a maximum of $350 million of accounts receivable on a revolving basis. At December 31, 2006, there were no accounts receivable sold under the program. The securitization agreement terminates on January 31, 2009. The accounts receivable are sold to an unrelated third party and in accordance with the agreement we must provide a loss reserve to replace defaulted receivables.

The securitization program provides us with cost-effective short-term funding for general corporate use. We account for these securitizations as asset sales. In the event the program is terminated, our liquidity would not be substantially reduced.

Standby Letters of Credit

In addition, from time to time, we issue letters of credit in connection with transactions in which the counterparty requires such security.

Derivative Instruments

We utilize derivative financial instruments in order to manage unacceptable risk. The derivative financial instruments currently outstanding are listed and discussed in Section 6.6, “Financial Risk and Risk Management.”

6.5  TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS

Husky, in the ordinary course of business, was party to a lease agreement with Western Canadian Place Ltd. The terms of the lease provided for the lease of office space at Western Canadian Place, management services and operating costs at commercial rates. Effective July 13, 2004, Western Canadian Place Ltd. sold Western Canadian Place to an unrelated party. Western Canadian Place Ltd. is indirectly controlled by Husky’s principal shareholders. Prior to the sale, we paid approximately $10 million for office space in Western Canadian Place during 2004.

We did not have any customers that constituted more than 10% of total sales and operating revenues during 2006.

6.6  FINANCIAL RISK AND RISK MANAGEMENT

Husky is exposed to market risks related to the volatility of commodity prices, foreign exchange rates and interest rates. Refer to Section 2.5 under “The Business Environment in 2006.” From time to time, we use derivative instruments to manage our exposure to these risks.

Commodity Price Risk Management

Husky uses derivative commodity instruments from time to time to manage exposure to price volatility on a portion of our oil and gas production and firm commitments for the purchase or sale of crude oil and natural gas and purchases of electricity.

     Power Consumption

During 2006, we received payments totalling $6 million on our power consumption hedges.

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Foreign Currency Risk Management

At December 31, 2006, Husky had the following cross currency debt swaps in place:

•  U.S. $150 million at 6.25% swapped at $1.41 to $212 million at 7.41% until June 15, 2012.

•  U.S. $75 million at 6.25% swapped at $1.19 to $90 million at 5.65% until June 15, 2012.

•  U.S. $50 million at 6.25% swapped at $1.17 to $59 million at 5.67% until June 15, 2012.

•  U.S. $75 million at 6.25% swapped at $1.17 to $88 million at 5.61% until June 15, 2012.

At December 31, 2006 the cost of a U.S. dollar in Canadian currency was $1.1653.

In 2006, the cross currency swaps resulted in an offset to foreign exchange gains on translation of U.S. dollar denominated debt amounting to $4 million.

In addition, we entered into U.S. dollar forward contracts, which resulted in realized gains totalling approximately $1 million in 2006. In 2004, Husky unwound its long-dated forwards resulting in a gain of $8 million, which was recognized into income during 2005 on the dates the underlying hedged transactions took place.

Interest Rate Risk Management

In 2006, interest rate risk management activities resulted in a decrease to interest expense of $1 million.

The cross currency swaps resulted in an addition to interest expense of $10 million in 2006.

We have interest rate swaps on $200 million of long-term debt, effective February 8, 2002, whereby 6.95% was swapped for Certificate of Deposit Offered Rate + 175 basis points until July 14, 2009. During 2006, these swaps resulted in an offset to interest expense amounting to $2 million.

The amortization of previous interest rate swap terminations resulted in an additional $9 million offset to interest expense in 2006.

6.7  OUTSTANDING SHARE DATA

Authorized:

•  unlimited number of common shares

•  unlimited number of preferred shares

Issued and outstanding: February 16, 2007

•	common shares	424,289,808
•	preferred shares	none
•	stock options	5,605,630
•	stock options exercisable	2,243,766

At February 16, 2007, 18,200,181 common shares were reserved for issuance under the stock option plan. Options awarded under the stock option plan have a maximum term of five years and vest evenly over the first three years.

7.  APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Husky’s Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The significant accounting policies we use are disclosed in Note 3 to the Consolidated Financial Statements. Certain accounting policies require that we make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following discusses such accounting policies and is included in this Management’s Discussion and Analysis (“MD&A”) to aid you in assessing the critical accounting policies and practices of Husky and the likelihood of materially different results being reported. We review our estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies is not meant to be exhaustive. Husky might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

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7.1  FULL COST ACCOUNTING FOR OIL AND GAS ACTIVITIES

The indicated change in the following estimates will result in a corresponding increase in the amount of DD&A expense charged to income in a given period:

An increase in:

•  estimated costs to develop the proved undeveloped reserves;

•  estimated fair value of the ARO related to the oil and gas properties; and

•  estimated impairment of costs excluded from the DD&A calculation.

A decrease in:

•  previously estimated proved oil and gas reserves; and

•  estimated proved reserves added compared to capital invested.

Depletion Expense

In accordance with the full cost method of accounting, all costs associated with exploration and development are capitalized on a country-by-country basis. The aggregate of capitalized costs, net of accumulated DD&A, plus the estimated future costs required to develop the proved undeveloped oil and gas reserves, less estimated equipment salvage values, is charged to income as the reserves are produced over time using the unit of production method based on proved oil and gas reserves.

Withheld Costs

Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.

Ceiling Test

The ceiling test requires each cost centre’s capitalized costs be tested for recoverability. The test uses the estimated undiscounted future net cash flows from proved oil and gas reserves based on forecast prices and costs. When the carrying amount of a cost centre is not recoverable, the cost centre is written down to its fair value. Fair value is estimated using present value techniques which incorporate risks and other uncertainties as well as the future value of reserves when determining estimated cash flows.

7.2  IMPAIRMENT OF LONG-LIVED ASSETS

We are required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived asset or oil and gas cost centre is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings.

7.3  FAIR VALUE OF DERIVATIVE INSTRUMENTS

Periodically, we utilize financial derivatives to manage market risk. The purpose of the derivative is to provide an element of stability to our cash flow in a volatile environment. We disclose the estimated fair value of open hedging contracts as at the end of a reporting period. Effective January 1, 2004 Husky adopted CICA Accounting Guideline 13, “Hedging Relationships” (“AcG-13”). AcG-13 has essentially the same criteria to be satisfied before the application of hedge accounting is permitted as the corresponding requirements of the FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). Refer to the description of FAS 133 in Note 19 to the Consolidated Financial Statements.

The estimation of the fair value of derivatives requires considerable judgment. The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location.

The estimate of fair value for interest rate and foreign currency hedges is determined largely through forward market prices and compared with quotes from financial institutions.

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Accounting rules for transactions involving derivative instruments are complex and subject to a range of interpretation. The FASB has established the Derivative Implementation Group task force, which, on an ongoing basis, considers issues arising from interpretation of these accounting rules. The potential exists that the task force may promulgate interpretations that differ from those of Husky. In this event our policy would be modified.

7.4  ASSET RETIREMENT OBLIGATIONS

We have significant obligations to remove tangible assets and restore land after operations cease and we retire or relinquish the asset. The ARO relates to all of our business operations, however, approximately 90% of the liability relates to the upstream business. The retirement of upstream assets consists primarily of plugging and abandoning wells, removing and disposing of surface and sub-sea equipment and facilities and restoration of land to a state required by regulation or contract. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often require interpretation. Restoration technologies and costs are constantly changing, as are regulatory, political, environmental, safety and stakeholder considerations.

The ARO rules require that an asset retirement obligation associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying cost of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the initial fair value of the ARO is recognized over the useful life of the asset. The initial fair value of the ARO is accreted to its expected settlement date. The accretion amount is expensed as a cost of operating and is added to the ARO liability. The fair value of the ARO is measured using expected future cash outflows discounted at our credit adjusted risk free interest rate.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, future third-party pricing, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the tangible asset balance.

7.5  LEGAL, ENVIRONMENTAL REMEDIATION AND OTHER CONTINGENT MATTERS

We are required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine if the loss can reasonably be estimated. When the loss is determined it is charged to earnings. Husky’s management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.

7.6  INCOME TAX ACCOUNTING

The determination of our income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

7.7  BUSINESS COMBINATIONS

Over recent years, Husky has grown considerably through combining with other businesses. Husky acquired Temple Exploration Inc. in 2004 and Marathon Canada Limited in 2003. These transactions were accounted for using what is now the only accounting method available, the purchase method. Under the purchase method, the acquiring company includes the fair value of the net assets of the acquired entity on its balance sheet. The determination of fair value necessarily involves many assumptions. The valuation of oil and gas properties relies mainly on placing a value on the oil and gas reserves. The valuation of oil and gas reserves entails the process described in Section 4.1, “Upstream” under the caption “Oil and Gas Reserves” but in contrast incorporates the use of economic forecasts that estimate future changes in prices and costs. In addition, this methodology is used to value unproved oil and gas reserves. The valuation of these reserves, by their nature, is less certain than the valuation of proved reserves.

7.8  GOODWILL

The process of accounting for the purchase of a company, described above, results in recognizing the fair value of the acquired company’s net assets on the balance sheet of the acquiring company. Any excess of the purchase price over fair value is recorded as goodwill. Since goodwill results from the culmination of a process that is inherently imprecise, the

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determination of goodwill is also imprecise. In accordance with the issuance of FASB Statement No. 142 and CICA section 3062, “Goodwill and Other Intangible Assets,” goodwill is no longer amortized but assessed annually for impairment. The process of assessing goodwill for impairment necessarily requires Husky to determine the fair value of its assets and liabilities. Such a process involves considerable judgment.

7.9  VARIABLE INTEREST ENTITIES

The principles of consolidation govern which entities and their accounts must be included in our consolidated financial statements. In 2003, the FASB issued additional guidance in respect of those principles in response to perceived abuse of special purpose entities that were designed to hold assets and liabilities and were not included in the consolidated financial statements of the reporting enterprise because they did not hold voting control of the special purpose entity. The CICA followed with similar guidance in 2004. These special purpose entities are now called variable interest entities. A variable interest entity is a legal entity that lacks sufficient controlling equity at risk to enable it to continue to finance its operations and absorb future potential losses without additional subordinated support. Reporting enterprises must now determine if they are the primary beneficiaries of any variable interest entities that they may have a contractual arrangement with. The process is complex and requires management’s judgment to determine if any variable interest entities are required to be consolidated.

We review our contractual arrangements annually to determine if any arrangements constitute a potential financial interest in a variable interest entity.

8.  NEW ACCOUNTING STANDARDS

8.1  CANADIAN ACCOUNTING

Non-monetary Transactions

Effective January 1, 2006, we began to apply the recommendations pursuant to CICA section 3831, “Non-monetary Transactions.” The recommendations of section 3831 require that all non-monetary transactions be measured based on fair value unless the transaction lacks commercial substance or is an exchange of product or property held for sale in the ordinary course of business.

8.2  U.S. ACCOUNTING

Accounting for Defined Benefit Pension Plans and Other Post-retirement Benefit Plans

In September 2006, the FASB issued FAS 158, “Employers Accounting for Defined Benefit Pension Plans and Other Post-retirement Benefit Plans — an Amendment of FASB Statements No. 87, 88, 106 and 132(R).” FAS 158 requires the recognition of the underfunded or overfunded status of each defined benefit pension plan and other post-retirement benefit plan as a liability or asset. Changes in the funded status are recorded through accumulated other comprehensive income as a separate component of shareholders’ equity in the year in which the changes occur. The impact of this standard on our U.S. GAAP financial statements is disclosed in Note 19 to the Consolidated Financial Statements.

Accounting for Purchases and Sales of Inventory with the Same Counterparty

In September 2005, the Emerging Issues Task Force (“EITF”) redeliberated EITF 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. In arrangements whereby one inventory transaction is legally contingent upon the performance of another inventory transaction with the same counterparty, including buy/sell transactions, these transactions are considered a single exchange transaction subject to Accounting Principles Board Opinion No. 29 “Accounting for Non-monetary Transactions”, when the transactions are entered into “in contemplation” of one another. EITF 04-13 clarifies that non-monetary exchanges whereby an entity transfers finished goods inventory in exchange for the receipt of raw materials or work-in-progress inventory within the same line of business is not an exchange transaction to facilitate sales to customers. These non-monetary exchanges are required to be recognized at fair value if reasonably determinable and the transaction has commercial substance. All other non-monetary exchanges of inventory within the same line of business are to be recognized at the carrying amount of the inventory transferred. EITF 04-13 is effective for new arrangements entered into, and modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006. The application of EITF 04-13 did not have a material impact on the financial statements.

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Quantifying Financial Statement Misstatements

In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”. SAB 108 was issued by the SEC because of an apparent diversity in the practice of registrants quantifying misstatements from prior years and assessing the effect on current year financial statements. SAB 108 requires registrants to adjust their financial statements if the misstatement quantified under the new approach, including prior-year effects, results in a material error in the current year. This adjustment is required even if misstatements of prior years are considered immaterial. If registrants followed an acceptable approach to quantifying financial statement misstatements in the past, the SEC will not require these registrants to restate prior years’ historical financial statements. Instead, these registrants will be able to report the cumulative effect of adopting the new approach as an adjustment to the current year’s beginning retained earnings balance. If entities correct prior-year financial statements for immaterial errors, this guidance does not require amendments to previously filed reports. Instead, this correction can be made the next time the entity files the prior year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The application of SAB 108 did not have an impact on the financial statements.

9.  PENDING ACCOUNTING STANDARDS

9.1  CANADIAN ACCOUNTING PRONOUNCEMENTS

Financial instruments

In April 2005, the CICA issued three new Handbook sections that deal with the recognition and measurement of financial instruments:

•  Section 1530, “Comprehensive Income;”

•  Section 3855, “Financial Instruments — Recognition and Measurement;” and

•  Section 3865, “Hedges.”

The new standards are an attempt to harmonize Canadian GAAP with U.S. GAAP. Initial measurement of all financial instruments is to be based on their fair values. The subsequent measurement of the financial instrument will depend on whether it is classified as a loan or receivable; held to maturity investment; available for sale financial asset; held for trading asset or liability; or, other financial liability. Available for sale financial assets and held for trading assets or liabilities are measured at fair value on an ongoing basis. The other financial instruments are recognized at amortized cost using the effective interest method. The gains and losses on available for sale financial assets will be recognized in other comprehensive income and are transferred to net income when the asset is derecognized. The gains and losses on held for trading financial instruments are recognized immediately in net income.

Other comprehensive income is a new equity category where revenues, expenses, gains and losses are temporarily presented outside of net income but included in comprehensive income. Unrealized gains or losses on qualifying hedging instruments and available for sale financial assets are included in other comprehensive income and reclassified to net income when required by GAAP.

Hedge accounting continues to be optional and the new Handbook section provides detailed guidance on the application of hedge accounting and the required disclosures.

These new standards are effective for fiscal years beginning on or after January 1, 2007. The impact of these standards is disclosed in Note 18 to the Consolidated Financial Statements.

Financial Instruments — Disclosures and Presentation

In December 2006, the Canadian Accounting Standards Board (“AcSB”) issued CICA section 3862, “Financial Instruments — Disclosures” and CICA section 3863, “Financial Instruments — Presentation” to replace CICA section 3861, “Financial Instruments — Disclosure and Presentation.” These standards were issued to converge with recently issued International Financial Reporting Standard (“IFRS”) 7. The presentation requirements under section 3863 are unchanged from section 3861. The disclosure requirements under section 3862 have been revised and enhanced. Upon application of section 3862, a reader of our financial statements will be afforded information to evaluate the effect of financial instruments on our financial position and the amount, timing and uncertainty of cash flows associated with financial instruments. Specifically, an increased emphasis has been placed on disclosures regarding the risks associated with recognized and unrecognized financial instruments and how these risks are managed. The disclosures will include both qualitative information about our objectives, policies and processes for risk management and quantitative

40

information that will provide information about the extent to which we are exposed to risk. CICA section 3862 and section 3863 are effective for fiscal years beginning on or after October 1, 2007.

Capital Disclosures

In December 2006, the AcSB issued CICA section 1535, “Capital Disclosures.” This standard was issued to converge with amendments to International Accounting Standard 1. Upon application of these recommendations, readers of financial statements will be provided information pertinent to our objectives, policies and processes for managing capital. We will also disclose quantitative data regarding what we consider capital and whether we are in compliance with all externally imposed capital requirements and the consequences of non-compliance. CICA section 1535 is effective for fiscal years beginning on or after October 1, 2007.

Accounting Changes

In July 2006, the AcSB issued a revised CICA section 1506, “Accounting Changes.” These amendments were made to harmonize section 1506 with current IFRS. The changes covered by this section include changes in accounting policy, changes in accounting estimates and correction of errors. Under CICA section 1506, voluntary changes in accounting policy are only permitted if they result in financial statements that provide more reliable and relevant information. When a change in accounting policy is made, this change is applied retrospectively unless impractical. Changes in accounting estimates are generally applied prospectively and material prior period errors are corrected retrospectively. This section also outlines additional disclosure requirements when accounting changes are applied including justification for voluntary changes, complete description of the policy, primary source of GAAP and detailed effect on financial statement line items. CICA section 1506 is effective for fiscal years beginning on or after January 1, 2007.

Determining the Variability to be Considered in Applying AcG-15

In September 2006, the Canadian Emerging Issues Committee (“EIC”) issued Abstract No. 163, “Determining the Variability to be Considered in Applying AcG-15” (“EIC-163”). This abstract was issued based on the previous issuance by the U.S. FASB of FASB Interpretation Number (“FIN”) 46(R)-6, which was issued to remedy an apparent diversity in applying the requirements of FIN 46(R). EIC-163 provides guidance in the interpretation of variability that should be considered when determining:

•  when an entity is a variable interest entity;

•  which interests are variable interests in the entity; and

•  which party, if any, is the primary beneficiary of the variable interest entity.

The appropriate process results in the determination of whether we are a primary beneficiary and therefore must consolidate a variable interest entity. The provisions of this abstract are applied prospectively. EIC-163 is effective for all new and reconsidered entities we are involved with and all entities previously considered under AcG-15, beginning the first reporting period after January 1, 2007.

9.2  U.S. ACCOUNTING PRONOUNCEMENTS

Fair Value Measurement

In September 2006, the FASB issued FAS 157, “Fair Value Measurements”, which defines fair value, establishes a framework for measuring fair value in U.S. GAAP pronouncements and expands the disclosure requirements for fair value measurements. Prior to FAS 157, various definitions of fair value existed with limited guidance for application of these definitions in U.S. GAAP. Fair value under this standard is focused on a market-based measurement as opposed to an entity-specific measurement. This standard establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from independent sources and the reporting entity’s own assumptions about the market. The provisions of this Statement are applied prospectively with certain exceptions that require retrospective application. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We will consider this fair value measurement framework when applying other U.S. GAAP pronouncements where fair value is a consideration.

Accounting for Uncertainty in Income Taxes

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.” This interpretation clarifies the accounting for the uncertainty in income taxes recognized in accordance with FAS 109. FIN 48 establishes a two-step process for the evaluation of a tax position taken or expected to be

41

taken in a tax return. The first step recognizes whether or not a tax position is sustainable based on a “more-likely-than-not” determination. The second step measures the amount of tax benefit to recognize in the financial statements if the tax position meets the more-likely-than-not threshold. Under FIN 48, the tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently determining the impact of this issue.

Accounting for Planned Major Maintenance Activities

In September 2006, the FASB issued a Staff Position in respect of accounting for major planned maintenance, which will prohibit the cost of major planned maintenance from being accrued as a liability over several reporting periods before the maintenance is performed or over interim reporting periods within the annual period in which the cost is expected to be incurred. This will become effective on January 1, 2007. This FASB Staff Position will not affect our financial statements.

10.  FORWARD-LOOKING STATEMENTS

Certain statements in this MD&A are forward-looking statements or information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The Company is hereby providing cautionary statements identifying important factors that could cause the Company’s actual results to differ materially from those projected in these forward-looking statements. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as: “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “intend,” “plan,” “projection,” “could,” “vision,” “goals,” “objective” and “outlook”) are not historical facts and may be forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, forward-looking statements include: our general strategic plans, our projected production for the Tucker in-situ oil sands project, our Sunrise oil sands project design, our exploration and development plans, including planned exploration and development for Western Canada, on the East coast of Canada, in the offshore basins of China and Indonesia and in the oil sands region of Alberta, the percentage of our expected production attributable to conventional oil equivalent production from the Western Canadian Sedimentary Basin, our plans to replace our conventional production, our planned capital expenditures in 2007 and the type of such expenditure, the rate at which we will ramp up production at Tucker, the timing of our plan to complete Sunrise front-end engineering, our business plans for the Midstream and Refined Products, our production guidance and reserves estimates. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this MD&A. Among the key factors that have a direct bearing on our results of operations are the nature of our involvement in the business of exploration for, and development and production of crude oil and natural gas reserves and the fluctuation of the exchange rates between the Canadian and United States dollar.

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to:

•  adequacy of and fluctuations in oil and natural gas prices;

•  demand for our products and services and the cost of required inputs;

•  our ability to replace our reserves;

•  competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternate sources of energy;

•  the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures, natural disasters and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us and that may or may not be financially recoverable;

•  actions by governmental authorities, including changes in environmental and other regulations that may impose restrictions in areas where we operate; and

•  the accuracy of our oil and gas reserve estimates and estimated production levels as they are affected by our success at exploration and development drilling and related activities and estimated decline rates.

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Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

11.  OIL AND GAS RESERVE REPORTING

DISCLOSURE OF PROVED OIL AND GAS RESERVES AND OTHER OIL AND GAS INFORMATION

Husky’s disclosure of proved oil and gas reserves and other information about its oil and gas activities has been made based on reliance of an exemption granted by Canadian Securities Administrators. The exemption permits Husky to make these disclosures in accordance with requirements in the United States. These requirements and, consequently, the information presented may differ from Canadian requirements under National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). The proved oil and gas reserves disclosed in this MD&A have been evaluated using the United States standards contained in Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934. The probable oil and gas reserves disclosed in this MD&A have been evaluated in accordance with the Canadian Oil and Gas Evaluation Handbook and NI 51-101.

The Company uses the terms barrels of oil equivalent (“boe”) and thousand cubic feet of gas equivalent (“mcfge”), which are calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the terms boe and mcfge may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the well head.

CAUTIONARY NOTE TO U.S. INVESTORS

The United States Securities and Exchange Commission permits U.S. oil and gas companies, in their filings with the SEC, to disclose only proved reserves, that is reserves that 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. We use certain terms in this MD&A, such as ‘‘probable reserves”, that the SEC’s guidelines strictly prohibit in filings with the SEC by U.S. oil and gas companies. U.S. investors should refer to our Annual Report on Form 40-F available from us or the SEC for further reserve disclosure.

12.  NON-GAAP MEASURES

DISCLOSURE OF CASH FLOW FROM OPERATIONS

This MD&A contains the term “cash flow from operations”, which should not be considered an alternative to, or more meaningful than “cash flow — operating activities”, as determined in accordance with GAAP as an indicator of the Company’s financial performance. The Company’s determination of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations equals net earnings plus items not affecting cash which include accretion, depletion, depreciation and amortization, future income taxes, foreign exchange and other non-cash items. The following table shows the reconciliation of cash flow from operations to cash flow — operating activities for the years ended December 31:

	2006			2005			2004
	($ millions)
Non-GAAP
Cash flow from operations	$	4,501		$	3,785		$	2,197
Settlement of asset retirement obligations		(36	)		(41	)		(40	)
Change in non-cash working capital		544			(72	)		169
GAAP
Cash flow — operating activities	$	5,009		$	3,672		$	2,326

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13.  ADDITIONAL READER ADVISORIES

Intention of Management’s Discussion and Analysis

This MD&A is intended to provide an explanation of financial and operational performance compared with prior periods and our prospects and plans. It provides additional information that is not contained in our financial statements.

Review by the Audit Committee

This MD&A was reviewed by the Audit Committee and approved by Husky’s Board of Directors on February 27, 2007. Any events subsequent to that date could conceivably materially alter the veracity and usefulness of the information contained in this document.

Additional Husky Documents Filed with Securities Commissions

This MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes. The readers are also encouraged to refer to Husky’s interim reports filed in 2006, which contain MD&A and Consolidated Financial Statements, and Husky’s Annual Information Form filed separately with Canadian regulatory agencies and Form 40-F filed with the SEC, the U.S. regulatory agency. These documents are available at www.sedar.com, at www.sec.gov and www.huskyenergy.ca.

Use of Pronouns and Other Terms

“We”, “our”, “us”, “Husky” and “the Company” refer to Husky Energy Inc. on a consolidated basis.

Standard Comparisons in this Document

Unless otherwise indicated, comparisons of results are for the years ended December 31, 2006 and 2005 and Husky’s financial position as at December 31, 2006 and at December 31, 2005.

Reclassifications and Materiality for Disclosures

Certain prior year amounts have been reclassified to conform to current year presentation. Materiality for disclosures is determined on the basis of whether the information omitted or misstated would cause a reasonable investor to change their decision to buy, sell or hold the securities of Husky.

Additional Reader Guidance

Unless otherwise indicated:

•  Financial information is presented in accordance with GAAP in Canada. Significant differences between Canadian and United States GAAP are disclosed in Note 19 to the Consolidated Financial Statements.

•  Currency is presented in millions of Canadian dollars.

•  Gross production and reserves are Husky’s working interest prior to deduction of royalty volume.

•  Prices are presented before the effect of hedging.

•  Light crude oil is 30^o API and above.

•  Medium crude oil is 21^o API and above but below 30^o API.

•  Heavy crude oil is above 10^o API but below 21^o API.

•  Bitumen is 10^o API and below.

14.  CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Husky’s management, with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of Husky’s disclosure controls and procedures (as defined in the rules of the SEC and the Canadian Securities Administrators (“CSA”)) as at December 1, 2006, and has concluded that such disclosure controls and procedures are effective.

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Management’s Annual Report on Internal Control Over Financial Reporting

The following report is provided by management in respect of Husky’s internal controls over financial reporting (as defined in the rules of the SEC and the CSA):

(1)	Husky’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Husky. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
(2)	Husky’s management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework to evaluate the effectiveness of Husky’s internal control over financial reporting.
(3)	As at December 31, 2006, management assessed the effectiveness of Husky’s internal control over financial reporting and concluded that such internal control over financial reporting is effective and that no material weaknesses in Husky’s internal control over financial reporting have been identified by management.
(4)	KPMG llp, who has audited the Consolidated Financial Statements of Husky for the year ended December 31, 2006, has also issued a report on Husky’s financial statements and internal controls under Auditing Standard No. 2 of the Public Company Accounting Oversight Board (United States). This report is located with Husky’s Consolidated Financial Statements and Auditors’ Report to Shareholders for the Year Ended December 31, 2006.

Changes in Internal Control over Financial Reporting

There have been no changes in Husky’s internal control over financial reporting during the year ended December 31, 2006, that have materially affected, or are reasonably likely to materially affect its internal control over financial reporting.

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ABBREVIATIONS

bbls	barrels
bps	basis points
mbbls	thousand barrels
mbbls/day	thousand barrels per day
mmbbls	million barrels
mcf	thousand cubic feet
mmcf	million cubic feet
mmcf/day	million cubic feet per day
bcf	billion cubic feet
tcf	trillion cubic feet
boe	barrels of oil equivalent
mboe	thousand barrels of oil equivalent
mboe/day	thousand barrels of oil equivalent per day
mmboe	million barrels of oil equivalent
mcfge	thousand cubic feet of gas equivalent
GJ	gigajoule
mmbtu	million British Thermal Units
mmlt	million long tons
MW	megawatt
MWh	megawatt hour
NGL	natural gas liquids
WTI	West Texas Intermediate
NYMEX	New York Mercantile Exchange
NIT	NOVA Inventory Transfer
LIBOR	London Interbank Offered Rate
CDOR	Certificate of Deposit Offered Rate
SEDAR	System for Electronic Document Analysis and Retrieval
FPSO	Floating production, storage and offloading vessel
FEED	Front-end engineering design
OPEC	Organization of Petroleum Exporting Countries
WCSB	Western Canada Sedimentary Basin
SAGD	Steam-assisted gravity drainage

TERMS

Bitumen	A naturally occurring viscous mixture consisting mainly of pentanes and heavier hydrocarbons. It is more viscous than 10 degrees API
Carbonate	Sedimentary rock primarily composed of calcium carbonate (limestone) or calcium magnesium carbonate (dolomite) which forms many petroleum reservoirs
Capital Employed	Short- and long-term debt and shareholders’ equity
Capital Expenditures	Includes capitalized administrative expenses and capitalized interest but does not include proceeds or other assets
Capital Program	Capital expenditures not including capitalized administrative expenses or capitalized interest
Cash Flow from Operations	Earnings from operations plus non-cash charges before settlement of asset retirement obligations and change in non-cash working capital
Coalbed Methane	Methane (CH4), the principal component of natural gas, is adsorbed in the pores of coal seams
Dated Brent	Prices which are dated less than 15 days prior to loading for delivery
Design Rate Capacity	Maximum continuous rated output of a plant based on its design
Diluent	A light liquid hydrocarbon, usually condensate, added to heavy oil to permit transportation through a pipeline
Equity	Shares and retained earnings
Feedstock	Raw materials which are processed into petroleum products
Front-end Engineering Design	Preliminary engineering and design planning, which among other things, identifies project objectives, scope, alternatives, specifications, risks, costs, schedule and economics
Gross/Net Acres/Wells	Gross refers to the total number of acres/wells in which an interest is owned. Net refers to the sum of the fractional working interests owned by a company
Gross Reserves/Production	A company’s working interest share of reserves/production before deduction of royalties
Hectare	One hectare is equal to 2.47 acres
Near-month Prices	Prices quoted for contracts for settlement during the next month
NOVA Inventory Transfer	Exchange or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline
Polymer	A substance which has a molecular structure built up mainly or entirely of many similar units bonded together
Section	Area that is one square mile or 640 acres
Surfactant	A substance that tends to reduce the surface tension of a liquid in which it is dissolved
Total Debt	Long-term debt including current portion and bank operating loans

Oil and Gas Reserves definitions

Proved reserves have been estimated in accordance with the SEC definition set out in Rule 4-10(a) of Regulation S-X under the Securities Exchange Act of 1934 as follows: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Proved Developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped reserves are those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which a relatively major expenditure is required for recompletion. Inclusion of reserves on undrilled acreage is limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only if it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

Exhibit No.			Description
	23	.1	Consent of KPMG llp, independent accountants.
	23	.2	Consent of McDaniel and Associates Consultants Ltd., independent engineers.
	31	.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.
	31	.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.
	32	.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
	32	.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Husky Energy Inc.

We consent to the incorporation by reference in the Registration Statement (No. 333-137211) on Form F-9 of Husky Energy Inc. and inclusion in this annual report on Form 40-F of:

•  our audit report dated February 5, 2007 on the consolidated balance sheets of Husky Energy Inc. as at December 31, 2006, 2005 and 2004 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 2006,

•  our Comments by Auditors for United States Readers on Canada-United States Reporting Differences, dated February 5, 2007,

•  our Report of Independent Registered Public Accounting Firm dated February 5, 2007 on management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 and the effectiveness of internal control over financial reporting as of December 31, 2006,

each of which is contained in this annual report on Form 40-F of the Company for the fiscal year ended December 31, 2006.

/s/ KPMG llp

KPMG llp

Chartered Accountants

Calgary, Canada

March 13, 2007

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT ENGINEERS

We refer to our report auditing estimates of the natural gas, natural gas liquids and conventional oil reserves attributable to Husky Energy Inc. (the “Company”) as of December 31, 2006 (the “Report”).

We hereby consent to references to our name in the Company’s Annual Report on Form 40-F to be filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, and the Company’s registration statement on Form F-9 (File No. 333-137211). We also confirm that we have read the Company’s Annual Information Form for the year ended December 31, 2006 dated March 13, 2007 and that we have no reason to believe that there are any misrepresentations in the information contained in it that was derived from the Report or that is within our knowledge as a result of the services we performed in connection with such Report.

Sincerely,

McDaniel & Associates Consultants Ltd.

/s/ P.A. Welch

P.A. Welch

President & Managing Director

Calgary, Alberta, Canada

March 13, 2007

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO
RULE 13a-14 OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF 1934,
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John C.S. Lau, certify that:

1.	I have reviewed this annual report on Form 40-F of Husky Energy Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.  The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: March 13, 2007

/s/ John C.S. Lau

John C.S. Lau

President & Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

RULE 13a-14 OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF 1934,

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, L. Geoffrey Barlow, certify that:

1.	I have reviewed this annual report on Form 40-F of Husky Energy Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.  The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: March 13, 2007

/s/ L. Geoffrey Barlow

L. Geoffrey Barlow

Vice President & Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Husky Energy Inc. (the “Company”) on Form 40-F for the fiscal year ending December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John C.S. Lau, President, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 13, 2007

/s/ John C.S. Lau

John C.S. Lau

President & Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Husky Energy Inc. (the “Company”) on Form 40-F for the fiscal year ending December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, L. Geoffrey Barlow, Vice President & Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 13, 2007

/s/ L. Geoffrey Barlow

L. Geoffrey Barlow

Vice President & Chief Financial Officer