Husky Energy 40F 2005 Annual report

2005

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, 2005	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: 424,125,078.

Common Shares were outstanding as of December 31, 2005

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 Form F-9 File No. 333-117972.

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, 2005, 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, 2005 and 2004, 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, 2005, see Document C of this Annual Report on Form 40-F.

Controls and Procedures

A. Disclosure Controls and Procedures

Husky maintains disclosure controls and other procedures and internal control over financial reporting designed to ensure that information required to be disclosed in the reports filed under the Exchange Act, as amended, is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Husky’s principal executive and acting chief financial officer evaluated the effectiveness of Husky’s disclosure controls and procedures as of the end of the period covered by this report and concluded that such disclosure controls and procedures are effective for the purpose for which they were designed as of the end of such period.

It should be noted that while Husky’s principal executive and acting chief financial officer believes that Husky’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, he does not expect that Husky’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

B. Changes in Internal Control over Financial Reporting

During the fiscal year ended December 31, 2005, there were no changes in Husky’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, Husky’s internal control over financial reporting.

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 the 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” in the Registrant’s Annual Information Form for the year ended December 31, 2005, 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 most recently completed 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, 2005, 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, 2005, which is filed as Document C to this Annual Report on Form 40-F.

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, 2005, 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.

iii

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 14th day of March, 2006.


	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

Document A

Form 40-F

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2005

Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2005

March 14, 2006

TABLE OF CONTENTS


			Page

Exchange Rate Information				2
Disclosure Exemption Under National Instrument 51-101				2
Corporate Structure
	Husky Energy Inc.			3
	Intercorporate Relationships			4
General Development of Husky
	Three Year History of Husky			4
	Business Environment Trends			5
Description of Husky’s Business
	General			6
	Social and Environmental Policy			7
	Risk Factors			7
	Upstream Operations — Disclosures for Oil and Gas Activities			9
		Disclosure about Oil and Gas Producing Activities — FAS 69		24
		Independent Engineer’s Audit Opinion		30
		Report on Reserves Data by Qualified Reserves Evaluator		31
		Report of Management and Directors on Reserves Data and Other Information		32
		Description of Major Properties and Facilities		34
	Distribution of Oil and Gas Production			49
	Midstream Operations			50
	Refined Products			53
	Human Resources			58
Dividends				58
Description of Capital Structure				58
Market for Securities				60
Directors and Officers				61
Audit Committee				66
Legal Proceedings				67
Interest of Management and Others in Material Transactions				67
Transfer Agent and Registrars				67
Interests of Experts				67
Additional Information				67
Abbreviations and Glossary of Terms				68
Special Note Regarding Forward-looking Statements				73
Schedule “A” Audit Committee Charter				75
Consent of KPMG LLP
Consent of McDaniel and Associates Consultants Ltd.
Certification of CEO and Acting CFO pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
Certification of CEO and Acting 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 boe basis using the ratio of six mcf of natural gas to one 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 barrels of oil equivalent (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 73 “Special Note Regarding Forward-Looking Statements”.

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

	2005		2004		2003

Year end		1.166		1.203		1.292
Low		1.151		1.178		1.292
High		1.210		1.397		1.575
Average		1.211		1.302		1.386

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 expected 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 AIF 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 AIF 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 NI 51-101 “Standards of Disclosure for Oil and Gas Activities”. Bitumen is very heavy crude oil that is 10 degrees

API and lower. This guidance stipulates that for establishing the constant prices for bitumen companies should use the posted price for 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, 2005. 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 theBusiness 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 theBusiness 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 theBusiness 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 percent 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”, mean Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis including information with respect to predecessor corporations.

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 percent 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
Husky Energy International Sulphur Corporation		Alberta
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

Effective October 1, 2003, Husky purchased all of the outstanding common shares of Marathon Canada Limited (“Marathon”) and the Western Canadian assets of Marathon International Petroleum Canada, Ltd. The total purchase price was U.S.$588 million. In a separate concurrent transaction Husky sold certain of the Marathon properties to another unrelated company for total proceeds of U.S. $320 million. The properties retained by Husky are located throughout western Alberta and northeastern British Columbia. The acquisition added approximately 39.8 mmboe of gross proved reserves, of which 75 percent was natural gas, and 729,000 acres of undeveloped lands in Alberta, British Columbia and the Northwest Territories.

In November 2003, Husky announced that it had signed a contract with CNOOC for the 04/35 exploration block in the East China Sea. The block comprises 4,835 square kilometres and requires one well to be drilled within the first three years of the contract. CNOOC has the right to participate up to a 51 percent interest in any subsequent development.

In November 2003, we established a securitization program to sell, on a revolving basis, up to $250 million of its accounts receivable to a third party. The agreement includes a program fee based on Canadian commercial paper rates.

On June 18, 2004 Husky issued U.S. $300 million of 6.15 percent notes due June 15, 2019. The notes were priced to yield 6.194 percent 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.

In August 2004 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.

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 3,900 square kilometre 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 percent.

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 percent interest in the 2,794 square kilometre exploration block, which contains two discoveries with commercial quantities of recoverable natural gas and natural gas liquids.

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

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. Completion of the second phase in 2006 will enable the refinery to produce diesel fuel in compliance with the Federal Government’s environmental specifications.

On November 12, 2005 first oil was produced at the White Rose oilfield offshore Newfoundland. Husky holds a 72.5 percent interest in White Rose, which is expected to reach plateau production of 100 mbbls/day (72.5 mbbls/day Husky working interest) by mid 2006. Production from White Rose is 31 degrees API light crude oil and will supply markets both in Canada and the United States.

Subsequent Event

In January 2006, Husky acquired two additional Exploration Licences (“EL”) in the Jeanne d’Arc Basin of the Grand Banks Region offshore Newfoundland. Husky holds 100 percent working interest in the 33,320 acre EL 1094 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 percent senior secured bonds for U.S. $85 million.

Events Expected to Occur During 2006

Husky’s in-situ oil sands project at Tucker, Alberta is expected to commence and ramp up to a plateau production of approximately 30 mbbls/day within a three to six month period. In addition Husky expects to commence front end engineering and design with respect to the extraction process for the first phase of the Sunrise in-situ oil sands project in 2006 as well as develop alternatives for upgrading and marketing. The extraction plans for Sunrise were approved by the Alberta Energy and Utilities Board in December 2005. Husky holds 100 percent working interest in both oil sands projects.

Husky expects construction of its 130 million litre per year ethanol plant at Lloydminster, Saskatchewan to be completed by mid 2006 and its second 130 million litre per year ethanol plant at Minnedosa, Manitoba to be well on its way to a scheduled mid 2007 completion date.

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 is expected to continue. Natural gas prices are sensitive to regional supply/demand imbalances, regional industrial activity levels, weather patterns and access to cheaper sources


(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.

of energy. Oil prices are dependent on the world economy and stable supply. As a result of numerous supply disruptions and increased demand from China and India oil prices have remained historically high.

DESCRIPTION OF HUSKY’S BUSINESS

General

Husky is a publicly held integrated energy and energy related company headquartered in Calgary, Alberta. Our operations include the exploration for and development of crude oil and natural gas properties, as well as the production, purchase, transportation, storage and marketing of crude oil, natural gas, natural gas liquids, sulphur and petroleum coke, and the upgrading and refining of crude oil and marketing of refined petroleum products, including gasoline, diesel, alternative fuels and asphalt products.

Upstream Operations

Husky’s portfolio of assets includes properties with reserves classified as light (30 degrees API and lighter), medium (between 20 degrees and 30 degrees API), heavy (20 degrees and heavier but lighter than 10 degrees API) and bitumen (10 degrees 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.

Reserves and Land Position

At December 31, 2005, our gross proved oil and gas reserves totalled 985 mmboe comprised of 273 mmbbls of light crude oil and NGL, 91 mmbbls of medium crude oil, 291 mmbbls of heavy crude oil, 48 mmbbls of bitumen and 2.1 bcf of natural gas. At December 31, 2005, our gross proved plus probable oil and gas reserves totalled 2,260 mmboe comprised of 462 mmbbls of light crude oil and NGL, 105 mmbbls of medium crude oil, 291 mmbbls of heavy crude oil, 951 mmbbls of bitumen and 2.7 bcf of natural gas. Our undeveloped landholdings in the Western Canada Sedimentary Basin totalled 7.1 million gross acres or 40 percent of our total gross undeveloped land holdings at December 31, 2005.

Properties

In the foothills 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 northeastern British Columbia, we hold natural gas interests in the Sikanni and Federal area as well as Boundary Lake.

In the plains region of northwest Alberta, we operate the Rainbow Lake Plant, miscible floods and properties in surrounding areas. We have interests in the Peace River Arch, Boyer, Sloat Creek, Marten Hills, Cherpeta and Simons Lake 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 southwest Saskatchewan at Shackleton/ Lacadena, Cantaur, Fosterton and Carnduff.

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

We hold a 40 percent working interest in the Wenchang oilfields located offshore in the South China Sea. Production at the Wenchang oilfields began in July 2002. We also hold interests in five exploration blocks in the South China Sea with an aggregate areal extent of approximately 17,800 square kilometres and one exploration block in the East China Sea of approximately 4,800 square kilometres.

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 field development of the BD field. We also hold a small non-operator interest in the Sirte Basin in 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 primarily 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.

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, for continued compliance with environmental legislation and to minimize future and current costs. Husky’s environmental 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.

During 2005 and to the date of this report Husky did not have any commodity price hedges in-place.

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 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, 2005, 84 percent or $1.6 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 emissions of green house gases such as carbon dioxide at its operations, 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 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 for Oil and Gas Activities

In the tables that follow, light crude oil has an API gravity of 30 degrees or more: medium crude oil has an API gravity of above 20 degrees and less than 30 degrees: heavy crude oil has an API gravity of 20 degrees to 10 degrees API.

Production


		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		—		—

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		—		—


		2003

				Western		East
		Total		Canada		Coast		Canada		China		Libya

Crude Oil(mbbls/day)
	Light crude oil and NGL		71.6		32.2		16.8		49.0		22.4		0.2
	Medium crude oil		39.2		39.2		—		39.2		—		—
	Heavy crude oil		99.9		99.9		—		99.9		—		—

	Total gross		210.7		171.3		16.8		188.1		22.4		0.2

	Total net		186.8		149.5		16.7		166.2		20.4		0.2

Natural Gas(mmcf/day)
	Gross		610.6		610.6		—		610.6		—		—

	Net		473.7		473.7		—		473.7		—		—

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


		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		—		—

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		48		48		—		48		—		—


		2003

				Western		East
		Total		Canada		Coast		Canada		China		Libya

		($ millions)
Crude Oil
	Light crude oil and NGL		879		300		238		538		338		3
	Medium crude oil		556		556		—		556		—		—
	Heavy crude oil		943		943		—		943		—		—

	Total gross		2,378		1,799		238		2,037		338		3

	Total net		2,082		1,539		233		1,772		307		3

Natural Gas
	Gross		1,346		1,346		—		1,346		—		—

	Net		1,058		1,058		—		1,058		—		—

	Processing		46		46		—		46		—		—

Sales Prices


		2005

				Western		East
		Total		Canada		Coast		Canada		China		Libya

Crude Oil($/bbl)
	Light crude oil and NGL		61.56		60.15		62.60		61.02		63.15		69.23
	Medium crude oil		43.44		43.44		—		43.44		—		—
	Heavy crude oil		31.09		31.09		—		31.09		—		—
	Total crude oil and NGL		42.75		38.77		62.60		40.97		63.15		69.23
Natural Gas($/mcf)			7.96		7.96		—		7.96		—		—

Sales Prices (continued)


		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		—		—


		2003

				Western		East
		Total		Canada		Coast		Canada		China		Libya

Crude Oil($/bbl)
	Light crude oil and NGL		39.53		38.28		38.91		38.49		41.45		40.44
	Medium crude oil		31.42		31.42		—		31.42		—		—
	Heavy crude oil		25.87		25.87		—		25.87		—		—
	Total crude oil and NGL (before hedging)		31.54		29.48		38.91		30.32		41.45		40.44
	Total crude oil and NGL (after hedging)		30.93		28.96		36.96		29.67		41.45		40.44
Natural Gas($/mcf)
	Before hedging		5.86		5.86		—		5.86		—		—
	After hedging		5.94		5.94		—		5.94		—		—

Capital Expenditures


	2005

			Western		East Coast/
	Total		Canada		Frontier		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 Coast/
	Total		Canada		Frontier		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		—

Capital Expenditures (continued)


	2003

			Western		East Coast/
	Total		Canada		Frontier		Canada		China		Indonesia		Libya

	($ millions)
Property acquisitions⁽²⁾		76		76		—		76		—		—		—
Exploration		324		274		24		298		26		—		—
Development		1,378		845		533		1,378		—		—		—

		1,778		1,195		557		1,752		26		—		—

Notes:


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

(2)	Does not include the acquisition of Marathon Canada Limited.

Oil and Gas Netbacks

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.


			2005

					Western		East
			Total		Canada		Coast		Canada		China		Libya

Crude Oil($/bbl)
	*Light crude oil*
		Sales revenue		61.86		60.74		62.60		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		51.55		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		62.60		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		51.55		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		62.60		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		51.55		27.94		54.30		46.50

Oil and Gas Netbacks (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

Oil and Gas Netbacks (continued)


			2003

					Western		East
			Total		Canada		Coast		Canada		China		Libya

Crude Oil($/bbl)
	*Light crude oil*
		Sales revenue		40.17		39.91		38.91		39.55		41.45		40.44
		Royalties		4.55		7.28		0.81		4.93		3.80		—
		Operating costs		5.41		9.27		3.16		7.05		1.94		15.43

		Netback before hedging		30.21		23.36		34.94		27.57		35.71		25.01

	*Medium crude oil*
		Sales revenue		31.57		31.57		—		31.57		—		—
		Royalties		5.28		5.28		—		5.28		—		—
		Operating costs		9.53		9.53		—		9.53		—		—

		Netback before hedging		16.76		16.76		—		16.76		—		—

	*Heavy crude oil*
		Sales revenue		25.98		25.98		—		25.98		—		—
		Royalties		2.76		2.76		—		2.76		—		—
		Operating costs		9.09		9.09		—		9.09		—		—

		Netback before hedging		14.13		14.13		—		14.13		—		—

	*Total crude oil*
		Sales revenue		31.70		29.52		38.91		30.53		41.45		40.44
		Royalties		3.83		4.14		0.81		3.84		3.80		—
		Operating costs		7.97		9.23		3.16		8.68		1.94		15.43

		Netback before hedging		19.90		16.15		34.94		18.01		35.71		25.01

		Netback after hedging		19.32		15.63		32.99		17.36		35.71		25.01

Natural Gas($/mcf)
	Sales revenue			5.79		5.79		—		5.79		—		—
	Royalties			1.29		1.29		—		1.29		—		—
	Operating costs			0.79		0.79		—		0.79		—		—

	Netback before hedging			3.71		3.71		—		3.71		—		—

	Netback after hedging			3.79		3.79		—		3.79		—		—

Equivalent Unit($/boe)
	Sales revenue			32.69		31.58		38.91		32.01		41.45		40.44
	Royalties			5.11		5.48		0.81		5.21		3.80		—
	Operating costs			6.92		7.56		3.16		7.30		1.94		15.43

	Netback			20.66		18.54		34.94		19.50		35.71		25.01

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		4,308		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
	Newfoundland and Labrador		17		4		—		—		17		4
	Northwest Territories		5		1		5		1		10		2

			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

Canada
	Alberta		4,477		3,525		4,219		3,367		8,696		6,892
	Saskatchewan		4,628		3,689		763		672		5,391		4,361
	British Columbia		223		78		133		74		356		152
	Manitoba		1		1		—		—		1		1
	Newfoundland and Labrador		10		2		—		—		10		2
	Northwest Territories		1		—		2		—		3		—

			9,340		7,295		5,117		4,113		14,457		11,408

International
	China		17		8		—		—		17		8
	Libya		2		1		—		—		2		1

			19		9		—		—		19		9

As at December 31, 2004			9,359		7,304		5,117		4,113		14,476		11,417

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)	2005 includes 331 gross, 312 net oil wells and 566 gross, 459 net natural gas wells and 2004 includes 482 gross, 411 net oil wells and 538 gross, 337 net natural gas wells which were completed in two or more formations and from which the production is not commingled. For the purposes of this table, multiple completions are counted as single wells. Where one of the completions in a given well is an oil completion, the well is classified as an oil well.

(3)	The above table does not include wells in which Husky holds a royalty interest. At December 31, 2005 Husky had royalty interests in 3,679 wells of which 1,370 were oil producers and 2,309 were natural gas producers.

Landholdings


			Developed Acreage

			Gross		Net

			(thousands of acres)
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

As at December 31, 2004
	Western Canada
		Alberta		3,200		2,687
		Saskatchewan		567		506
		British Columbia		186		110
		Manitoba		—		—

				3,953		3,303

	Northwest Territories and Arctic			7		1
	Eastern Canada			35		4

				3,995		3,308

	China			17		7
	Libya			7		2

				4,019		3,317


			Undeveloped Acreage

			Gross		Net

			(thousands of acres)
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

	International			6,280		3,429

				17,763		12,728

Landholdings (continued)


			Undeveloped Acreage

			Gross		Net

			(thousands of acres)
As at December 31, 2004
	Western Canada
		Alberta		4,983		4,449
		Saskatchewan		1,831		1,669
		British Columbia		787		544
		Manitoba		7		7

				7,608		6,669
	Northwest Territories and Arctic			924		254
	Eastern Canada			3,154		2,104

				11,686		9,027

	International			6,280		3,429

				17,966		12,456

Drilling Activity


		Year ended December 31

		2005				2004				2003

		Gross		Net		Gross		Net		Gross		Net

Western Canada Drilling
Exploration
	Oil		89		85		45		39		12		11
	Gas		392		196		234		180		147		124
	Dry		36		36		34		33		22		21

			517		317		313		252		181		156

Development
	Oil		466		433		552		499		520		490
	Gas		610		551		807		740		540		518
	Dry		42		39		57		53		60		57

			1,118		1,023		1,416		1,292		1,120		1,065

			1,635		1,340		1,729		1,544		1,301		1,221

Present Activities


	Exploratory				Development

Wells Drilling⁽¹⁾	Gross		Net		Gross		Net

Western Canada		12		8.1		17		14.5
East Coast		—		—		2		0.9
China		—		—		—		—

		12		8.1		19		15.4

Note:


(1)	Denotes wells that were drilling at December 31, 2005.

Reserves Data and Other Oil and Gas Information

Husky’s oil and gas reserves as of December 31, 2005 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 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 COGEH.

Oil and Gas Reserves Data

The following table presents in summary Husky’s gross and net proved developed reserves, gross and net proved undeveloped reserves and associated future net cash flows as at December 31, 2005. Future revenues, based on prices and costs in effect on that date and remain constant in future periods, are presented net of royalties. Estimated future net revenues assume continuation of year end economic conditions including market demand and government policy, which are subject to uncertainty and may differ materially in the future. It should not be assumed that the discounted value of estimated future net reserves is representative of the fair market value of the reserves.

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⁾		446		399		1,710		1,413		22,512		13,782
Proved undeveloped⁽³⁾⁽⁵⁾		183		166		426		358		5,001		2,923

Proved total⁽³⁾		629		565		2,136		1,771		27,513		16,705

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, 2005 were based on the year-end spot NYMEX natural gas price of U.S. $9.52/mmbtu and on a spot WTI crude oil price of U.S. $61.06/bbl.

(5)	Estimated future capital expenditures required to gain access to proved undeveloped reserves as at December 31, 2005 and 2004 were as follows:


	As at December 31, 2005

	Total		2006		2007		2008		2009		2010		Thereafter

	($ millions undiscounted)
Western Canada		1,428		545		353		191		116		56		167
Eastern Canada		109		87		—		—		—		—		22

		1,537		632		353		191		116		56		189


	As at December 31, 2004

	Total		2005		2006		2007		2008		2009		Thereafter

Western Canada		651		218		210		107		34		13		69
Eastern Canada		352		390		19		9		11		4		(81	)

		1,003		608		229		116		45		17		(12	)


(6)	On December 31, 2005, the date our oil and gas reserves were evaluated, the calculated price of Lloydminster heavy crude oil was $28.57 per barrel. Our heavy crude oil reserves were economic at that price and no negative price revision resulted.

Reconciliation of Gross Proved Reserves


		Canada																	International						Total

																East
		Western Canada														Coast

Proved Reserves,		Light Crude			Medium			Heavy			Natural					Light			Light Crude			Natural			Crude Oil			Natural
Before Royalties⁽¹⁾		Oil & NGL			Crude Oil			Crude Oil			Gas			Bitumen⁽²⁾		Crude Oil			Oil & NGL			Gas			& NGL			Gas

		(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)		(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(bcf)
End of 2002			166			108			227			1,952					31			37			143			569			2,095

	Revisions		5			1			6			(132	)				1			(5	)		(143	)		8			(275	)
	Purchases		9						3			184														12			184
	Sales		(1	)		(3	)		(1	)		(23	)													(5	)		(23	)
	Discoveries and extensions		5			2			29			300														36			300
	Improved recovery		1									1														1			1
	Production		(12	)		(14	)		(37	)		(223	)				(6	)		(8	)					(77	)		(223	)
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

Notes:


(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.

(2)	Bitumen is very heavy crude oil that is 10 degrees API and lower.

Gross Reserves and Production by Principal Area


Crude Oil and NGL⁽¹⁾				Proved Reserves		Production

				(mmbbls)		(mbbls/day)
Canada
	Western Canada
		British Columbia and Foothills
			Alberta and BC Plains area		29		6
			Foothills Deep Gas area		24		6
			Ram River and Kaybob areas		7		2
		Northwest Alberta Plains
			Rainbow Lake area		83		8
			Peace River Arch area		10		4
		East Central Alberta
			North area		2		1
			South area		7		3
			Provost area		29		15
		Southern Alberta and Saskatchewan
			South Alberta area		25		9
			South Saskatchewan area		69		17
		Lloydminster Area
			Primary production		124		79
			Thermal production		66		18
		Oil Sands			48		—
		Other⁽²⁾			—		1

					523		169

	East Coast Canada
			Terra Nova		21		12
			White Rose		68		5

					89		17

	China
		Wenchang			17		16

					629		202

Notes:


(1)	Gross crude oil and NGL reserves as at December 31, 2005 and average 2005 daily gross production of crude oil and NGL.

(2)	Other is comprised primarily of royalty interests, which are not considered to be reserves.


Natural Gas⁽¹⁾				Proved Reserves		Production

				(bcf)		(mmcf/day)
Canada
	Western Canada
		British Columbia and Foothills
			Alberta and BC Plains area		174		56
			Foothills Deep Gas area		278		92
			Ram River and Kaybob areas		249		76
		Northwest Alberta Plains
			Rainbow Lake area		381		56
			Peace River Arch		47		25
			Northern Alberta area		246		89
		East Central Alberta
			Provost area		73		22
			North area		177		54
			South area		197		57
		Southern Alberta and Saskatchewan
			South Alberta area		52		32
			South Saskatchewan area		188		58
		Lloydminster Area			74		56
		Other⁽²⁾			—		7

					2,136		680

Notes:


(1)	Gross natural gas reserves as at December 31, 2005 and average 2005 daily gross production of natural gas.

(2)	Other is comprised primarily of royalty interests, which are not considered to be reserves.

Gross Probable Oil and Gas Reserves⁽¹⁾

Crude Oil & NGL


	Canada

	Western Canada

	Conventional		Bitumen		East Coast		International		Total

	(mmbbls)
2005		146		903		118		13		1,180
2004		113		79		156		13		361
2003		167		79		182		7		435

Natural Gas


	Canada

	Western Canada

	Conventional		International		Total

	(bcf)
2005		407		167		574
2004		388		167		555
2003		381		67		448

Barrels of Oil Equivalent


	Canada

	Western Canada

	Conventional		Bitumen		East Coast		International		Total

	(mmboe)
2005		213		903		118		41		1,275
2004		177		79		156		41		453
2003		231		79		182		18		510

Notes:


(1)	The probable reserves presented have been prepared, using constant prices and costs, in accordance with NI 51-101.

(2)	Probable 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.


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

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, 2005, 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


		Canada						International						Total
Results of Operations for
Producing Activities⁽¹⁾⁽²⁾		2005		2004		2003		2005		2004		2003		2005		2004		2003

		($ millions except per boe amounts)
Oil and gas production revenue			4,085		2,866		2,917		337		310		310		4,422		3,176		3,227

Operating costs
	Lease operating expenses		925		874		794		18		17		17		943		891		811
	Production taxes		56		56		41		—		—		—		56		56		41
	Asset retirement obligation accretion		28		23		18		—		—		—		28		23		18

			1,009		953		853		18		17		17		1,027		970		870
Depreciation, depletion and amortization			1,102		1,018		852		42		59		66		1,144		1,077		918

Earnings before taxes			1,974		895		1,212		277		234		227		2,251		1,129		1,439
Income tax			730		349		491		106		92		91		836		441		582

Results of operations			1,244		546		721		171		142		136		1,415		688		857

Operating costs per gross boe⁽³⁾			8.39		7.66		7.30		3.06		2.25		2.04		8.12		7.32		6.92
Operating costs per net boe⁽⁴⁾			11.09		10.02		9.32		3.24		2.81		2.31		10.64		9.55		8.78
Amortization rate per gross boe			10.10		9.11		8.05		7.21		8.19		8.00		9.95		9.06		8.04
Amortization rate per net boe			12.45		10.97		9.51		7.96		9.13		8.81		12.19		10.85		9.46

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 2005 amounted to $1,036 million (2004 — $981 million; 2003 — $772 million). Income taxes for Canadian producing activities under U.S. GAAP for 2005 amounted to $755 million (2004 — $364 million; 2003 — $511 million).

(3)	Unit operating costs are field operating expenses divided by gross production.

(4)	Unit operating costs include field operating costs, direct administrative expenses and production taxes divided by net production.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities⁽¹⁾


			Canada		International		Total

			($ millions)
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				2,677		78		2,755
		Less: Proved acquisitions		68		—		68
		Capitalized interest		112		—		112

Finding and development costs				2,497		78		2,575

2004
Property acquisition
	Proved			101		—		101
	Unproved			91		62		153
Exploration				295		18		313
Development				1,712		4		1,716
Capitalized interest				75		—		75

Total costs incurred				2,274		84		2,358
		Less: Proved acquisitions		101		—		101
		Capitalized interest		75		—		75

Finding and development costs				2,098		84		2,182

2003
Property acquisition
	Proved			541		—		541
	Unproved			106		—		106
Exploration				298		26		324
Development				1,402		2		1,404
Capitalized interest				52		—		52

Total costs incurred				2,399		28		2,427
		Less: Proved acquisitions		541		—		541
		Capitalized interest		52		—		52

Finding and development costs				1,806		28		1,834

Notes:


(1)	Development costs incurred exclude actual retirement expenditures and include asset retirement obligation incurred.

(2)	Property acquisition costs related to corporate acquisitions for proved properties were $98 million.

(3)	Property acquisition costs related to corporate acquisitions for unproved properties were $40 million.

(4)	Property acquisition costs related to corporate acquisitions for proved properties were $517 million.

(5)	Property acquisition costs related to corporate acquisitions for unproved properties were $54 million.

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.

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, 2005, by the year in which the costs were incurred:


										Prior to
Withheld Costs		Total		2005		2004		2003		2003

		($ millions)
Property acquisitions
	Canada		301		54		—		56		191
	International		75		—		62		—		13

			376		54		62		56		204

Exploration
	Canada		417		279		96		42		—
	International		37		22		13		2		—

			454		301		109		44		—

Development
	Canada		1,213		826		294		93		—
	International		15		6		1		1		7

			1,228		832		295		94		7

Capitalized interest
	Canada		385		112		75		52		146

			2,443		1,299		541		246		357

Capitalized Costs Relating to Oil and Gas Producing Activities


	Canada		International		Total

	($ millions)
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⁽²⁾		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⁽²⁾		10,301		276		10,577

2003
Proved properties		12,017		449		12,466
Unproved properties		1,814		54		1,868

		13,831		503		14,334
Accumulated DD&A		4,718		252		4,970

Net Capitalized Costs⁽²⁾		9,113		251		9,364

Notes:


(1)	Capitalized costs related to proved properties include the asset retirement obligations. The asset retirement obligations for the years presented were as follows:


	Canada		International		Total

2005		377		6		383
2004		314		6		320
2003		223		7		230

(2)

The net capitalized costs for Canadian oil and gas exploration, development and producing activities under U.S. GAAP for 2005 was $11,290 million (2004 — $9,721 million, 2003 — $8,518 million). The net capitalized costs for International property oil and gas exploration, development and producing activities under U.S. GAAP for 2005 was $300 million (2004 — $274 million, 2003 — $249 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 Oil			Natural			Crude Oil			Natural			Crude Oil			Natural
Reserves		& NGL			Gas			& NGL			Gas			& NGL			Gas

		(mmbbls)			(bcf)			(mmbbls)			(bcf)			(mmbbls)			(bcf)
Net proved reserves^(1)(2)(3)(4)
End of 2002			468			1,612			33			101			501			1,713
	Revisions		19			(89	)		(3	)		(101	)		16			(190	)
	Purchases		9			146			—			—			9			146
	Sales		(4	)		(16	)		—			—			(4	)		(16	)
	Discoveries and extensions		31			245			—			—			31			245
	Improved recovery		1			1			—			—			1			1
	Production		(61	)		(182	)		(8	)		—			(69	)		(182	)

End of 2003			463			1,717			22			—			485			1,717
	Revisions		(105	)		(54	)		2			—			(103	)		(54	)
	Purchases		1			17			—			—			1			17
	Sales		(1	)		(12	)		—			—			(1	)		(12	)
	Discoveries and extensions		55			309						—			55			309
	Improved recovery		6			3			—			—			6			3
	Production		(62	)		(192	)		(6	)		—			(68	)		(192	)

End of 2004			357			1,788			18			—			375			1,788
	Revisions		129			(75	)		2			—			131			(75	)
	Purchases		6			2			—			—			6			2
	Sales		(7	)		(7	)		—			—			(7	)		(7	)
	Discoveries and extensions		94			230			1			—			95			230
	Improved recovery		29			6			—			—			29			6
	Production		(59	)		(173	)		(5	)		—			(64	)		(173	)

End of 2005			549			1,771			16			—			565			1,771

Net proved developed reserves,^(1)(2)(3)(4)
	End of year 2002		361			1,273			28			—			389			1,273
	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

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.

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.

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.


		Canada⁽¹⁾						International⁽¹⁾						Total⁽¹⁾

Standardized Measure		2005		2004		2003		2005		2004		2003		2005		2004		2003

								($ millions)
Future cash inflows			40,066		22,681		24,003		999		979		928		41,065		23,660		24,931
	Future production and development costs		13,430		9,353		8,645		122		148		146		13,552		9,501		8,791
	Future income taxes		9,000		4,871		5,696		272		266		247		9,272		5,137		5,943

Future net cash flows			17,636		8,457		9,662		605		565		535		18,241		9,022		10,197
Annual 10 percent discount factor			7,115		3,712		4,242		123		105		117		7,238		3,817		4,359

Standardized measure of discounted
Future net cash flows			10,521		4,745		5,420		482		460		418		11,003		5,205		5,838

Changes in Standardized Measure


	Canada⁽¹⁾									International⁽¹⁾									Total⁽¹⁾

	2005			2004			2003			2005			2004			2003			2005			2004			2003

	($ millions)
Present value at January 1		4,745			5,420			6,347			460			418			839			5,205			5,838			7,186
Sales and transfers, net of production costs		(3,101	)		(1,952	)		(2,097	)		(320	)		(294	)		(293	)		(3,421	)		(2,246	)		(2,390	)
Net change in sales and transfer prices, net of development and production costs		5,585			555			(1,379	)		155			197			(376	)		5,740			752			(1,755	)
Extensions, discoveries and improved recovery, net of related costs		2,027			958			541			24			—			—			2,051			958			541
Revisions of quantity estimates		2,310			(1,318	)		76			110			85			(97	)		2,420			(1,233	)		(21	)
Accretion of discount		762			877			1,055			68			61			130			830			938			1,185
Sale of reserves in place		(62	)		(20	)		(47	)		—			—			—			(62	)		(20	)		(47	)
Purchase of reserves in place		36			45			304			—			—			—			36			45			304
Changes in timing of future net cash flows and other		826			(233	)		(237	)		(13	)		17			(49	)		813			(216	)		(286	)
Net change in income taxes		(2,607	)		413			857			(2	)		(24	)		264			(2,609	)		389			1,121

Net increase (decrease)		5,776			(675	)		(927	)		22			42			(421	)		5,798			(633	)		(1,348	)
Present value at December 31		10,521			4,745			5,420			482			460			418			11,003			5,205			5,838

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.

The future cash flows presented 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.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2005 was based on the NYMEX year-end natural gas spot price of U.S. $9.52/mmbtu (2004 — U.S. $6.02/mmbtu; 2003 — U.S. $5.96/mmbtu) and on crude oil prices computed with reference to the year-end WTI price of U.S. $61.06/bbl (2004 — U.S. $43.36/bbl; 2003 — U.S. $32.51/bbl).

INDEPENDENT ENGINEER’S AUDIT OPINION

January 23, 2006

Husky Energy Inc.

707 – 8^th 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, 2005. 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

REPORT ON RESERVES DATA BY QUALIFIED RESERVES EVALUATOR

To the Board of Directors of

HUSKY ENERGY INC. (the “Company”):


1.	Our staff has evaluated the Company’s reserves data as at December 31, 2005. The reserves data consists of the following:


	(a)	proved oil and gas reserve quantities estimated as at December 31, 2005 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 the Company’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 the Company, 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 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2005:


	Discounted Future Net Cash Flows
Location of Reserves	(Before Income Taxes, 10% Discount Rate)

(country or foreign geographic area)	($ millions)
Canada		16,005
China		688
Libya		12

		16,705


	We have filed the Company’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.

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

Calgary, Alberta

January 19, 2006

/s/Preston Kraft P. Eng

Preston Kraft P. Eng

Manager of Reservoir Engineering

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 Husky’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, 2005 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 Husky’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 Husky’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, Husky involve independent qualified reserve auditors as part of Husky’s corporate governance practices. Their involvement helps assure that Husky’s internal oil and gas reserves estimates are materially correct.

In Husky’s view, the reliability of its 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.

Husky’s view is based in large part on the following. Husky’s 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

133 individuals, including support staff, of whom 64 individuals are qualified reserves evaluators as defined in the Canadian Oil and Gas Evaluation Handbook, with an average of 8 years of relevant experience in evaluating reserves. Husky’s internal reserves evaluation management personnel includes 24 individuals with an average of 12 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 judgements 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 14, 2006

/s/James D. Girgulis James D. Girgulis Vice President Legal & Corporate Secretary				March 14, 2006

/s/R. Donald Fullerton R. Donald Fullerton Director				March 14, 2006

/s/Wayne E. Shaw Wayne E. Shaw Director				March 14, 2006

Description of Major Properties and Facilities

Husky’s portfolio of assets includes properties with reserves of light (30 degrees API and lighter), medium (between 20 degrees and 30 degrees API) heavy (20 degrees API and heavier but lighter than 10 degrees API) and bitumen (10 degrees 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 covering more than 14,800 square kilometres in the Lloydminster area in the Canadian provinces of Saskatchewan and Alberta. Approximately 80 percent 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 maintain a land position of approximately 1.6 million acres in the Lloydminster area, of which approximately 70 percent is undeveloped.

We currently produce from oil and gas wells ranging in depth from 450 to 650 metres and hold a 100 percent 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 net heavy and medium crude oil production from the area totalled 97.4 mbbls/day in 2005. Of the total production, 76.2 mbbls/day was primary production of heavy crude oil, 18.0 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.

In the Lloydminster area we own and operate 16 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 strong growth opportunities for 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 2005 was 55.8 mmcf/day.

Lloydminster Area

British Columbia Foothills/ Northwest Plains

Rainbow Lake Area

Rainbow Lake, located approximately 700 kilometres northwest 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 percent. Our production in this area is derived from more than 50 oil and gas pools extending over 1,300 square kilometres.

We use secondary and tertiary oil recovery methods extensively in the Rainbow Lake area. 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 percent of the original crude oil-in-place in certain pools. As a consequence of implementing these natural gas and NGL re-injection programs, historically only small volumes of gas and NGL have been marketed from the Rainbow Lake area prior to 2002. In 2003, we initiated the recovery of natural gas from several pools. NGL recovery is forecast to begin in the2008-2010 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-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 area. Husky’s gross production from this area averaged 7.8 mbbls/day of light crude oil and NGL and 34.1 mmcf/day of natural gas during 2005.

We hold a 50 percent 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.

During the winter of 2005, Husky installed a dew point facility and compressor at Bivouac to eliminate a pipeline restriction to the Rainbow Lake plant which limited production to 4 mmcf/day. With completion of this facility in May 2005, production from Bivouac increased to 14 mmcf/day. Plans for 2006 are to drill sufficient wells to fill the facility capacity of 20 mmcf/day.

We hold an interest in two significant non-operated properties in the Rainbow area. They include the Ekwan/ Sierra property in northeastern British Columbia and the Bistcho/ Cameron Hills property straddling the Alberta and Northwest Territories border. Our gross production from these properties currently averages 11.0 mmcf/day of natural gas and 143 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 Area

The Slave Lake area 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 northwest of Edmonton. We operate and hold an average 80 percent working interest in several properties in this area. Gross production from our properties was 3.7 mbbls/d of crude oil and 25 mmcf/d natural gas in 2005. The average working interest in these lands is 80 percent. Infrastructure includes a 100 percent working interest in a 30 mmcf/day sour gas plant and three oil batteries. We plan to continue development drilling and waterflood optimization for both crude oil and natural gas targets in this area. In addition, we will assess oil sands deposits for potential primary production.

High Level Area

The High Level area of Alberta is approximately 600 kilometres northwest of Edmonton, Alberta. We are the operator and hold close to 100 percent working interest in our properties. The area holds shallow Bluesky gas reservoirs that are characterized as low deliverability and low decline that are being developed with a drilling density of three wells per section. We intend to continue to develop this area by drilling undeveloped sections, infill drilling, land acquisitions and step out exploration. Gross production from this area in 2005 averaged 32.3 mmcf/day of natural gas. Our plans in 2006 are to drill new wells and recompletions to fully utilize facilities and optimize operating costs.

Athabasca Area

The Athabasca area 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. Gross natural gas production from this district was 49.4 mmcf/day in 2005. The largest asset in the area 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 produced 13.4 mmcf/day in 2005. Our plans for 2006 are to continue with development drilling, recompletions and facility optimizations to keep existing infrastructure fully utilized and optimize unit operating costs. In 2006 we also plan to evaluate the existing oil sands leases and prospective oil sands leases for primary production potential.

Ram River Area

The Ram River area 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 60 mmcf/day. We hold a 34 percent interest in two unitized wells, a 24 percent and a 50 percent 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 percent 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 525 mmcf/day. The plant also has the capacity to produce in excess of 2.8 mlt/day of sulphur from raw gas. During 2005, the plant operated at approximately 90 percent of its design rate capacity. The Ram River plant processes in excess of 10 percent of our total gross natural gas production, which includes an average of 44 mmcf/day of our gross production from the Blackstone, Brown Creek, Cordel and Stolberg fields and an average of 20.6 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 5.1 mmcf/day of natural gas, bringing our total gross production of natural gas from the Ram River area to 65 mmcf/day in 2005. Our 2006 plans for the Ram River area 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 area and hold a 30 percent 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 2005, with the addition of Shell Tay River gas volumes and continued success along the Chungo Mississippian trend, net processing income was $25.3 million.

Kaybob Area

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

We have a 17.8 percent working interest in the sour portion and a 20.4 percent 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 area during 2005 was 390 bbls/day of oil, 463 bbls/day of NGL and 11 mmcf/day of natural gas.

Alberta/ British Columbia Plains

Boundary Lake Area

We hold a 50 percent working interest in the Boundary Lake Gas Unit and a 34 percent and 19 percent interest in the Boundary Lake oil unit 1 and 2, respectively, in northeast 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 12 mmcf/day of natural gas and 1.6 mbbls/day crude oil and NGL from the Boundary Lake units during 2005.

Valhalla and Wapiti Area

We hold an approximate 30 percent interest in three Valhalla oil units, a 100 percent interest in the Valhalla non-unit waterflood wells and a 100 percent 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 3.3 mbbls/day of crude oil and NGL and 8.5 mmcf/day of natural gas in 2005.

Kakwa Area

We hold an average 60 percent 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 14.8 mmcf/day of natural gas, 491 bbls/day NGL and 307 bbls/day of oil in 2005.

Lynx and Copton Area

Husky has had a significant focus on exploration activity in the Lynx/ Copton area of western Alberta drilling and tie-in of four net wells in the area, increasing production from 12 mmcf/d to 16 mmcf/d. We plan to continue to develop this immature asset in 2006 to maintain Husky production at 15 mmcf/d.

Foothills West

Caroline Area

We hold an 11 percent working interest in the 32,000 acre Caroline natural gas field located approximately 97 kilometres northwest 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 percent interest in the Caroline sour gas processing facility. The plant is presently running at a license limit of 113 percent of design capacity and is processing approximately 124 mmcf/day of total plant sales gas and 39 mbbls/day of NGL. Husky’s gross production was 3.3 mbbls/day NGL and 11.9 mmcf/day natural gas in 2005.

Edson Area

We hold an average 85 percent working interest in two gas processing facilities and associated gas gathering systems in the Edson area. We operate these properties that had average gross production of 34.0 mmcf/day of natural gas and 1.4 mbbls/day of NGL in 2005. Husky had a significant development program of 20 development in 2005 with plans to drill 20 wells in 2006 to increase production to 40 mmcf/day.

Sikanni Area

We hold interests in properties in the Sikanni and Federal areas of northeast British Columbia, which averaged gross production of 9.8 mmcf/day of natural gas from four wells in 2005. The production flows through our gathering systems for processing at third party plants at Sikanni and McMahon. In December 2005 Husky’s gross production increased by 6 mmcf/day with the payout of a reversionary working interest on a farmout well in the Lily area.

Graham Area

We hold a 40 percent working interest in lands in the Graham area of northeastern British Columbia. Our gross production from this area averaged 8.3 mmcf/day of gross natural gas sales in 2005. 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 full capacity. We hold a 33.2 percent interest in the gas treating unit, 28.2 percent interest in the amine unit and 28 percent interest in the sulphur unit.

East Central Alberta

Craigend Area

The Athabasca area 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 percent 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 54.3 mmcf/day of natural gas and 635 bbls/day of crude oil in 2005.

Red Deer and Hussar Area

The core of the Red Deer and Hussar area is between Calgary, Drumheller and Sylvan Lake. Husky operates 21 facilities with gas gathering systems in this area. Our gross production from this area averaged 57.3 mmcf/day of natural gas and crude oil and NGL of 2.4 mmbbls/day in 2005. We intend to continue to develop the natural gas potential of this area 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, and by year-end 2005 had drilled 300 wells and built extensive infrastructure. There were 120 wells tied-in by year-end that were producing gross 10 mmcf/day of natural gas. In 2006, we plan to drill 300 more wells to reach an expected gross 35 mmcf/day of natural gas.

Provost Area

The centre of the Provost area is approximately 240 kilometres southeast of Edmonton. It is predominantly a medium crude oil area that averaged gross production of 15.4 mbbls/day of crude oil and 22.2 mmcf/day of natural gas

in 2005. We intend to selectively drill lower risk oil locations and focus on managing operating costs and improving oil recovery, as well as increasing our focus on natural gas exploration and development. In 2006, we intend to continue to develop several of our 2004 and 2005 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 percent working interest in most of our facilities.

Southern Alberta and Southern Saskatchewan

Southern Saskatchewan Area

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 area averaged 16.7 mbls/day of crude oil and 58.2 mmcf/day of natural gas during 2005.

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

At the Shackleton/ Lacadena Milk River shallow gas project, 132 wells were drilled and tied-in in 2005. The project was producing at a rate of 48.8 mmcf/day of natural gas at December 31, 2005 from a total of 330 wells. In 2006, we plan to drill between 65 and 100 additional step out and infill wells and add two 8 mmcf/day sales gas plants.

Southern Alberta Area

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 percent. 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 Etzikom, near Taber, we operate an alkaline-polymer flood to increase recovery from the Cretaceous Mannville reservoir and we are currently implementing additional floods at Warner and Crowsnest for 2006, and 2007 respectively. Our gross production from this area averaged 10.2 mbbls/day of crude oil and 32.1 mmcf/day of natural gas during 2005.

During 2005 we divested of approximately 1,100 bbls/day of heavy crude production at Jenner, which had very high operating costs, and minimal upside.

Oil Sands

Athabasca, Cold Lake and Peace River

Husky currently holds interests in 433,610 net acres, including 7,680 acres of petroleum and natural gas rights, in the bitumen prone areas of Athabasca, Cold Lake and Peace River.

In addition to interests in the 353,930 net acres in the Cold Lake and Athabasca regions in northeastern Alberta, Husky holds an interest in 79,680 net acres in the Peace River region of northern Alberta.

Tucker

In May of 2004 we received approval from the Alberta Energy and Utilities Board to develop the Tucker in-situ oil sands project. Tucker is located 30 kilometres northwest of Cold Lake, Alberta. The Tucker project will utilize SAGD technology and will have a design rate capacity of 30 mbbls/day. Construction commenced in late 2004 and as of year-end 2005 drilling operations were 85 percent complete and facility construction was approximately 65 percent complete. The project remains on schedule and on budget and we expect to commission the facility in the third quarter of 2006 with first oil production before year-end 2006.

Sunrise

The Sunrise in-situ oil sands project is located in the Athabasca region of Alberta. Stratigraphic delineation drilling over the last four years has confirmed a large recoverable resource base with original bitumen-in-place under Husky lands estimated at 10.6 billion barrels. 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 in December 7, 2005. Husky worked closely with local stakeholders including several First Nations and the local environmental coalition and obtained regulatory approval approximately 15 months after submission. During 2006 Husky will conduct front end engineering and design for the extraction aspects of the project and will develop optimal transportation and product marketing plans.

Caribou

Our Caribou oil sands lands are located in the Cold Lake Air Weapons Range and comprise 35,840 acres. Pilot testing was conducted in the early 1990s. Further stratigraphic drilling in 2005 yielded encouraging results, confirming that the Clearwater reservoirs being developed to the south by other operators extend onto Husky’s Caribou lands. In 2006 Husky will drill 15 additional stratigraphic (resource assessment) wells and begin preparation of the development project application.

Saleski

Our largest bitumen deposit, with original bitumen-in-place estimated at 16.8 billion barrels is located approximately 120 kilometres west of Fort McMurray, Alberta. The bitumen is contained in the Grosmont carbonate formation. During 2005 Husky examined available geological data and the results of previous pilot projects. A 20 well program will be conducted in 2006 to provide additional geological data. Since there are no existing operations producing bitumen from the Grosmont carbonate, piloting of various technologies will be required over the coming years to identify commercial development approaches.

Oil Sands Leases

Oil Sands

Gross

Net

Husky

General Location Name

Area

Acres

Operator

South Athabasca — overriding royalty

Athabasca

35,601

—

South Athabasca

Athabasca

22,032

11,016

Yes

Sunrise — In situ⁽¹⁾

Athabasca

57,634

Yes

Misthae (Drowned, Martin Hills W. & Spur)

Athabasca

28,160

Yes

Saleski

Athabasca

154,880

Yes

Hoole — overriding royalty

Athabasca

47,040

—

Beaverdam

Cold Lake

11,520

Yes

Caribou⁽²⁾

Cold Lake

35,840

Yes

Lobstick

Cold Lake

37,120

Yes

Tucker⁽³⁾

Cold Lake

10,080

Yes

Panny (Senex & Welstead)

Peace River

47,360

Yes

Peace River (Cadotte Lake)

Peace River

11,840

Yes

Sawn Lake (Loon)

Peace River

20,480

Yes

519,587

425,930

Notes:


(1)	Not 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 GB2003-28 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)	Not 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.

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, which contains the Hibernia, Terra Nova and White Rose oilfields. We hold ownership interests in the Terra Nova and White Rose oilfields as well as in a number of smaller undeveloped fields in the central part of the basin. We presently hold working interests ranging from 5.33 to 72.5 percent in 15 Significant Discovery License (“SDL”) areas in the Jeanne d’Arc Basin. We are also the operator of 10 exploration licenses (“EL”) on the Grand Banks and also hold an interest in one non-operated EL on-shore in the province of Nova Scotia. In 2005, we acquired 2 ELs. One of the licenses, EL 1096, totalling 5,263 acres is directly north of the Terra Nova oilfield and the other, EL 1094, totalling 33,321 acres is directly west of the Hebron significant discovery area. Husky holds 100 percent of the two licences and operates both. We believe that there is exploration potential in the area, and that our position off the East Coast of Canada will provide growth opportunities for light crude oil production in the medium to long-term.

We will continue technical evaluation of our East Coast exploration acreage. In 2006, we plan to acquire3-D seismic over several license areas in the Northern Jeanne d’Arc Basin as well as south of the White Rose oilfield. Depending on drilling rig availability, we plan on drilling several delineation/ exploration wells in 2006.

In January 2006, we relinquished two ELs following the drilling of the Lewis Hill G-85 exploration well, which was plugged and abandoned.

Terra Nova Oilfield

The Terra Nova oilfield is located approximately 350 kilometres southeast of St. John’s, Newfoundland and Labrador, 35 kilometres southeast of the Hibernia oilfield, in 91 to 100 metres of water. The Terra Nova oilfield 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 percent. 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 2005 from the Terra Nova field was 4.5 mmbbls based on an average of 12.4 mbbls/day annual production rate.

As at December 31, 2005, there were 12 development wells drilled in the Graben area, eight production wells and four 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 in 2006 based on a 36 well depletion plan for the Graben and East Flank areas. An extended reach well was drilled from the East Flank subsea template to the Far East Central area in 2005 and production will commence during the first quarter of 2006. Husky continues to promote drilling additional delineation wells in the Far East area and a Far East South well location, PF8, will be included in the 2006 drilling program. As at December 31, 2005, we had booked 13.7 mmbbls of gross light crude oil in the proved developed category and 6.7 mmbbls of proved undeveloped. These reserves are estimated to be capable of being produced using primary and secondary (waterflood and gasflood) production techniques.

White Rose Oilfield

The White Rose oilfield, which we operate, is located 354 kilometres off the coast of Newfoundland approximately 48 kilometres east of the Hibernia oilfield on the eastern section of the Jeanne d’Arc Basin. Husky holds a 72.5 percent interest in the White Rose oilfield. At plateau production, the oilfield is estimated to produce approximately 100,000 barrels per day and Husky’s share is expected to average 67,500 barrels per day on an annual basis. Husky’s share of proven and probable reserves for the field is estimated at 173 million barrels including the currently undeveloped West Avalon pool.

In August 2005, theSeaRose FPSO(floating production, storage and offloading vessel) arrived at the White Rose oilfield, 350 kilometres east of St. John’s, Newfoundland and Labrador, following a48-hour journey from Marystown, Newfoundland and Labrador. TheSeaRose FPSOhad arrived in Marystown in April 2004, where topsides fabrication, installation and commissioning were carried out. TheSeaRose FPSOdeparted Marystown on August 20, 2005. The vessel connected to a subsea production system and then underwent approximately three months of offshore hook-up and commissioning in preparation for first oil.

In November, 2005 first oil production was achieved marking the successful completion of the third offshore oil development for Newfoundland and Labrador. Oil was introduced into the process stream on theSeaRose FPSOon November 12, 2005. The White Rose field is expected to reach plateau production of 100,000 barrels per day in the first half of 2006. Husky has chartered two shuttle tankers, theHeather Knutsenand theJasmine 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. In December 2005, Husky offloaded three shipments of crude oil from theSeaRose FPSO.Approximately 2.4 million barrels of oil were produced from the White Rose field in 2005, with 1.74 million net to Husky.

Development drilling activity at the field is on schedule with 10 wells drilled as at the end of 2005, including three production wells, one gas injection well and six water injection wells. All well results were as predicted, or better. Initial production from the field supports an average oil production per well of 25,000 bbls/day.

In 2005, three pre-front end engineering and design studies relating to East Coast Natural Gas development were completed. The studies were undertaken by Husky to evaluate the viability of producing and transporting natural gas from White Rose. The studies commissioned focused on screening assessment of compressed natural gas (CNG) as one potential development option. During 2005 the scope was widened to consider and rank all technical options for development of the east coast natural gas resource. Husky also entered into a Memorandum of Understanding with other east coast operators to explore potential synergies and a regional solution.

Husky intends to progress technical screening to a shortlist of solutions complete with high level cost estimates. In parallel, delineation drilling will improve estimates of the reserve base ahead of future development. We will also continue to work closely with the Government of Newfoundland and Labrador as they work to develop a suitable fiscal regime during 2006.

East Coast

International

Our international exploration and development program is focused on Southeast Asia. In China, we have a 40 percent interest in one producing oilfield and interests in six exploration blocks. The bulk of these interests are in the South China Sea. In Indonesia, we have a 100 percent interest in the Madura block.

South China Sea

Wenchang

The Wenchang oilfield 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 percent working interest in the oilfields, which commenced production in July 2002. The Wenchang 13-1 and13-2 oilfields are producing from 24 wells in 100 metres of water into a FPSO (floating production, storage and offloading vessel) stationed between fixed platforms located in the fields. The blended crude oil from the two fields averages approximately 35 degree API, similar to the benchmark Minas blend. At December 31, 2005, our gross proved reserves at Wenchang were 17.3 mmbbls of crude oil and NGL. Our gross production averaged 16.0 mbbls/day during 2005. Two near field wildcat exploration wells were drilled in 2005 with no economic success.

Block 39/05

We executed a production sharing contract with China National Offshore Oil Corporation (“CNOOC”) for the 5,700 square kilometres 39-05 exploration block surrounding the Wenchang fields with a commencement date of October 1, 2001. CNOOC has the right to participate in development of any discoveries up to a 51 percent 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 percent of Block 39-05. Husky will relinquish an additional 25 percent of39-05 in 2006. Husky is continuing to evaluate the geological information for the remainder of this block and expects to undertake additional exploration drilling in 2007.

Blocks 23/15 and 23/20

Husky executed production sharing contracts with CNOOC for the23-15 and23-20 exploration blocks with a commencement date of December 1, 2002. Both contract areas are located in the South China Sea north of Hainan, within 80 kilometres of the Weizhan oilfields. The23-15 block is approximately 1,325 square kilometres and the23-20 Block is 1,543 square kilometres. The work program requires Husky to drill a single exploration well on each block within three years. CNOOC has the right to participate in development of any discoveries up to a 51 percent working interest. In 2003, we completed a 1,000 square kilometre3-D seismic survey shot over a portion of block 23-15. Husky fulfilled its Phase I commitments on Block 23-15 with the drilling of Wushi 17-1-1 in 2005. Husky is currently evaluating the results ofWS17-1-1 and expects to announce its intentions with respect to Phase II commitments in 2006. Husky fulfilled its Phase I commitments on Block 23-20 with drilling of Wushi 32-1-1 in 2005. Husky is currently evaluating the results ofWS32-1-1 and its intentions with respect to Phase II commitments in 2006.

Block 29/26

Husky executed a production sharing contract with CNOOC for the29-26 exploration block with a commencement date of October 1, 2004. The block is located in the South China Sea approximately 300 kilometres southeast of Hong Kong and 65 kilometres southeast of the Panyu gas discovery. The block covers an area of approximately 3,965 square kilometres. The production sharing contract requires the drilling of one exploration well within three years and has a minimum work commitment of U.S.$8 million. CNOOC has the right to participate in development of any discoveries up to a 51 percent working interest. Husky has contracted a deep-water drill ship and plans to spud the first exploratory well in the first quarter of 2006.

Block 40/30

We executed a production sharing contract with CNOOC for the 40-30 exploration block with a commencement date of February 1, 2003. The block is located in the South China Sea approximately 100 kilometres south of the Wenchang 13-1 and13-2 oilfields. The block covers an area of approximately 6,705 square kilometres. The production sharing contract requires the drilling of one exploration well within three years and has a minimum work commitment of U.S.$10 million. CNOOC has the right to participate in development of any discoveries up to a 51 percent working interest. We fulfilled our Phase I obligations of the petroleum contract with the drilling of ChangChang (“CC”)12-1-1. The CC 12-1-1 is the deepest-water well in the South China Sea to date. TheCC12-1-1 well was plugged and abandoned without testing.

East China Sea

Block 04/35

We executed a production sharing contract with CNOOC for the04-35 exploration block with a commencement date of 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 4,835 square kilometres. 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 first phase commitments early in 2006. CNOOC has the right to participate in development of any discoveries up to a 51 percent working interest. Husky has completed its preliminary geological evaluation and expects to begin exploration drilling in 2006.

China

Madura Strait, Indonesia

We have a 100 percent interest in the approximately 2,795 square kilometre Madura Strait production sharing contract (“PSC”), 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 has been 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. Husky has begun discussions to establish a new natural gas sales contract for Madura production and in addition, the development engineering re-validation work commenced in 2005 for the production facilities. In 2006, we expect to complete negotiation of the gas sales contract, submit a revised Plan of Development to the Indonesian regulatory authority for approval and negotiate an extension to the PSC term. Production is expected to come on stream approximately three years after these agreements are negotiated.

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. The combined dry crude feedstock requirements of the upgrader and asphalt refinery are equal to approximately 75 percent 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,

		2005		2004		2003

		(mmcf/day)
Sales to end users
	United States		357		407		382
	Canada		212		187		156

			569		594		538

Sales to aggregators			31		34		43
Internal use⁽¹⁾			80		61		30

			680		689		611

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 in Western Canada. 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

2006		25.9		3.98		19.7
2007		20.4		4.51		19.7
2008		20.4		4.75		11.8
2009		20.4		5.00		0.9
2010		20.4		5.28		0.5
2011		20.4		5.57		—
2012		20.0		5.47		—
2013		20.0		3.67		—
2014		6.2		3.67		—

Midstream Operations

Overview

The midstream operations include:


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

	•	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 56.7 mbbls/calendar day of synthetic crude oil and 9.9 mbbls/day of diluent in 2005 compared with 55.2 mbbls/day of synthetic crude oil and 9.4 mbbls/day of diluent in 2004. Throughput at the Upgrader in 2005 was higher than 2004 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 312 lt/day of sulphur and 755 lt/day of petroleum coke during 2005. These products are sold in local and international markets. By the end of 2006 it is anticipated that the Upgrader will also be producing 2,500/bbls per day of low sulphur diesel. The profitability of our upgrading operations is primarily dependent upon the differential between the price of synthetic crude oil and the price of heavy crude oil. The Upgrader shipped its 250 millionth barrel of Husky Synthetic Blend in May 2005.

The Upgrader is currently undergoing a number of debottleneck projects. These projects, upon completion in late 2006, are expected to increase upgrading capacity to 82 mbbls/day of synthetic crude oil and diluent.

Infrastructure

Heavy Oil Pipeline Systems and Processing Facilities

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,

2005

2004

2003

(mbbls/day)

Combined pipeline throughput

474

492

484

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.

Heavy Oil Pipeline Systems

Cogeneration

Husky has a 50 percent 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 percent 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 northwestern 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/northeastern United States (28 percent), mid-west United States (23 percent), Western Canada (46 percent) and west coast United States (3 percent). The natural gas volumes sales contracted are primarily at market prices (90 percent). The terms of the contracts remaining at December 31, 2004 are up to one year (74 percent), one year to five years (18 percent) and over five years (8 percent). 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.

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 and retail, commercial and wholesale marketing 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.

Branded Petroleum Product Outlets and Commercial Distribution

Distribution

As of December 31, 2005, there were 515 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.

Retail Marketing System

Branded Petroleum Product Outlets

Branded Petroleum Outlets

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, 2005:


	British
	Columbia &												2004
Retail Outlets	Yukon		Alberta		Sask.		Manitoba		Ontario		Total		Total

Travel Centres		9		8		4		2		13		36		36
Full Serve		10		15		2		2		2		31		37
Full/ Self Serve		16		25		6		11		3		61		59
Self Serve		18		12		1		1		1		33		34
Bulk Distributor		1		7		4		1		1		14		14
Card/ Key Locks		2		7		0		0		1		10		10

		56		74		17		17		21		185		190

Leased
Travel Centres		1		0		0		0		0		1		1
Full Serve		3		8		5		4		0		20		24
Full/ Self Serve		14		22		4		6		0		46		46
Self Serve		31		22		0		1		0		54		52
Bulk Distributor		3		0		0		0		0		3		3
Card/ Key Locks		3		2		0		3		2		10		9

		55		54		9		14		2		134		135

Independent Retailers
Travel Centres		1		1		0		0		4		6		6
Full Serve		22		15		8		14		7		66		77
Full/ Self Serve		17		5		5		1		1		29		28
Self Serve		29		45		4		3		2		83		85
Bulk Distributor		2		4		1		0		0		7		7
Card/ Key Locks		1		1		0		0		3		5		3

		72		71		18		18		17		196		206

Total
Travel Centres		11		9		4		2		17		43		43
Full Serve		35		38		15		20		9		117		138
Full/ Self Serve		47		52		15		18		4		136		133
Self Serve		78		79		5		5		3		170		171
Bulk Distributor		6		11		5		1		1		24		24
Card/ Key Locks		6		10		0		3		6		25		22

		183		199		44		49		40		515		531

Cardlocks⁽¹⁾		24		18		4		6		21		73		74
Convenience Stores⁽¹⁾		178		183		39		46		33		479		484
Restaurants		11		12		4		2		16		45		45

Note:


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

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 northwestern United States.

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


	Years ended
	December 31,

	2005		2004		2003

	(mbbls/day)
Gasoline		28.3		28.3		28.5
Diesel fuel		26.5		23.9		22.1
Liquefied petroleum gas		0.9		1.1		1.2

		55.7		53.3		51.8

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.

Supply

Prince George Refinery

In 2005 Husky completed the upgrade at its Prince George Refinery to produce low sulphur gasoline fuels that meet the Government of Canada’s new fuel specification. The cost of the upgrade is expected to be $92 million and with this upgrade refinery nameplate productive capacity was increased 20 percent to 12,000 bbls/day. Upgrades to produce ultra low sulphur diesel will continue into 2006. The Prince George refinery production makes up 22 percent of the Refined Products — Light Oil’s fuel supply as it is the lowest cost supply source. 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 oilfield products. The refinery has a total nameplate throughput capacity of 25,000 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 is currently under construction, at a cost of approximately $130 million. This plant, which is scheduled to be operational in the second quarter 2006, will have 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, and 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 with major refiners. Processing arrangements allow us to participate in industry refining margins. Primarily Husky crude oil production and some third party purchased crude oil is delivered 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 2005, these refiners processed an average of approximately 38.2 mbbls/day of crude oil

for us, yielding approximately 34.7 mbbls/day of refined petroleum products. During 2005, we also purchased approximately 11.2 mbbls/day of refined petroleum products from refiners and acquired approximately 6.2 mbbls/day of refined petroleum products pursuant to exchange agreements with third party refiners.

Asphalt Products

Husky produces asphalt and residual products at our 10,000 bbls/day asphalt refinery at Lloydminster and markets these products to customers across Western Canada and the northwestern and midwestern United States.

Husky has 37 percent of the market for paving asphalt sold in Western Canada our Pounder Emulsions division has a 50 percent market share in Western Canada for road application emulsion products and additional non-asphalt based road maintenance products are marketed and distributed through the Western Road Management division. We have increased sales to the United States and Eastern Canada, with 40 percent of production in 2005 exported to the United States and products shipped as far as Texas, Florida and New Brunswick. Husky plans to expand asphalt production, improve distribution, improve quality and reduce cost.

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 a hydrogen deficient and are sold directly to the Upgrader and blended into the Husky Synthetic Blend stream. The cut 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 was designed specifically to produce asphalt from heavy crude oil at a rate of 25 mbbls/day. Debottlenecking has allowed us to increase that to 26.9 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,

	2005		2004		2003

	(mbbls/day)
Asphalt		13.8		14.0		12.9
Residual and other		8.7		8.8		9.1

		22.5		22.8		22.0

Refinery throughput averaged 25.5 mbbls/day of blended heavy crude oil feedstock during 2005. Total production of asphalt at the refinery for 2005 was down due to a planned maintenance and repair turnaround in July as well as other repairs that limited production.

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.

Some of the focus areas in 2006 will include identifying acquisition, merger, brokering, terminalling, and processing opportunities, increasing residual sales relative to diluents and tops to enhance margins, focusing on sales of higher quality products with larger margins, developing new sales tools and programs to improve customer service and satisfaction and developing new products and improving existing products.

Human Resources

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


	December 31,

	2005		2004

Upstream		2,019		1,822
Midstream		367		347
Refined Products		385		358
Corporate and business support		518		505

		3,289		3,032

DIVIDENDS

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


	2005		2004		2003

Cash dividends declared per common share	$	1.65	$	1.00	$	1.38

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 July 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 again reviewed in April 2005 and increased to $0.14 ($0.56 annually) and again in October 2005 when it was increased to $0.25 ($1.00 annually). 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 amounting to $1.00 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, theBusiness 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.

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

U.S. Senior Secured Bonds

Baa2

April 30, 2004

April 25, 2001

Capital Securities

Ba1

August 29, 2005

April 25, 2001

Standard and Poor’s:

Outlook

Positive

September 12, 2005

October 3, 2002

Senior Unsecured Debt

BBB

September 12, 2005

—

U.S. Senior Secured Bonds

BBB

August 24, 2005

—

Capital Securities

BB+

September 12, 2005

—

Dominion Bond Rating Service:

Trend

Stable

May 13, 2005

—

Senior Unsecured Debt

BBB(high)

May 13, 2005

—

Capital Securities

BBB

May 13, 2005

Fitch:

Outlook

Stable

July 22, 2005

—

Senior Unsecured Debt

BBB+

July 22, 2005

—

U.S. Senior Secured Bonds

A-

July 22, 2005

Capital Securities

BBB-

July 22, 2005

—

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 of 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 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, 2005:


	High		Low		Volume

					(000’s)
January		34.90		32.50		11,845
February		37.65		32.30		20,225
March		40.49		35.89		14,300
April		38.84		35.12		16,441
May		42.30		36.65		12,283
June		50.75		42.00		18,264
July		53.35		47.37		11,386
August		62.00		53.50		11,413
September		69.95		59.00		11,722
October		65.79		50.50		15,936
November		59.95		53.63		11,028
December		61.60		55.58		11,767

DIRECTORS AND OFFICERS

The following are the names and municipalities of residence of the directors and officers of Husky, 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.


Name and
Municipality of
Residence	Office or Position	Director Since		Principal Occupation During Past 5 Years

Li, Victor T.K. Hong Kong	Co-Chairman and Director		August 25, 2000	Managing Director of Cheung Kong (Holdings) Limited (an investment holding and project management company) since 1999 and Deputy Chairman since 1994. Mr. Li has also been Deputy Chairman of Hutchison Whampoa Limited (an investment holding company) since 1999 and Executive Director since 1995. Mr. Li has been a Director and Chairman of CK Life Sciences Int’l., (Holdings) Inc. (a biotechnology company) since 2002 and has held the following positions for more than five years: a Director and Chairman of Cheung Kong Infrastructure Holdings Limited (an infrastructure development company), an Executive Director of Hongkong Electric Holdings Limited (a holding company). Mr. Li is also a Director of The Hongkong and Shanghai Banking Corporation Limited. Mr. Li is a member of the Standing Committee of the 10^thNational 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 and the Economic and Employment Council of the Hong Kong Special Administrative Region. Mr. Li holds a Bachelor of Science degree in Civil Engineering and a Master of Science degree in Structural Engineering.
Fok, Canning K.N. Hong Kong	Co-Chairman and Director		August 25, 2000	Group Managing Director of Hutchison Whampoa Limited since 1993 and Executive Director since 1984. Mr. Fok has been a Director and Chairman of Hutchison Telecommunications International Limited (an investment holding company) since 2004. Mr. Fok has held the following positions for more than five years: a Director and since 2002, Chairman of Hutchison Harbour Ring Limited (an investment holding company), a Director and Chairman of Hutchison Telecommunications (Australia) Limited (a telecommunications company), and Partner Communications Company Ltd. (a telecommunications company), Deputy Chairman and a Director of Cheung Kong Infrastructure Holdings Limited and a Director, and since November 2005 Chairman


Name and
Municipality of
Residence	Office or Position		Director Since		Principal Occupation During Past 5 Years

					of Hongkong Electric Holdings Limited. Mr. Fok is also a director of Cheung Kong (Holdings) Limited and Hutchison Whampoa Finance (CI) Limited (a finance company). Mr. Fok is also a Non Executive Director of Panvas Gas Holdings Limited. Mr. Fok was a director of Voice Stream Wireless Corporation from 1998 - 2001 and Hanny Holdings Limited from 1992 - 2005. Mr. Fok holds a Bachelor of Arts degree and is a member of the Australian Institute of Chartered Accountants.
Fullerton, R. Donald Toronto, Ontario Canada		Director		May 1, 2003	Corporate Director. Mr. Fullerton has been a Director of Asia Satellite Telecommunications Holdings Limited since 1996. Mr. Fullerton was a director of George Weston Limited (a holding company) from 1991 to 2005, of Partner Communications Ltd. from 2003 to 2005, of CIBC from 1974 to 2004, of Hollinger Inc. from 1992 to 2003, of Westcoast Energy Inc. from 1993 to 2003 and of IBM Canada Ltd. from 1982 to 2001.
Glynn, Martin J.G. New York, New York U.S.A.		Director		August 25, 2000	President and Chief Executive Officer of HSBC Bank USA N.A. since 2003 and a director since 2000. Mr. Glynn has been a director of HSBC Bank Canada since 1999 and was President and Chief Executive Officer from 1999 to 2003. From 1982 Mr. Glynn held various senior executive positions with HSBC Bank Canada (formerly Hongkong Bank of Canada). Mr. Glynn is also a director of Wells Fargo HSBC Trade Bank N.A. and Group General Manager of HSBC Holdings plc.
Hui, Terence C.Y. Vancouver, British Columbia Canada		Director		August 25, 2000	President & Chief Executive Officer, Concord Pacific Group Inc. (a real estate development company) since 1997, Director and President of Adex Securities Inc. (a financial services company) since 1992 and Director and Chairman of Maximizer Software Inc. (formerly Multiactive Software Inc.) and Multiactive Technologies Inc. (computer software companies) since 1995 and of Coopers Park Real Estate Corporation since 2005. Mr. Hui was President and Chief Executive Officer of Pacific Place Developments Corp. (a real estate development company) from 1992 to 2001. Mr. Hui has been a director of abc Multiactive Limited (a software company) since 1995.
Kinney, Brent D. Dubai, United Arab Emirates		Director		August 25, 2000	Mr. Kinney has been a director and Chief Executive Officer of Sky Petroleum Inc. since 2005. Mr. Kinney has been a director


Name and
Municipality of
Residence	Office or Position		Director Since		Principal Occupation During Past 5 Years

					of Dragon Oil plc since 2001, of Western Silver Corporation (a mineral exploration company) since 2005 and of Benchmark Energy Ltd. since 2005. Mr. Kinney was also a director of Aurado Energy Inc. from 2003 to 2004.
Kluge, Holger Toronto, Ontario Canada		Director		August 25, 2000	Corporate Director. Mr. Kluge has been a director of Hongkong Electric Holdings Limited since 1999, of Hutchison Whampoa Limited since 2004 and of Shoppers Drug Mart since 2006. Mr. Kluge was a director of Hutchison Telecommunications (Australia) Limited from 1999 to 2005, of TOM Group Limited (formerly TOM.COM LIMITED) from 2000 to 2005, and of Loring Ward International Limited (a financial planning company) from 2004 to 2005. Mr. Kluge holds a Bachelor of Commerce degree and a Master’s degree in Business Administration.
Koh, Poh Chan Hong Kong		Director		August 25, 2000	Finance Director, Harbour Plaza Hotel Management (International) Ltd. since 1998.
Kwok, Eva L. Vancouver, British Columbia Canada		Director		August 25, 2000	Chairman, a director and Chief Executive Officer of Amara International Investment Corp. (an investment holding company) since 1992 and President from 1992 to 1996. Mrs. Kwok has been a director of Bank of Montreal Group of Companies since 1999, of CK Life Sciences Int’l., (Holdings) Inc. since 2002, Cheung Kong Infrastructure Holdings Limited and Shoppers Drug Mart since 2004 and of the Li Ka Shing (Canada) Foundation since 2005. Mrs. Kwok was a director of Air Canada from 1998 to 2003 and of Telesystem International Wireless Inc. from 2002 to 2003.
Kwok, Stanley T.L. Vancouver, British Columbia Canada		Director		August 25, 2000	President, Stanley Kwok Consultants (an architecture, planning and development company) since 1993. Mr. Kwok has been a director since 1997 and President since 1999 of Amara International Investment Corp. Mr. Kwok is a director of Cheung Kong (Holdings) Limited and CTC Bank of Canada.
Lau, John C.S. Calgary, Alberta Canada	President & Chief Executive Officer and Director			August 25, 2000	President & Chief Executive Officer of Husky Energy Inc. since August 2000.
Shaw, Wayne E. Toronto, Ontario Canada		Director		August 25, 2000	Senior Partner, Stikeman Elliott LLP, Barristers and Solicitors.
Shurniak, William Limerick, Saskatchewan Canada	Deputy Chairman and Director			August 25, 2000	Director and chairman of Northern Gas Networks Limited (a distributor of natural gas in Northern England) since 2005 and a director of Hutchison Whampoa Limited since 1984. Mr. Shurniak held the following


Name and
Municipality of
Residence	Office or Position		Director Since		Principal Occupation During Past 5 Years

					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 and CitiPower Pty Ltd. (a utility company) since 2002, a director of Envestra Limited (a natural gas distributor) since 2000, CrossCity Motorways Pty Ltd. (an infrastructure and transportation company) since 2002, and of Lane Cove Tunnel Company Pty Ltd. (an infrastructure and transportation company) since 2004. Mr. Shurniak holds an Honorary Doctor of Laws degree from the University of Saskatchewan and from The University of Western Ontario.
Sixt, Frank J. Hong Kong		Director		August 25, 2000	Group Finance Director of Hutchison Whampoa Limited since 1998 and Executive Director since 1991. Mr. Sixt has been the Chairman and Director of TOM Online Inc., and a Director of Hutchison Telecommunications International Limited since 2004. Mr. Sixt has held the following positions for more than five years: Chairman and Director of TOM Group Limited, Executive Director of Cheung Kong Infrastructure Holdings Limited and Hongkong Electric Holdings Limited and a Director of Cheung Kong (Holdings) Limited, Hutchison Whampoa Finance (CI) Limited, Hutchison Telecommunications (Australia) Limited, and Partner Communications Company Ltd. Mr. Sixt was also a director of VoiceStream Wireless Corp. from 2000 to 2001. Mr. Sixt holds a Master’s degree in Arts and a Bachelor’s degree in Civil Law and is a member of the Bar and of the Law Society of the Provinces of Quebec and Ontario, Canada.


Name and Municipality of
Residence	Office or Position	Principal Occupation During Past 5 Years

Ingram, Donald R. Calgary, Alberta	Senior Vice President, Midstream & Refined Products	Senior Vice President, Midstream and Refined Products of Husky since August 2000.

Girgulis, James D. Calgary, Alberta	Vice President, Legal & Corporate Secretary	Vice President, Legal & Corporate Secretary of Husky since August 2000.

The Board of Directors has an Audit Committee (as required by theBusiness Corporations Act(Alberta)) currently consisting of R.D. Fullerton (Chair), M.J.G. Glynn, T.C.Y. Hui, 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, 2006, the directors and officers of Husky, as a group, owned beneficially, directly or indirectly, or exercised control or direction over 397,108 common shares of Husky representing less than 1 percent 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 theBusiness 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, 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 theCompanies 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, T.C.Y. Hui 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.

T.C.Y. Hui — Mr. Hui is the President and Chief Executive Officer of Concord Pacific Group Inc. which three years ago was a public company.

M.J.G. Glynn — Mr. Glynn is currently the Chief Executive Officer of HSBC Bank USA and prior thereto served as Chief Executive Officer of HSBC Bank Canada.

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

	2005		2004

	($ thousands)
Audit fees		447		805
Audit-related fees		27		207
Tax fees		160		144
All other fees		476		45

		1,110		1,201

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 associated with various aspects of the Sarbanes-Oxley Act of 2002.

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 2005.

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 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 percent 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.

Up to and effective July 13, 2004, the Company leased its head office space located in Western Canadian Place in Calgary, Alberta from Western Canadian Place Ltd., which is indirectly controlled by the Company’s principal shareholders. The Company’s President & Chief Executive Officer is also a director and officer of Western Canadian Place Ltd. The Vice President, Corporate Administration of the Company’s subsidiary, Husky Oil Operations Limited, is also a director and officer of Western Canadian Place Ltd. The Company entered into an amended and restated lease for a term ending August 31, 2013 with Western Canadian Place Ltd. on commercial terms consistent with those for leases of comparable space in Class A office buildings in Calgary. Effective July 13, 2004, Western Canadian Place Ltd. sold Western Canadian Place to an unrelated party.

The Company has 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 – 8^th Avenue S.W., Calgary, Alberta. The Company was paid fees of $129,547.03 in 2005 for providing such management services.

TRANSFER AGENTS 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, 2005 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 percent of the Company’s securities of any class.

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 14, 2006, prepared in connection with the annual and special meeting of shareholders to be held on April 19, 2006.

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, 2005, contained in Husky’s 2005 Annual Report.

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

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

API		— American Petroleum Institute
COGEH		— Canadian Oil and Gas Evaluation Handbook
FASB		— Financial Accounting Standards Board
FPSO		— floating production, storage and offloading vessel
LLB		— Lloydminster Blend
NGL		— natural gas liquids
NYMEX		— New York Mercantile Exchange
OPEC		— Organization of Petroleum Exporting Countries
PSC		— production sharing contract
SAGD		— steam assisted gravity drainage
SEC		— Securities and Exchange Commission of the United States
SEDAR		— System for Electronic Document Analysis and Retrieval
WTI		— West Texas Intermediate crude oil

Barrel

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

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.

Coal Bed Methane

The primary energy source of natural gas is methane (CH(4)). Coal bed methane is methane found and recovered from the 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.

Degrees API 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.

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.

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 from there 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.

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 additional 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.

Recoverable Oil-in-place

The total original oil-in-place which can be expected to be recovered. This quantity is dependent upon recovery efficiency and the economics of operation.

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 with respect to the Canadian offshore or the Northwest Territories or Yukon 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 other provisions of the relevant legislation, the exclusive right to obtain a production 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, where 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			- 13.5

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.

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.

Straight Run

A term used to describe any refined product that emerges from the initial distillation of crude oil.

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.

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 applicable Canadian securities legislation, and 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 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, our construction plans for the Tucker in-situ oil sands project, Lloydminster Ethanol Plant and the Minnedosa Ethanol Plant; our plans to debottleneck 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 and the Northwest Territories; our South and east China Seas exploration drilling plans; our estimates of the productive capacity for White Rose, Tucker and Sunrise; our production forecasts; our plans to develop our Madura Stait PSC; and statements relating to declining production in the Western Canada Sedimentary Basin and increasing non-conventional production, 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

	•	such other risks, uncertainties and other factors described from time to time in Husky’s reports and filings with Canadian securities authorities and with the SEC.

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.

Schedule A

AIF

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 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 judgements 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 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.

	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 16, 2005

Document B

Form 40-F

CONSOLIDATED FINANCIAL STATEMENTS AND

AUDITORS’ REPORT TO SHAREHOLDERS

For the Year Ended December 31, 2005

MANAGEMENT’S REPORT

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

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 Annual Report 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. 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 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 6, 2006

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of Husky Energy Inc., as at December 31, 2005, 2004 and 2003 and the consolidated statements of earnings, retained earnings, and cash flows for each of the years in the three-year period ended December 31, 2005. 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 audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free 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, 2005, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2005 in accordance with Canadian generally accepted accounting principles.

/s/ KPMGllp

KPMGllp

Chartered Accountants

Calgary, Alberta, Canada

February 6, 2006

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 principles that has a material effect on the comparability of the Company’s financial statements, such as the change described in Note 11, Long-term debt — to the Company’s consolidated financial statements as at December 31, 2005, 2004 and 2003, and for each of the years in the three-year period ended December 31, 2005. Our report to the shareholders dated February 6, 2006 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/ KPMGllp

KPMGllp

Chartered Accountants

Calgary, Alberta, Canada

February 6, 2006

CONSOLIDATED BALANCE SHEETS


		As at December 31

		2005		2004		2003

		(millions of dollars)
ASSETS
Current assets
	Cash and cash equivalents	$	249	$	7	$	3
	Accounts receivable(note 4)		856		446		618
	Inventories(note 5)		471		274		198
	Prepaid expenses		40		52		33

			1,616		779		852
Property, plant and equipment, net(notes 1, 6)			13,959		12,193		10,862
Goodwill(note 7)			160		160		120
Other assets(note 11)			62		108		115

		$	15,797	$	13,240	$	11,949


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Bank operating loans(note 9)	$	—	$	49	$	71
	Accounts payable and accrued liabilities(note 10)		2,391		1,498		1,136
	Long-term debt due within one year(note 11)		274		56		259

			2,665		1,603		1,466
Long-term debt(note 11)			1,612		2,047		1,730
Other long-term liabilities(note 12)			730		632		519
Future income taxes(note 13)			3,270		2,758		2,621
Commitments and contingencies(note 14)
Shareholders’ equity
	Common shares(note 15)		3,523		3,506		3,457
	Retained earnings		3,997		2,694		2,156

			7,520		6,200		5,613

		$	15,797	$	13,240	$	11,949

On behalf of the Board:


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

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

2004 and 2003 amounts as restated (notes 3 and 11).

CONSOLIDATED STATEMENTS OF EARNINGS


		Year ended December 31

		2005			2004			2003

		(millions of dollars, except per
		share amounts)
Sales and operating revenues, net of royalties		$	10,245		$	8,440		$	7,658
Costs and expenses
	Cost of sales and operating expenses(note 12)		5,917			5,706			4,847
	Selling and administration expenses		138			135			119
	Stock-based compensation(note 15)		171			67			—
	Depletion, depreciation and amortization(notes 1, 6)		1,256			1,179			1,021
	Interest — net(note 11)		32			60			102
	Foreign exchange(note 11)		(31	)		(120	)		(282	)
	Other — net		(50	)		8			3

			7,433			7,035			5,810

Earnings before income taxes			2,812			1,405			1,848

Income taxes(note 13)
	Current		297			302			147
	Future		512			97			331

			809			399			478

Net earnings		$	2,003		$	1,006		$	1,370

Earnings per share(note 15)
	Basic	$	4.72		$	2.37		$	3.26
	Diluted	$	4.72		$	2.37		$	3.25

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS


		Year ended December 31

		2005			2004			2003

		(millions of dollars)
Beginning of year		$	2,694		$	2,156		$	1,366
Net earnings			2,003			1,006			1,370
Dividends on common shares(note 15)
	Ordinary		(276	)		(195	)		(160	)
	Special		(424	)		(229	)		(420	)
Stock-based compensation — retroactive adoption(note 15)			—			(44	)		—

End of year		$	3,997		$	2,694		$	2,156

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

2004 and 2003 amounts as restated (notes 3 and 11).

CONSOLIDATED STATEMENTS OF CASH FLOWS


			Year ended December 31

			2005			2004			2003

			(millions of dollars)
Operating activities
	Net earnings		$	2,003		$	1,006		$	1,370
	Items not affecting cash
		Accretion(note 12)		33			27			22
		Depletion, depreciation and amortization		1,256			1,179			1,021
		Future income taxes		512			97			331
		Foreign exchange		(37	)		(124	)		(309	)
		Other		18			12			(5	)
	Settlement of asset retirement obligations			(41	)		(40	)		(34	)
	Change in non-cash working capital(note 8)			(72	)		169			113

	Cash flow — operating activities			3,672			2,326			2,509

Financing activities
	Bank operating loans financing — net			(49	)		(22	)		71
	Long-term debt issue			3,235			2,200			598
	Long-term debt repayment			(3,401	)		(1,937	)		(971	)
	Settlement of cross currency swap			—			—			(32	)
	Debt issue costs			—			(5	)		—
	Proceeds from exercise of stock options			6			18			51
	Proceeds from monetization of financial instruments			39			8			44
	Dividends on common shares			(700	)		(424	)		(580	)
	Other			(1	)		—			—
	Change in non-cash working capital(note 8)			255			337			48

	Cash flow — financing activities			(616	)		175			(771	)

Available for investing				3,056			2,501			1,738

Investing activities
	Capital expenditures			(3,068	)		(2,349	)		(1,868	)
	Corporate acquisitions			—			(102	)		(809	)
	Asset sales			74			36			511
	Other			(31	)		(19	)		5
	Change in non-cash working capital(note 8)			211			(63	)		120

	Cash flow — investing activities			(2,814	)		(2,497	)		(2,041	)

Increase (decrease) in cash and cash equivalents				242			4			(303	)
Cash and cash equivalents at beginning of year				7			3			306

Cash and cash equivalents at end of year			$	249		$	7		$	3

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

2004 and 2003 amounts as restated (notes 3 and 11).

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1

Segmented Financial Information⁽¹⁾


		Upstream						Midstream

														Infrastructure
								Upgrading						and Marketing

		2005		2004		2003		2005		2004		2003		2005			2004		2003

Year ended December 31
Sales and operating revenues, net of royalties		$	4,367	$	3,120	$	3,186	$	1,488	$	1,058	$	1,013	$	7,383		$	6,126	$	4,946
Costs and expenses
	Operating, cost of sales, selling and general		1,050		967		873		1,018		884		901		7,084			5,914		4,747
	Depletion, depreciation and amortization		1,144		1,077		918		21		19		20		21			21		21
	Interest — net		—		—		—		—		—		—		—			—		—
	Foreign exchange		—		—		—		—		—		—		—			—		—

			2,194		2,044		1,791		1,039		903		921		7,105			5,935		4,768

Earnings (loss) before income taxes			2,173		1,076		1,395		449		155		92		278			191		178
Current income taxes			215		211		95		16		—		1		(14	)		31		27
Future income taxes			434		152		233		120		43		20		110			32		37

Net earnings (loss)		$	1,524	$	713	$	1,067	$	313	$	112	$	71	$	182		$	128	$	114

Capital employed — As at December 31		$	8,697	$	7,600	$	6,607	$	510	$	480	$	456	$	359		$	402	$	450

Property, plant and equipment — As at December 31
Cost
	Canada	$	18,512	$	16,023	$	13,831	$	1,205	$	1,084	$	1,023	$	683		$	647	$	622
	International		655		587		503		—		—		—		—			—		—

		$	19,167	$	16,610	$	14,334	$	1,205	$	1,084	$	1,023	$	683		$	647	$	622

Accumulated depletion, depreciation and amortization
	Canada	$	6,729	$	5,722	$	4,718	$	430	$	409	$	391	$	247		$	226	$	203
	International		354		311		252		—		—		—		—			—		—

		$	7,083	$	6,033	$	4,970	$	430	$	409	$	391	$	247		$	226	$	203

Net
	Canada	$	11,783	$	10,301	$	9,113	$	775	$	675	$	632	$	436		$	421	$	419
	International		301		276		251		—		—		—		—			—		—

		$	12,084	$	10,577	$	9,364	$	775	$	675	$	632	$	436		$	421	$	419

Capital expenditures — Year ended December 31 (3)		$	2,730	$	2,157	$	1,778	$	120	$	62	$	25	$	37		$	31	$	18

Total assets — As at December 31 (4)
	Canada	$	12,559	$	10,771	$	9,583	$	844	$	708	$	650	$	866		$	746	$	804
	International		328		275		264		—		—		—		—			—		—

		$	12,887	$	11,046	$	9,847	$	844	$	708	$	650	$	866		$	746	$	804


(1)	2004 and 2003 amounts as restated (notes 3 and 11).

(2)	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.

(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.


		Refined Products							Corporate and Eliminations (2)									Total

		2005			2004		2003		2005			2004			2003			2005			2004			2003

Year ended December 31
Sales and operating revenues, net of royalties		$	2,345		$	1,797	$	1,502	$	(5,338	)	$	(3,661	)	$	(2,989	)	$	10,245		$	8,440		$	7,658
Costs and expenses
	Operating, cost of sales, selling and general		2,169			1,694		1,426		(5,145	)		(3,543	)		(2,978	)		6,176			5,916			4,969
	Depletion, depreciation and amortization		47			38		26		23			24			36			1,256			1,179			1,021
	Interest — net		—			—		—		32			60			102			32			60			102
	Foreign exchange		—			—		—		(31	)		(120	)		(282	)		(31	)		(120	)		(282	)

			2,216			1,732		1,452		(5,121	)		(3,579	)		(3,122	)		7,433			7,035			5,810

Earnings (loss) before income taxes			129			65		50		(217	)		(82	)		133			2,812			1,405			1,848
Current income taxes			(3	)		11		9		83			49			15			297			302			147
Future income taxes			50			13		9		(202	)		(143	)		32			512			97			331

Net earnings (loss)		$	82		$	41	$	32	$	(98	)	$	12		$	86		$	2,003		$	1,006		$	1,370

Capital employed — As at December 31		$	475		$	354	$	315	$	(635	)	$	(484	)	$	(155	)	$	9,406		$	8,352		$	7,673

Property, plant and equipment — As at December 31
Cost
	Canada	$	1,063		$	878	$	773	$	257		$	232		$	205		$	21,720		$	18,864		$	16,454
	International		—			—		—		—			—			—			655			587			503

		$	1,063		$	878	$	773	$	257		$	232		$	205		$	22,375		$	19,451		$	16,957

Accumulated depletion, depreciation and amortization
	Canada	$	476		$	432	$	392	$	180		$	158		$	139		$	8,062		$	6,947		$	5,843
	International		—			—		—		—			—			—			354			311			252

		$	476		$	432	$	392	$	180		$	158		$	139		$	8,416		$	7,258		$	6,095

Net
	Canada	$	587		$	446	$	381	$	77		$	74		$	66		$	13,658		$	11,917		$	10,611
	International		—			—		—		—			—			—			301			276			251

		$	587		$	446	$	381	$	77		$	74		$	66		$	13,959		$	12,193		$	10,862

Capital expenditures — Year ended December 31 (3)		$	191		$	106	$	58	$	21		$	23		$	23		$	3,099		$	2,379		$	1,902

Total assets — As at December 31 (4)
	Canada	$	834		$	625	$	540	$	366		$	115		$	108		$	15,469		$	12,965		$	11,685
	International		—			—		—		—			—			—			328			275			264

		$	834		$	625	$	540	$	366		$	115		$	108		$	15,797		$	13,240		$	11,949

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 strategy and 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 and deposits with a maturity of less than three months at the time of purchase.


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 percent 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;

	•	the costs of unproved properties, less impairment; and

	•	the costs of major development projects, less impairment.


	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. Major 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 certain 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.

	When applicable, 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 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.

	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 other 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.


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 on a gross basis 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


	Effective January 1, 2004, 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.

	Effective June 1, 2004, the Company amended its stock option plan to 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.


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


	2005			2004			2003

Trade receivables	$	854		$	448		$	568
Investment tax credit		—			—			48
Allowance for doubtful accounts		(10	)		(10	)		(12	)
Other		12			8			14

	$	856		$	446		$	618

Sale of Accounts Receivable

As at December 31, 2005, 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, 2005, $350 million (2004 — $350 million; 2003 — $250 million) in outstanding accounts receivable had been sold under the program. The agreement includes a program fee. The average effective rate for 2005 was approximately 3.0 percent (2004 — 2.6 percent; 2003 — 2.8 percent).

The Company has retained the responsibility for servicing, administering and collecting accounts receivable sold. The servicing liability at December 31, 2005 was not significant.

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

Note 5

Inventories


	2005		2004		2003

Crude oil and refined petroleum products	$	241	$	159	$	115
Natural gas		207		100		69
Materials, supplies and other		23		15		14

	$	471	$	274	$	198

Note 6

Property, Plant and Equipment

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

General and administrative costs capitalized in 2005 were $61 million (2004 — $40 million; 2003 — $28 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:


	2005		2004		2003

Canada	$	2,317	$	2,399	$	1,814
International		127		129		54

	$	2,444	$	2,528	$	1,868

The prices used in the ceiling test evaluation of the Company’s crude oil and natural gas reserves at December 31, 2005 were:


											Price increase
Canada	2006		2007		2008		2009		2010		from 2010 to 2025

											(percent)
Crude oil($/bbl)	$	50.08	$	46.57	$	39.13	$	37.12	$	36.83		30
Natural gas($/mcf)		10.23		8.97		7.40		6.82		6.69		26

Note 7

Corporate Acquisitions

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.

Effective October 1, 2003, the Company acquired all of the issued and outstanding shares of Marathon Canada Limited and the Western Canadian assets of Marathon International Petroleum Canada, Ltd. (“Marathon Canada”) for cash consideration of U.S. $611 million (Cdn $831 million).

In conjunction with the above acquisition of Marathon Canada, the Company sold certain of the Marathon Canada oil and gas properties to a third party for cash consideration of U.S. $320 million (Cdn $431 million).

The results of Temple and Marathon Canada are included in the consolidated financial statements of the Company from their acquisition dates.

The allocation of the aggregate purchase price based on the estimated fair values of the net assets of Temple and Marathon Canada on their acquisition dates was as follows:


					Marathon
		Temple			Canada

Net assets acquired
	Working capital (1)	$	(17	)	$	(15	)
	Property, plant and equipment		138			1,008
	Goodwill (2)		20			140
	Asset retirement obligations		—			(38	)
	Future income taxes		(39	)		(264	)

		$	102		$	831


(1)	Working capital of Marathon Canada acquired included cash of $22 million.

(2)	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:


		2005			2004			2003

Decrease (increase) in non-cash working capital
	Accounts receivable	$	(410	)	$	209		$	(7	)
	Inventories		(197	)		(77	)		28
	Prepaid expenses		17			(12	)		(10	)
	Accounts payable and accrued liabilities		984			323			270

Change in non-cash working capital			394			443			281
Relating to:
	Financing activities		255			337			48
	Investing activities		211			(63	)		120

	Operating activities	$	(72	)	$	169		$	113

b) Other cash flow information:


	2005		2004		2003

Cash taxes paid	$	154	$	213	$	69
Cash interest paid	$	147	$	143	$	165

Note 9

Bank Operating Loans

At December 31, 2005, the Company had unsecuredshort-term borrowing lines of credit with banks totalling $195 million (2004 and 2003 — $195 million). As at December 31, 2005, $0.4 million (2004 — $49 million; 2003 — $71 million) had been used for bank operating loans and $18 million (2004 — $23 million; 2003 — $18 million) had been used for letters of credit. Interest payable is based on Bankers’ Acceptance, U.S. LIBOR or prime rates. During 2005, the weighted average interest rate onshort-term borrowings was approximately 3.9 percent (2004 — 3.4 percent; 2003 — 3.7 percent).

Note 10

Accounts Payable and Accrued Liabilities


	2005		2004		2003

Trade payables	$	88	$	110	$	58
Accrued liabilities		1,247		760		804
Dividend payable		530		280		42
Commodity contract settlements		—		50		8
Stock-based compensation		130		49		—
Current income taxes		164		119		117
Other		232		130		107

	$	2,391	$	1,498	$	1,136

Note 11

Long-term Debt


					Cdn $ Amount									U.S. $ Denominated

			Maturity		2005			2004			2003			2005		2004		2003

Long-term debt
		Syndicated credit facility			$	—		$	70		$	—		$	—	$	—	$	—
		Bilateral credit facilities				—			40			—			—		—		—
		7.125% notes		2006		175			181			194			150		150		150
		6.25% notes		2012		467			481			517			400		400		400
		7.55% debentures		2016		233			241			258			200		200		200
		6.15% notes		2019		350			361			—			300		300		—
		Private placement notes				—			18			41			—		15		32
		8.45% senior secured bonds		2006		99			140			188			85		117		145
		Medium-term notes				—			—			200			—		—		—
		Medium-term notes		2007		100			100			100			—		—		—
		Medium-term notes		2009		200			200			200			—		—		—
		8.90% capital securities		2028		262			271			291			225		225		225

	Total long-term debt					1,886			2,103			1,989		$	1,360	$	1,407	$	1,152

	Amount due within one year					(274	)		(56	)		(259	)

					$	1,612		$	2,047		$	1,730

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


	2005			2004			2003

Long-term debt	$	144		$	133		$	158
Short-term debt		4			3			2

		148			136			160
Amount capitalized		(114	)		(75	)		(52	)

		34			61			108
Interest income		(2	)		(1	)		(6	)

	$	32		$	60		$	102

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


	2005			2004			2003

Gain on translation of U.S. dollar denominated long-term debt	$	(51	)	$	(150	)	$	(382	)
Cross currency swaps		14			27			73
Other losses		6			3			27

	$	(31	)	$	(120	)	$	(282	)

As at December 31, 2005, other assets included $21 million (2004 — $24 million; 2003 — $22 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 athree-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

The 7.125 percent notes and the 7.55 percent debentures represent unsecured securities issued under a trust indenture dated October 31, 1996. These securities mature in 2006 and 2016, respectively. The 7.125 percent notes are not redeemable prior to maturity. Interest is payablesemi-annually.

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

On August 12, 2004, the Company filed a base shelf prospectus with securities regulatory authorities in Canada and the United States. The prospectus permits Husky to offer for sale, from time to time, up to U.S. $1 billion of debt securities during the25-month period from August 12, 2004. No notes have been issued under the base shelf prospectus as of December 31, 2005.

The 8.45 percent senior secured bonds represent securities issued by a subsidiary under a trust indenture dated July 20, 1999. These securities amortizesemi-annually. 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 oilfield located off the East Coast of Canada. Interest is payablesemi-annually. The Company has the option of delaying the repayment schedule by one year. The Company, through a wholly owned partnership, owns 12.51 percent of the Terra Nova oilfield and associated facilities. The repayment of the securities is contracted to be made solely from revenue from the Terra Nova oilfield. There is also a charge created by the partnership on its interest in the assets of the Terra Nova oilfield and associated facilities in favour of the security holders. Certain related financial obligations require collateral of letters of credit and/or cash equivalents. As at December 31, 2005, letters of credit totalling $41 million (2004 and 2003 — $54 million) were outstanding. The Company redeemed these bonds in full on February 1, 2006.

Themedium-term notes Series B represent unsecured securities issued under a trust indenture dated February 3, 1997 and the Series E notes represent unsecured securities issued under a trust indenture dated May 4, 1999. The amounts, rates and maturities are as follows:


Issue	Amount		Interest Rate		Maturity Date

Series B	$	100		6.85%	February 2007
Series E	$	200		6.95%	July 2009

Interest is payablesemi-annually on all series.

The 8.90 percent 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 percent interest is payablesemi-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 percent payablesemi-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 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.

Capital Securities Restatement

In November 2003, the Accounting Standards Board revised recommendations in CICA section 3860, “Financial Instruments — Disclosure and Presentation”, on the classification of obligations that must or could be settled with an entity’s own equity instruments. The new recommendations were effective January 1, 2005 and resulted in the Company’s capital securities being classified as liabilities instead of equity. The accrued return on the capital securities and the issue costs are classified outside of shareholders’ equity. The return on the capital securities is a charge to earnings. The revision was applied retroactively effective January 1, 2005 and resulted in the following changes to the Company’s financial statements:


			2004									2003

			As Reported			Change			As Restated			As Reported			Change			As Restated

Consolidated Balance Sheets
	Assets
		Other assets	$	106		$	2		$	108		$	112		$	3		$	115
	Liabilities and Shareholders’ Equity
		Accounts payable and accrued liabilities		1,489			9			1,498			1,126			10			1,136
		Long-term debt		1,776			271			2,047			1,439			291			1,730
		Capital securities and accrued return		278			(278	)		—			298			(298	)		—
Consolidated Statements of Earnings
		Interest — net	$	33		$	27		$	60		$	73		$	29		$	102
		Foreign exchange		(99	)		(21	)		(120	)		(215	)		(67	)		(282	)
		Future income taxes		103			(6	)		97			329			2			331
		Net earnings		1,006			—			1,006			1,334			36			1,370

Note 12

Other Long-term Liabilities


	2005		2004		2003

Asset retirement obligations	$	557	$	509	$	432
Cross currency swaps		40		68		41
Interest rate swaps		42		18		26
Employee future benefits		27		23		20
Stock-based compensation		46		14		—
Other		18		—		—

	$	730	$	632	$	519

Asset Retirement Obligations

At December 31, 2005, the estimated total undiscounted inflation adjusted amount required to settle the asset retirement obligations was $3.3 billion. These obligations will be settled at the end of the useful lives of the underlying assets, which currently extend up to 50 years into the future. This amount has been discounted using credit adjusted risk free rates ranging from 6.2 percent to 6.4 percent.

Changes to the asset retirement obligations were as follows:


	2005			2004			2003

Asset retirement obligations at beginning of year	$	509		$	432		$	286
Liabilities incurred		63			13			158
Liabilities disposed		(7	)		—			—
Liabilities settled		(41	)		(40	)		(34	)
Revisions		—			77			—
Accretion		33			27			22

Asset retirement obligations at end of year	$	557		$	509		$	432

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:


		2005			2004			2003

Earnings before income taxes
	Canadian	$	2,553		$	1,165		$	1,625
	Foreign jurisdictions		259			240			223

			2,812			1,405			1,848
Statutory income tax rate(percent)			38.4			39.3			40.2

Expected income tax			1,080			552			743
Effect on income tax of:
	Royalties, lease rentals and mineral taxes payable to the crown		105			153			175
	Resource allowance on Canadian production income		(133	)		(156	)		(183	)
	Rate benefit on partnership earnings		(69	)		(42	)		(23	)
	Change in statutory tax rate		(4	)		(40	)		(161	)
	Non-deductible capital taxes		15			20			22
	Capital gains and losses		(140	)		(23	)		(58	)
	Foreign jurisdictions		(14	)		(13	)		(16	)
	Other — net		(31	)		(52	)		(21	)

Income tax expense		$	809		$	399		$	478

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


		2005		2004		2003

Future tax liabilities
	Property, plant and equipment	$	3,487	$	2,949	$	2,826
	Foreign exchange gains taxable on realization		60		56		32
	Other temporary differences		2		5		2

			3,549		3,010		2,860
Future tax assets
	Asset retirement obligations		195		180		160
	Loss carry forwards		—		11		2
	Provincial royalty rebates		7		14		52
	Other temporary differences		77		47		25

			279		252		239

		$	3,270	$	2,758	$	2,621

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 2005, the Company capitalized $68 million (2004 — $27 million; 2003 — $10 million) of payments under this arrangement.

At December 31, 2005, the Company had commitments for non-cancellable operating leases and other long-term agreements that require the following minimum future payments:


											After
	2006		2007		2008		2009		2010		2010		Total

Operating leases	$	81	$	82	$	76	$	68	$	63	$	132	$	502
Firm transportation agreements		169		133		110		68		50		149		679
Unconditional purchase obligations		616		656		565		127		44		9		2,017
Lease rentals and exploration work agreements		50		54		44		44		81		154		427
Engineering and construction commitments		365		154		12		—		—		—		531

	$	1,281	$	1,079	$	807	$	307	$	238	$	444	$	4,156

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, 2002			417,873,601	$	3,406
	Options and warrants exercised		4,302,141		51

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

Stock Options

At December 31, 2005, 20.4 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. Similar downward adjustments of $0.48 in 2004 and $0.82 in 2003 were made to the exercise price of all outstanding stock options as a result of a special dividend declared in each of those years.

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


							Weighted
					Weighted		Average
		Number of			Average		Contractual		Options
		Options			Exercise Prices		Life		Exercisable

		(thousands)					(years)		(thousands)
December 31, 2002			7,920		$	13.91		3		4,822
	Granted		591		$	19.17		5
	Exercised for common shares		(3,789	)	$	13.45		2
	Forfeited		(125	)	$	14.71		2

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


	As at December 31, 2005

	Outstanding Options						Options Exercisable

			Weighted		Weighted				Weighted
			Average		Average				Average
	Number of		Exercise		Contractual		Number of		Exercise
Range of Exercise Price	Options		Prices		Life		Options		Prices

	(thousands)				(years)		(thousands)
$13.67 — $14.99		187	$	14.32		2		144	$	14.17
$15.00 — $22.99		234	$	19.44		3		116	$	19.98
$23.00 — $23.99		5,977	$	23.83		3		1,252	$	23.83
$24.00 — $39.99		392	$	32.11		4		21	$	30.60
$40.00 — $55.14		495	$	52.12		5		—	$	—

		7,285	$	25.81		3		1,533	$	22.72

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. During 2005, 16,000 warrants were exercised (2004 — 113,600; 2003 — 276,500). As at December 31, 2005, there were no Renaissance replacement options or warrants outstanding.

Earnings per Common Share


		2005		2004		2003

Net earnings		$	2,003	$	1,006	$	1,370

Weighted average number of common shares outstanding
	Basic(millions)		424.0		423.4		419.5
Effect of dilutive stock options and warrants			—		0.9		2.0

Weighted average number of common shares outstanding
	Diluted(millions)		424.0		424.3		421.5

Earnings per share
	Basic	$	4.72	$	2.37	$	3.26
	Diluted	$	4.72	$	2.37	$	3.25

Stock-based Compensation

As described in note 3 m), 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. If the Company had applied the fair value method retroactively with restatement of prior periods for all options granted, the Company’s net earnings and earnings per share for the year ended December 31, 2003 would have been as follows:


		2003

Compensation cost — all options granted (1)		$	14
Net earnings available to common shareholders
	As reported	$	1,370
	As restated	$	1,356
Weighted average number of common shares outstanding(millions)
	Basic		419.5
	Diluted		421.5
Basic earnings per share
	As reported	$	3.26
	As restated	$	3.23
Diluted earnings per share
	As reported	$	3.25
	As restated	$	3.22


(1)	Includes options modified.

As described in note 3 m), 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		2003

Weighted average fair value per option	$	5.67	$	4.00
Risk-free interest rate(percent)		3.1		3.9
Volatility(percent)		21		23
Expected life(years)		5		5
Expected annual dividend per share	$	0.44	$	0.36

As a result of the downward adjustment of $0.82 to the exercise price of all outstanding options effective September 3, 2003, the fair values of all common share options granted prior to that date were revalued on September 3, 2003 using the Black-Scholes option-pricing model. The weighted average fair value of outstanding stock options as at September 3, 2003 and the assumptions used are noted below:


Weighted average fair value per option	$	7.14
Risk-free interest rate(percent)		2.8
Volatility(percent)		20
Expected life(years)		2.3
Expected annual dividend per share	$	0.40

Dividends

During 2005, the Company declared dividends of $1.65 per common share (2004 — $1.00 per common share; 2003 — $1.38 per common share), including a special dividend of $1.00 per common share (2004 — $0.54 per common share; 2003 — $1.00 per common share).

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.

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


	2005		2004		2003

Discount rate(percent)		5.8		6.0		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		8.0		8.0

The discount rate used at the end of 2005 to determine the accrued benefit obligation was 5.0 percent.

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 2005 was 7.5 percent.

The average health care cost trend used was eight percent, which is reduced by 0.50 percent until 2009. The average dental care cost trend used was four percent, which remains constant.

Defined Benefit Pension Plan

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

Benefit Obligation


	2005			2004			2003

Benefit obligation, beginning of year	$	124		$	118		$	108
Current service cost		2			2			2
Interest cost		7			7			7
Benefits paid		(6	)		(6	)		(6	)
Actuarial losses		11			3			7

Benefit obligation, end of year	$	138		$	124		$	118

Fair Value of Plan Assets


	2005			2004			2003

Fair value of plan assets, beginning of year	$	96		$	85		$	77
Contributions		11			10			8
Benefits paid		(6	)		(6	)		(6	)
Expected return on plan assets		7			7			6
Gain on plan assets		—			1			2
Foreign exchange losses		—			(1	)		(2	)

Fair value of plan assets, end of year	$	108		$	96		$	85

Funded Status of Plan


	2005			2004			2003

Fair value of plan assets	$	108		$	96		$	85
Benefit obligation		(138	)		(124	)		(118	)

Excess obligation		(30	)		(28	)		(33	)
Unrecognized past service costs		1			1			1
Unrecognized losses		40			32			32

Accrued benefit asset	$	11		$	5		$	—

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 date of the last actuarial valuation for the Company was January 1, 2005.

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


	2005			2004			2003

U.S. common equities		—	%		15	%		15	%
Canadian common equities		29			25			28
International equity mutual funds		28			11			10
Canadian equity mutual funds		—			—			2
Canadian government bonds		18			25			29
Canadian corporate bonds		3			16			12
Canadian fixed income mutual funds		20			—			—
Cash and receivables		2			8			4

Total		100	%		100	%		100	%

During 2005, Husky contributed $11 million to the defined benefit pension plan assets, $9 million of which was in respect of additional contributions as a result of the plan’s deficiency. Husky currently plans to contribute $10 million in 2006.

The Company amortizes the portion of the unrecognized actuarial gains or losses that exceed 10 percent 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 percent 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 status of the post-retirement health and dental care plan at December 31 was as follows:

Benefit Obligation


	2005		2004			2003

Benefit obligation, beginning of year	$	25	$	23		$	21
Current service cost		2		2			2
Interest cost		1		1			1
Benefits paid		—		(1	)		(1	)
Actuarial losses		5		—			—

Benefit obligation, end of year	$	33	$	25		$	23

Funded Status of Plan


	2005			2004			2003

Benefit obligation	$	(33	)	$	(25	)	$	(23	)
Unrecognized losses		6			2			3

Accrued benefit liability	$	(27	)	$	(23	)	$	(20	)

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	$	—
Effect on post-retirement benefit obligation	$	6	$	(5	)

Pension Expense and Post-retirement Health and Dental Care Expense

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

Pension Expense


		2005			2004			2003

Defined benefit pension plan
	Employer current service cost	$	2		$	2		$	2
	Interest cost		7			7			7
	Expected return on plan assets		(7	)		(7	)		(6	)
	Amortization of net actuarial losses		3			2			2

			5			4			5
Defined contribution pension plan			14			12			11

Total expense		$	19		$	16		$	16

Post-retirement Health and Dental Care Expense


	2005		2004		2003

Employer current service cost	$	2	$	2	$	2
Interest cost		1		1		1

Total expense	$	3	$	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

2006	$	7	$	1
2007		7		1
2008		8		1
2009		8		1
2010		8		1
2011 - 2015		46		7

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 (2003 — $17 million).

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:


	2005				2004				2003

	Carrying		Fair		Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value		Value		Value

Long-term debt	$	1,886	$	1,995	$	2,103	$	2,296	$	1,989	$	2,209

Unrecognized Gains (Losses) on Derivative Instruments


		2005			2004			2003

Commodity price risk management
	Natural gas	$	—		$	(9	)	$	(8	)
	Crude oil		—			—			(109	)
	Power consumption		—			(1	)		2
Interest rate risk management
	Interest rate swaps		7			52			31
Foreign currency risk management
	Foreign exchange contracts		(32	)		(30	)		(19	)
	Foreign exchange forwards		—			—			15

Commodity Price Risk Management


	*Natural Gas Production*

During 2005 the impact of hedging was a loss of $17 million (2004 — loss of $1 million; 2003 — gain of $16 million).


	*Crude Oil Production*

The Company did not have a hedge program in 2005. The impact of hedging in 2004 and 2003 was a loss of $560 million and $36 million, respectively.


	*Power Consumption*

The impact of the 2005 hedge program was a gain of $4 million (2004 — gain of $3 million).


	*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, 2005, the Company had the following offsetting physical purchase and sale contracts:


				Unrecognized
	Volumes			Gain (Loss)

	(mmcf)
Physical purchase contracts		35,261		$	29
Physical sale contracts		(35,261	)	$	(28	)

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, 2005, 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

During 2005 the Company realized a gain of $13 million (2004 — gain of $22 million; 2003 — gain of $17 million) from interest rate risk management activities.

In 2005 and 2003, the Company unwound interest rate swaps for proceeds of $37 million and $44 million, respectively. 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.

At December 31, 2005, the Company had the following cross currency debt swaps:


			Canadian
Debt	Swap Amount		Equivalent		Swap Maturity		Interest Rate

							(percent)
7.125% notes	U.S. $	150	$	218		November 15, 2006		8.74
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 2005 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.

During 2005 the Company recognized a gain of $1 million (2004 — loss of $13 million; 2003 — loss of $56 million) from foreign currency risk management activities.

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 percent of total sales and operating revenues during 2005.

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


			2005			2004			2003

Net earnings under Canadian GAAP (1)			$	2,003		$	1,006		$	1,370
Adjustments:
Full cost accounting (a)				66			37			80
	Related income taxes			(23	)		(13	)		(29	)
Derivatives and hedging (b)				—			—			(1	)
	Related income taxes			—			—			1
Energy trading contracts (c)				—			(1	)		(15	)
	Related income taxes			—			—			6
Stock-based compensation (e)				—			2			(46	)

Earnings before cumulative effect of change in accounting principle under U.S. GAAP				2,046			1,031			1,366
Cumulative effect of change in accounting principle, net of tax (d)				—			—			9

Net earnings under U.S. GAAP			$	2,046		$	1,031		$	1,375

Weighted average number of common shares outstanding under U.S. GAAP(millions)
		Basic		424.0			423.4			419.5
		Diluted		424.0			424.3			421.5
Earnings per share before cumulative effect of change in accounting principle under U.S. GAAP
		Basic	$	4.83		$	2.44		$	3.26
		Diluted	$	4.83		$	2.43		$	3.24
Earnings per share under U.S. GAAP
		Basic	$	4.83		$	2.44		$	3.28
		Diluted	$	4.83		$	2.43		$	3.26


(1)	2004 and 2003 amounts as restated (notes 3 and 11).

Condensed Consolidated Balance Sheets


		2005					2004					2003

		Canadian		U.S.			Canadian		U.S.			Canadian		U.S.
		GAAP		GAAP			GAAP (1)		GAAP			GAAP (1)		GAAP

Current assets (b)(c)		$	1,616	$	1,672		$	779	$	837		$	852	$	911
Property, plant and equipment, net (a)			13,959		13,465			12,193		11,633			10,862		10,264
Other assets (i)			222		223			268		269			235		236

		$	15,797	$	15,360		$	13,240	$	12,739		$	11,949	$	11,411

Current liabilities (b)(c)(i)		$	2,665	$	2,766		$	1,603	$	1,656		$	1,466	$	1,628
Long-term debt (b)			1,612		1,670			2,047		2,124			1,730		1,794
Other long-term liabilities (b)			730		688			632		614			519		493
Future income taxes (a)(b)(c)(d)(i)			3,270		3,089			2,758		2,555			2,621		2,372
Share capital (e)(f)(g)			3,523		3,757			3,506		3,740			3,457		3,737
Retained earnings			3,997		3,431			2,694		2,085			2,156		1,478
Accumulated other comprehensive income
	Cash flow hedges, net of tax (b)		—		(21	)		—		(20	)		—		(76	)
	Minimum pension liability, net of tax (i)		—		(20	)		—		(15	)		—		(15	)

		$	15,797	$	15,360		$	13,240	$	12,739		$	11,949	$	11,411


(1)	2004 and 2003 amounts as restated (notes 3 and 11).

Condensed Consolidated Statements of Retained Earnings and Accumulated Other Comprehensive Income


	2005						2004						2003

	Canadian			U.S.			Canadian			U.S.			Canadian			U.S.
	GAAP			GAAP			GAAP (1)			GAAP			GAAP (1)			GAAP

Retained earnings, beginning of year	$	2,694		$	2,085		$	2,156		$	1,478		$	1,366		$	683
Net earnings		2,003			2,046			1,006			1,031			1,370			1,375
Dividends on common shares		(700	)		(700	)		(424	)		(424	)		(580	)		(580	)
Stock-based compensation — retroactive adoption (e)		—			—			(44	)		—			—			—

Retained earnings, end of year	$	3,997		$	3,431		$	2,694		$	2,085		$	2,156		$	1,478

Accumulated other comprehensive income, beginning of year	$	—		$	(35	)	$	—		$	(91	)	$	—		$	(17	)
Cash flow hedges, net of tax (b)		—			(1	)		—			56			—			(69	)
Minimum pension liability, net of tax (i)		—			(5	)		—			—			—			(5	)

Accumulated other comprehensive income, end of year	$	—		$	(41	)	$	—		$	(35	)	$	—		$	(91	)


(1)	2004 and 2003 amounts as restated (notes 3 and 11).

Condensed Consolidated Statements of Earnings and Comprehensive Income


	2005				2004					2003

	Canadian		U.S.		Canadian		U.S.			Canadian		U.S.
	GAAP		GAAP		GAAP (1)		GAAP			GAAP (1)		GAAP

Sales and operating revenues (b)(c)(h)	$	10,245	$	8,445	$	8,440	$	7,038		$	7,658	$	6,823
Costs and expenses (b)(c)(e)(h)		6,112		4,312		5,769		4,366			4,665		3,892
Accretion expense		33		33		27		27			22		22
Depletion, depreciation and amortization (a)		1,256		1,190		1,179		1,142			1,021		941
Interest — net		32		32		60		60			102		102

Earnings before income taxes		2,812		2,878		1,405		1,443			1,848		1,866
Income taxes (a)(b)(c)		809		832		399		412			478		500

Earnings before cumulative effect of change in accounting principle		2,003		2,046		1,006		1,031			1,370		1,366
Cumulative effect of change in accounting principle, net of tax (d)		—		—		—		—			—		9

Net earnings		2,003		2,046		1,006		1,031			1,370		1,375
Other comprehensive income (b)(i)		—		6		—		(56	)		—		74

Comprehensive income	$	2,003	$	2,052	$	1,006	$	975		$	1,370	$	1,449


(1)	2004 and 2003 amounts as restated (notes 3 and 11).

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 percent. 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 $62 million (2004 — $76 million; 2003 — $80 million), net of tax of $21 million (2004 — $27 million; 2003 — $30 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 taxes 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 and are included in the reserve base resulting in a reduction to depletion expense for U.S. GAAP of $4 million, net of tax of $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 FAS 133, “Accounting for Derivative Instruments and Hedging Activities”. At December 31, 2005, the Company recorded additional assets and liabilities for U.S. GAAP purposes of $7 million (2004 — $52 million; 2003 — $52 million) and $39 million (2004 — $93 million; 2003 — $172 million), respectively, for the fair values of derivative financial instruments. The Company also recorded a gain of less than $1 million, net of tax (2004 — loss of less than $1 million; 2003 — loss of $2 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 increased by $1 million net of tax (2004 — decreased by $51 million; 2003 — increased by $69 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 2005. In 2004, the Company unwound its long-dated foreign exchange forwards. The unrealized gain of $5 million, net of tax was deferred in other comprehensive income and recognized in 2005 when the underlying transactions 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. In prior years, the gains net of tax (2003 — $1 million), on foreign currency derivatives and natural gas basis swaps that did not qualify for hedge accounting under FAS 133 were included in income for U.S. GAAP purposes.

(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 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, 2005 the Company recorded additional assets and liabilities of $49 million (2004 — $4 million; 2003 — $7 million) and $48 million (2004 — $3 million; 2003 — $5 million), respectively, and included the resulting unrealized gain, net of tax of less than $1 million (2004 — loss of $1 million; 2003 — loss of $9 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)	In 2003, the Company adopted FAS 143, “Accounting for Asset Retirement Obligations”, which requires the fair value of a liability for an asset retirement obligation to be recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related tangible long-lived asset. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and normal use of the asset. The liability is accreted at the end of each period through charges to accretion expense. The change was effective January 1, 2003, and the related cumulative effect of change in accounting principle to net earnings to December 31, 2002 was an increase of $20 million, net of tax of $11 million or $0.02 per share (diluted). Effective January 1, 2004, under Canadian GAAP the Company adopted CICA section 3110, “Asset Retirement Obligations”, which is substantially the same as the recommendations in FAS 143. CICA section 3110 was adopted retroactively with restatement. The application of asset retirement obligations did not have a material impact on the Company’s depletion, depreciation and amortization rate. There was no impact on the Company’s cash flow as a result of adopting asset retirement obligations.

(e)	On September 3, 2003, the Company modified the exercise price of all outstanding options. Under U.S. GAAP these options are required to be accounted for using variable accounting where the in-the-money portion of the vested stock options outstanding is adjusted through the statement of earnings as compensation expense over the remaining vesting period.

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”. As a result, the compensation expense of $46 million for the year ended December 31, 2003 was reversed through earnings and a compensation expense of $44 million was recognized for the fair value of all stock options.


(f)	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.

(g)	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.

(h)	Under U.S. GAAP, transportation costs are included in cost of sales. Effective January 1, 2004, for Canadian purposes, certain transportation costs that were previously netted against revenue are now being recorded as cost of sales on a prospective basis. Transportation costs for 2003 were $112 million.

(i)	The Company amortizes the portion of the unrecognized gains or losses that exceed 10 percent 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. Under U.S. GAAP, an additional minimum liability is recognized if the unfunded accumulated benefit obligation exceeds the unfunded pension cost already recognized. If an additional minimum liability is recognized, an amount equal to the unrecognized prior service cost is recognized as an intangible asset and any excess is reported in other comprehensive income. At December 31, 2005, the additional minimum liability was increased by $6 million (2004 — decrease of $1 million; 2003 — increase of $6 million) with a decrease to other comprehensive income of $5 million (2004 — decrease of less than $1 million; 2003 — decrease of $5 million), net of tax.

Additional U.S. GAAP Disclosures

Corporate Acquisitions

As described in note 7, Corporate Acquisitions, the Company purchased all of the outstanding shares of Temple Exploration Inc. and Marathon Canada Limited. The Company also purchased the Western Canadian assets of Marathon International Petroleum Canada, Ltd. These transactions 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

FAS 123 establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. As permitted by FAS 123, Husky has elected to follow the intrinsic value method of accounting for stock-based compensation arrangements, as provided for in Accounting Principles Board (“APB”) Opinion 25. Since all options were granted with exercise prices equal to the market price, no compensation expense has been charged to income at the time of the option grants. On September 3, 2003, the Company modified the exercise price of all outstanding options, resulting in the use of variable accounting for these modified stock options. The table below provides pro forma amounts prior to the application of variable accounting which required recognition of compensation expense on September 3, 2003. Effective January 1, 2004, the Company adopted CICA section 3870, which requires the Company to record a compensation expense over the vesting period of the options based on the fair value of the options granted. CICA section 3870 is consistent with the recommendations in FAS 123. Had compensation cost for Husky’s stock options been determined based on the fair market value at the grant dates of the awards, and amortized on a straight-line basis over the vesting period, consistent with methodology prescribed by FAS 123, Husky’s net earnings and earnings per share for the year ended December 31, 2003 would have been the pro forma amounts indicated below:


	2003

	As Reported		Pro Forma

Net earnings under U.S. GAAP	$	1,375	$	1,407
Earnings per share — Basic	$	3.28	$	3.35
— Diluted	$	3.26	$	3.34

The fair values of all common share options granted were estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of options granted during 2003 and the assumptions used in their determination are the same as described in note 15.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued FAS 123(R), “Share-based Payment”, which replaces FAS 123 and supersedes 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 will be measured at fair value using an option pricing model. Under Canadian GAAP, the liability will be 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) is effective for the first quarter of 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:


	2005		2004		2003

Depletion, depreciation and amortization per boe	$	9.38	$	8.76	$	7.35

Accounting for Inventory Costs

In November 2004, the FASB issued FAS 151, 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 Company does not believe that the application of FAS 151 will have an impact on the financial statements.

Accounting for Exchanges of Nonmonetary Assets

In December 2004, the FASB issued FAS 153, 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 Company does not believe that the application of FAS 153 will have an impact on the financial statements.

Accounting Changes and Error Corrections

In May 2005, the FASB issued FAS 154, 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.

Document C

Form 40-F

MANAGEMENT’S DISCUSSION AND ANALYSIS

February 16, 2006

TABLE OF CONTENTS


		Page

Introduction			2
1. Vision			3
	Core Businesses		3
	Operating and Financial Strategies		3
	Capability to Deliver Results		4
	Key Performance Drivers and Measures		5
2. Financial and Operational Overview			7
	Overview		7
	Selected Annual Information		8
	Selected Quarterly Information		8
	The Business Environment in 2005		9
	Sensitivities by Segment for 2005 Results		10
3. Results of Operations			11
	Upstream		11
	Midstream		19
	Refined Products		22
	Corporate		23
4. Liquidity and Capital Resources			25
	Summary of Cash Flow		25
	Financial Position		26
	Cash Requirements		28
	Off-balance Sheet Arrangements		29
	Transactions with Related Parties and Major Customers		29
	Financial Risk and Risk Management		30
	Outstanding Share Data		31
5. 2006 Outlook			31
	General Economy		31
	Upstream		31
	Midstream		32
	Refined Products		32
6. Application of Critical Accounting Estimates			32
	Full Cost Accounting for Oil and Gas Activities		33
	Depletion Expense		33
	Withheld Costs		33
	Full Cost Accounting		33
	Impairment of Long-lived Assets		33
	Fair Value of Derivative Instruments		33
	Asset Retirement Obligations		34
	Legal, Environmental Remediation and Other Contingent Matters		34
	Income Tax Accounting		34
	Business Combinations		35
	Goodwill		35
7. New Accounting Standards			35
	Liabilities and Equity		35
	Non-monetary Transactions		35
8. Pending Accounting Standards			35
9. Summary of Variances for 2004 compared with 2003			36
10. Forward-looking Statements			37
11. Oil and Gas Reserve Reporting			38
12. Non-GAAP Measures			38
13. Evaluation of Disclosure Controls and Procedures			39

INTRODUCTION

Intention of Management’s Discussion and Analysis (“MD&A”)

This MD&A is intended to provide a wide range of readers with information explaining Husky’s financial and operational performance against performance in prior periods and expected or planned performance. It also describes our ability to deliver expected results from our current plans.

Review by the Audit Committee

This MD&A was reviewed by the Audit Committee and approved by Husky’s Board of Directors on February 16, 2006. Any events subsequent to that date could conceivably materially alter the veracity and usefulness of the information contained in this document. Husky may, but is not obligated, to provide updates to its forward-looking statements in its subsequent interim MD&A filings or in subsequent news releases filed or furnished to regulatory agencies.

Additional Husky Documents that should be considered by the Reader

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 2005, 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 Securities and Exchange Commission (“SEC”), the U.S. regulatory agency. These documents are available at www.sedar.com and www.sec.gov, respectively.

Use of Pronouns and Other Terms Denoting Husky

In this MD&A the pronouns “we”, “our” and “us” and the term “Husky” denote the corporate entity, Husky Energy Inc. and its subsidiaries on a consolidated basis.

Standard Comparisons in this Document

Unless otherwise indicated, the discussions in this MD&A with respect to results for the year ended December 31, 2005 are compared with results for the year ended December 31, 2004 and, similarly discussions with respect to Husky’s financial position as at December 31, 2005 are compared with its financial position at December 31, 2004.

Reclassifications and Materiality for Disclosures

Certain prior year amounts have been reclassified to conform with 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

The Consolidated Financial Statements and all financial information included and incorporated by reference in this MD&A have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). The effect of significant differences between Canadian and United States accounting principles is disclosed in Note 19 of the Consolidated Financial Statements.

All dollar amounts are in millions of Canadian dollars, unless otherwise indicated. Unless otherwise indicated, all production volumes quoted are gross, which represent Husky’s working interest share before royalties. Prices quoted include or exclude the effect of hedging as indicated. Crude oil has been classified as the following: light crude oil has an API gravity of 30 degrees or more; medium crude oil has an API gravity of 21 degrees or more and less than 30 degrees; heavy crude oil has an API gravity of less than 21 degrees.

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.

Forward-looking Statements

This MD&A contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See Section 10. “Forward-looking Statements” for additional information.

1. VISION

CORE BUSINESSES

Our operations are organized into three major business segments:

Upstream

The upstream business includes the exploration for and development and production of crude oil, natural gas, natural gas liquids (“NGL”) and sulphur. Our upstream operations are primarily located throughout the Western Canada Sedimentary Basin in the provinces of Alberta, Saskatchewan and British Columbia. We also have significant operations off the East Coast of Canada in the Jeanne d’Arc Basin and we are currently evaluating development potential in the Mackenzie Valley in the Northwest Territories. Outside of Canada, we are involved in China including exploration in the South China Sea near Hainan Island and the East China Sea east of Shanghai and production at Wenchang in the South China Sea. In Indonesia, we are in the early stages of developing a natural gas and NGL property in the Madura Strait offshore Java.

Midstream

The midstream business includes the operation of a heavy oil upgrader with a capacity in excess of 60,000 barrels of synthetic crude oil per day located at Lloydminster, Saskatchewan, pipeline systems with combined capacity in excess of 500,000 barrels per day in the heavy oil producing regions between Cold Lake, Alberta south through Lloydminster to Hardisty, Alberta, crude oil and natural gas storage facilities, cogeneration and commodity marketing activities.

Refined Products

The refined products business includes the operation of a recently upgraded 11,000 barrel per day full slate refinery in Prince George, British Columbia, a 25,000 barrel per day asphalt refinery in Lloydminster, Alberta and a marketing and distribution system with locations from the West Coast of Canada to the eastern border of Ontario. We are also currently at various stages of constructing ethanol plants at Lloydminster, Saskatchewan and Minnedosa, Manitoba.

OPERATING AND FINANCIAL STRATEGIES

Strategic Objective and Measures

Our mission is “to maximize returns to our shareholders in a socially responsible manner.” Our strategy is to maintain financial discipline while optimizing our foundation asset base in the Western Canada Sedimentary Basin and expanding into large scale sustainable areas including oil sands, Canada’s East Coast and northern basins and high potential basins offshore Southeast Asia.

Strategic Plans

Our ultimate success in achieving our 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.

Financial Objective and Strategies


	•	maintain debt to capitalization ratio of less than 40 percent; and

	•	maintain debt to cash flow from operations of less than two times.

Upstream Strategies


	•	increase production through plant and facility optimization, increased property development, property consolidation and decreased tie-in time;

	•	increase reserves through capital allocation to high-impact areas in the foothills, deep basin and northern plains;

	•	continue exploration on our large land position in the Jeanne d’Arc Basin and delineation of White Rose satellite prospects;


	•	continue exploration in China and development of Wenchang satellite prospects;

	•	development of Indonesian natural gas and NGL property in the Madura Strait and exploration in the area; and

	•	continue development of oil sands resources starting with first oil at Tucker in 2006.

Midstream Strategies


	•	debottleneck and enhance performance of upgrader;

	•	expand upgrader;

	•	expand pipeline and facilities;

	•	expand natural gas storage capacity; and

	•	centralize sulphur handling facilities.

Refined Products Strategies


	•	continue to enhance retail outlets through automation, remodeling and expanded services;

	•	expand commercial marketing through application of our cardlock system;

	•	expand ethanol production capacity;

	•	continue to expand manufacture and use of ethanol as an oxygenate in gasoline;

	•	optimize throughput per outlet;

	•	optimize asphalt product mix by seeking customers with high quality requirements;

	•	expand asphalt marketing reach and distribution network; and

	•	continue to debottleneck Lloydminster asphalt refinery and improve operational performance.

We believe that the execution of our current strategic plans as they relate to our current portfolio of assets will attain our mission but we will continue to purse acquisitions and strategic alliances. Our financial objective and strategies are intended to maintain our financial condition to facilitate corporate acquisitions of a size and type that will leverage our core portfolio of assets.

CAPABILITY TO DELIVER RESULTS

We have and will maintain the financial capacity and flexibility to undertake our strategic plans including major growth projects. We have a significant resource in our workforce and will maintain it through increasing investment in training, mentoring, succession and retention programs. Our capital investments must meet an established criterion of providing a return on capital employed.

Upstream Strengths and Challenges

Our upstream business strengths consist primarily of:


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

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

	•	longstanding experience in the heavy oil producing areas in the Lloydminster region of Alberta and Saskatchewan combined with an extensive infrastructure;

	•	substantial long-term growth potential in the oil sands regions of Alberta;

	•	well established exploration capability in the Jeanne d’Arc Basin off the East Coast of Canada now combined with development experience with the White Rose oilfield;

	•	well established relationships in Southeast Asia and readily transferable exploitation expertise.

Our upstream business will likely be challenged by the following:


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

	•	labour market skills shortages;


	•	highly competitive environment for materials and services required to undertake large projects;

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

	•	increasing resistance from opposing special interest groups; and

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

Midstream Strengths and Challenges

Our midstream business strengths consist primarily of:


	•	modern reliable heavy oil upgrading facility located in the Lloydminster heavy oil producing region capable of expansion;

	•	reliable heavy oil pipeline systems well integrated in the Lloydminster producing region with expansion opportunities; and

	•	large scale marketer capable of operating as a market balancer, serving the needs of both customer and supplier.

Our midstream business will likely be challenged by the following:


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

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

Refined Products Strengths and Challenges

Our refined products business strengths consist primarily of:


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

	•	growing economies of scale for our ethanol production;

	•	largest manufacturer of paving asphalt in Western Canada; and

	•	modern asphalt manufacturing facilities located within the Lloydminster integrated infrastructure.

Our refined products business will likely be challenged by the following:


	•	limited access to refining margins due to lack of sufficient refining facilities;

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

	•	higher transportation costs as a result of plant locations and lack of asphalt distribution network in the U.S. and Eastern Canada.

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 price that is competitive with our peers; and

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

In the short-term we must:


	•	competitively optimize production through effective exploitation techniques;

	•	exercise selective acquisition and divestitures;

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

	•	continue to progress 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 and optimization and expansion assessment of the Lloydminster Upgrader.

In addition to the metrics presented by financial statements, which are prepared in accordance with Canadian 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.

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 can be found in Section 2. “Financial and Operational Overview.”

The individual components of the overall metrics which we can and must influence are as follows:

Revenue Performance

Our revenues are primarily sensitive 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. The expected results of all plans to increase production must 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, a number of which are related to our own business such as energy costs and crude oil feedstock 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: that of increasing production, optimizing operating expenses or increasing reserves.

People Performance

We are continually investigating the factors that influence the development of a high functioning work environment and strong corporate culture. It is evident that the competitive edge that is measured with numbers is dependent on the quality of an enterprise’s value-based culture. To help us foster the development of a value-based culture we monitor attrition rates as well as the results of exit interviews; we monitor training statistics and attendance records. We facilitate and maintain a work place 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 debriefings subsequent to events and regular audits to ensure full compliance.

2. FINANCIAL AND OPERATIONAL OVERVIEW

OVERVIEW

Financial Position

Comparative Shareholder Return

Financial Performance

SELECTED ANNUAL INFORMATION


			Year ended December 31

						Percent					Percent
			2005			Change			2004⁽¹⁾		Change			2003⁽¹⁾

			($ millions, except where indicated)
Sales and operating revenues, net of royalties			$	10,245			21		$	8,440		10		$	7,658
Segmented earnings
	Upstream		$	1,524			114		$	713		(33	)	$	1,067
	Midstream			495			106			240		30			185
	Refined Products			82			100			41		28			32
	Corporate and eliminations			(98	)					12					86

Net earnings			$	2,003			99		$	1,006		(27	)	$	1,370

	Per share
		Basic	$	4.72			99		$	2.37		(27	)	$	3.26
		Diluted	$	4.72			99		$	2.37		(27	)	$	3.25
Dividends per common share			$	0.65			41		$	0.46		21		$	0.38
Special dividend per common share			$	1.00			85		$	0.54		(46	)	$	1.00
Total assets			$	15,797			19		$	13,240		11		$	11,949
Long-term debt excluding current portion			$	1,612			(21	)	$	2,047		18		$	1,730
Return on equity(percent)				29.2						17.0					26.4
Return on average capital employed(percent)				22.8						13.0					18.9


(1)	2004 and 2003 amounts as restated. Refer to Notes 3 and 11 to the Consolidated Financial Statements.

SELECTED QUARTERLY INFORMATION


			2005								2004

			Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1

			($ millions, except where indicated)
Sales and operating revenues, net of royalties			$	3,207	$	2,594	$	2,350	$	2,094	$	2,018	$	2,191	$	2,210	$	2,021
Net earnings			$	669	$	556	$	394	$	384	$	225	$	297	$	229	$	255
	Per share
		Basic	$	1.58	$	1.31	$	0.93	$	0.91	$	0.53	$	0.70	$	0.54	$	0.60
		Diluted	$	1.58	$	1.31	$	0.93	$	0.91	$	0.53	$	0.70	$	0.54	$	0.60
Share price
		High	$	65.79	$	69.95	$	50.75	$	40.49	$	35.65	$	31.15	$	28.30	$	28.04
		Low	$	50.50	$	47.37	$	35.12	$	32.30	$	30.05	$	25.42	$	23.74	$	22.73
		Close (end of period)	$	59.00	$	64.57	$	48.73	$	36.33	$	34.25	$	30.79	$	25.65	$	26.20
Shares traded(thousands)				38,731		34,521		46,988		46,370		37,417		35,074		26,654		22,824
Dividends declared per common share			$	0.25	$	0.14	$	0.14	$	0.12	$	0.12	$	0.12	$	0.12	$	0.10
Special dividend per common share			$	1.00	$	—	$	—	$	—	$	0.54	$	—	$	—	$	—
Weighted average number of common shares outstanding(thousands)
		Basic		424,120		424,049		423,891		423,791		423,708		423,610		423,413		422,711
		Diluted		424,120		424,049		423,891		423,791		423,708		423,610		425,169		424,720

THE BUSINESS ENVIRONMENT IN 2005

Husky’s financial results are significantly influenced by its business environment. Risks include, but are not limited to:


	•	crude oil and natural gas prices;

	•	the price differential and demand related to various crude oil qualities;

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

	•	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	2005		2004		2003

WTI crude oil⁽¹⁾ (U.S. $/bbl)	$	56.56	$	41.40	$	31.04
Dated Brent (U.S. $/bbl)	$	54.38	$	38.21	$	28.94
Canadian par light crude 0.3 percent sulphur ($/bbl)	$	69.28	$	52.91	$	43.56
Lloyd @ Lloydminster heavy crude ($/bbl)	$	31.07	$	28.75	$	26.44
NYMEX natural gas⁽¹⁾ (U.S. $/mmbtu)	$	8.62	$	6.14	$	5.39
NIT natural gas ($/GJ)	$	8.04	$	6.44	$	6.35
WTI/ Lloyd crude blend differential (U.S. $/bbl)	$	21.01	$	13.65	$	8.55
U.S./ Canadian dollar exchange rate (U.S. $)	$	0.826	$	0.769	$	0.716


(1)	Prices quoted arenear-month contract prices for settlement during the next month.

Our profitability is largely determined by the price we realize for crude oil and natural gas. All of our crude oil production and the majority of our natural gas production receive 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 exert a dramatic effect on short-term supply and demand.

Lately the world supply and demand balance has been edging toward higher demand and as a result prices have increased substantially. This brings with it increased international effort to increase production. Notwithstanding the success of those efforts, any diminishing of global demand could set the stage for price declines.

In addition, the global decline in the supply of lighter crude oil has spawned a surge in the price of heavier grades of crude oil and consequently an increase in the development and production of heavier grades of crude oil. The heavier grades trade at a discount to light crude oil refinery feedstock since they are less suited to the manufacture of motor fuels. The increased supply of heavy crude has caused a widening of the pricing differential between heavy and light crude oil since the capacity to refine heavy crude oil feedstock has not materially increased.

The majority of our crude oil and natural gas production is marketed in North America.

WTI and Husky Average Crude Oil Prices

($/bbl)

NYMEX Natural Gas, NIT Natural Gas and Husky Average Natural Gas Prices

SENSITIVITIES BY SEGMENT FOR 2005 RESULTS

The following table is indicative of the relative effect on pre-tax cash flow and net earnings from changes in certain key variables in 2005. The analysis is based on business conditions and production volumes during 2005. 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.


		2005					Effect on Pre-tax						Effect on
Sensitivity Analysis		Average			Increase		Cash Flow						Net Earnings

							($			($/share)⁽⁵⁾			($ millions)			($/share)⁽⁵⁾
							millions)
Upstream and Midstream
	WTI benchmark crude oil price		$56.56			U.S. $1.00/bbl		77			0.18			50			0.12
	NYMEX benchmark natural gas price⁽¹⁾		$8.62			U.S. $0.20/mmbtu		36			0.08			22			0.05
	Upgrading differential⁽²⁾		$30.70			Cdn $1.00/bbl		(27	)		(0.06	)		(17	)		(0.04	)
	Exchange rate (U.S. $ per Cdn $)⁽³⁾		$0.826			U.S. $0.01		(58	)		(0.14	)		(39	)		(0.09	)
Refined Products
	Light oil margins		$0.039			Cdn $0.005/litre		16			0.04			10			0.02
	Asphalt margins		$10.05			Cdn $1.00/bbl		8			0.02			5			0.01
Consolidated
	Year-end translation of U.S. $ debt (U.S. $ per Cdn $)		$0.858	⁽⁴⁾		U.S. $0.01		—			—			10			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, 2005.

(5)	Based on December 31, 2005 common shares outstanding of 424.1 million.


3.	RESULTS OF OPERATIONS

Segmented Earnings

UPSTREAM

Earnings Summary and 2005 Variance Analysis


	Year ended December 31

Upstream Earnings Summary	2005		2004		2003

	($ millions)
Gross revenues	$	5,207	$	4,392	$	3,796
Royalties		840		711		584
Hedging loss		—		561		26

Net revenues		4,367		3,120		3,186
Operating and administration expenses		1,050		967		873
Depletion, depreciation and amortization		1,144		1,077		918
Income taxes		649		363		328

Earnings	$	1,524	$	713	$	1,067

Upstream earnings in 2005 were $811 million higher than in 2004 primarily due to the following factors:


	•	higher natural gas and crude oil prices increased 2005 revenue by $947 million; and

	•	absence of commodity price hedging in 2005; 2004 hedging was primarily on 85 mbbls/day of crude oil at a strike price of U.S. $27.46.

Partially offset by:


	•	higher royalties resulting from higher commodity prices and Terra Nova progressing to a higher royalty rate;

	•	lower sales volume of crude oil and natural gas, the net effect of which lowered revenue by $145 million in 2005;

	•	unit operating costs were $0.80/boe higher in 2005 compared with 2004 as a result of:


	•	higher fuel and energy related costs;

	•	increasing level of field maintenance costs involved in crude oil exploitation activities; and

	•	increasing wells and compression for natural gas production.


	•	higher unit depletion, depreciation and amortization, which was $9.95/boe during 2005 versus $9.06 during 2004 as a result of:


	•	start up of operations at the White Rose oilfield offshore the East Coast of Canada; and

	•	increasing exploration and exploitation costs in the Western Canada Sedimentary Basin.


		Crude Oil			Natural
Net Revenue Variance Analysis		& NGL			Gas			Other		Total

		($ millions)
Year ended December 31, 2003
Net revenues		$	2,097		$	1,024		$	65	$	3,186
	Price changes		359			98			—		457
	Volume changes		(36	)		172			—		136
	Royalties		(67	)		(60	)		—		(127	)
	Hedging		(514	)		(21	)		—		(535	)
	Processing and sulphur		—			—			3		3

Year ended December 31, 2004
Net revenues			1,839			1,213			68		3,120
	Price changes		1,081			427			—		1,508
	Volume changes		(120	)		(25	)		—		(145	)
	Royalties		(71	)		(58	)		—		(129	)
	Processing and sulphur		—			—			13		13

Year ended December 31, 2005
Net revenues		$	2,729		$	1,557		$	81	$	4,367

Production


	Year ended December 31

Daily Production, before Royalties	2005		2004		2003

Light crude oil & NGL (mbbls/day)		64.6		66.2		71.6
Medium crude oil (mbbls/day)		31.1		35.0		39.2
Heavy crude oil (mbbls/day)		106.0		108.9		99.9

Total crude oil & NGL (mbbls/day)		201.7		210.1		210.7
Natural gas (mmcf/day)		680.0		689.2		610.6
Barrels of oil equivalent (6:1) (mboe/day)		315.0		325.0		312.5


		Year ended December 31

Average Sales Prices		2005		2004		2003

Crude oil ($/bbl)
	Light crude oil & NGL	$	61.56	$	48.34	$	39.53
	Medium crude oil		43.44		36.13		31.42
	Heavy crude oil		31.09		28.66		25.87
	Total average		42.75		36.07		31.54
	Total average after hedging		42.75		28.43		30.93
Natural gas ($/mcf)
	Average	$	7.96	$	6.25	$	5.86
	Average after hedging		7.96		6.24		5.94


		Year ended December 31

Upstream Revenue Mix⁽¹⁾		2005		2004		2003

Percentage of upstream sales revenues, after royalties
	Light crude oil & NGL		29%		27%		29%
	Medium crude oil		9%		11%		12%
	Heavy crude oil		24%		27%		26%
	Natural gas		38%		35%		33%

	Total		100%		100%		100%


		Year ended December 31

Effective Royalty Rates⁽¹⁾		2005		2004		2003

Percentage of upstream sales revenues
	Light crude oil & NGL		14%		13%		12%
	Medium crude oil		18%		18%		17%
	Heavy crude oil		12%		12%		11%
	Natural gas		20%		22%		22%
	Total		16%		16%		16%

(1) Before commodity hedging.

Operating Netbacks


	Year ended December 31

Western Canada Light Crude Oil Netbacks⁽¹⁾	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	60.74	$	46.12	$	39.91
Royalties		8.66		7.76		7.28
Operating costs		9.86		8.94		9.27

Netback	$	42.22	$	29.42	$	23.36


	Year ended December 31

Western Canada Medium Crude Oil Netbacks⁽¹⁾	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	43.67	$	36.20	$	31.57
Royalties		7.77		6.10		5.28
Operating costs		10.97		10.07		9.53

Netback	$	24.93	$	20.03	$	16.76


(1)	Includes associatedco-products converted to boe.


	Year ended December 31

Western Canada Heavy Crude Oil Netbacks⁽¹⁾	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	31.22	$	28.73	$	25.98
Royalties		3.75		3.38		2.76
Operating costs		9.90		9.33		9.09

Netback	$	17.57	$	16.02	$	14.13


	Year ended December 31

Western Canada Natural Gas Netbacks⁽²⁾	2005		2004		2003

	(per mcfge)
Sales revenues before hedging	$	8.02	$	6.25	$	5.79
Royalties		1.76		1.44		1.29
Operating costs		1.04		0.89		0.79

Netback	$	5.22	$	3.92	$	3.71


	Year ended December 31

Total Western Canada Upstream Netbacks⁽¹⁾	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	42.53	$	35.01	$	31.58
Royalties		7.45		6.22		5.48
Operating costs		8.59		7.85		7.56

Netback	$	26.49	$	20.94	$	18.54


	Year ended December 31

Terra Nova Crude Oil Netbacks	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	62.19	$	47.87	$	38.91
Royalties		7.95		1.80		0.81
Operating costs		4.53		3.28		3.16

Netback	$	49.71	$	42.79	$	34.94


	Year ended December 31

White Rose Crude Oil Netbacks	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	63.68	$	—	$	—
Royalties		0.61		—		—
Operating costs		6.72		—		—

Netback	$	56.35	$	—	$	—


	Year ended December 31

Total Canada Netbacks⁽¹⁾	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	43.69	$	35.60	$	32.01
Royalties		7.36		6.03		5.21
Operating costs		8.39		7.66		7.30

Netback	$	27.94	$	21.91	$	19.50


(1)	Includes associatedco-products converted to boe.

(2)	Includes associatedco-products converted to mcfge.


	Year ended December 31

Wenchang Crude Oil Netbacks	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	63.15	$	47.66	$	41.45
Royalties		5.93		4.91		3.80
Operating costs		2.92		2.16		1.94

Netback	$	54.30	$	40.59	$	35.71


	Year ended December 31

Total Upstream Segment Netbacks⁽¹⁾	2005		2004		2003

	(per boe)
Sales revenues before hedging	$	44.56	$	36.34	$	32.69
Royalties		7.29		5.96		5.11
Operating costs		8.12		7.32		6.92

Netback	$	29.15	$	23.06	$	20.66


(1)	Includes associated co-products converted to boe.

Oil and Gas Reserves

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.

At December 31, 2005, the present value of future net cash flows after tax from Husky’s proved oil and gas reserves, based on prices and costs in effect at year-end and discounted at 10 percent, was $11.0 billion compared with $5.2 billion at the end of 2004.

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		Proved Developed						Proved Undeveloped						Total Proved						Proved and Probable
Natural Gas
Reserves Summary⁽¹⁾		2005		2004		2003		2005		2004		2003		2005		2004		2003		2005		2004			2003

		(constant price before royalties)
Crude oil (mmbbls)
	Light & NGL		226		191		200		47		47		23		273		238		223		462		465			474
	Medium		80		80		86		11		6		8		91		86		94		105		96			108
	Heavy		140		91		156		77		14		71		217		105		227		291		150			319
	Bitumen		—		—		—		48		—		—		48		—		—		951		79			79

			446		362		442		183		67		102		629		429		544		1,809		790			980
Natural gas (bcf)			1,710		1,745		1,712		426		424		347		2,136		2,169		2,059		2,709		2,724			2,507

Total (mmboe)			731		653		727		254		138		160		985		791		887		2,260		1,244	��		1,397


(1)	Refer to “Terms and Abbreviations” in this Annual Report for definitions of reserves.

2005 Reserve Additions

Our oil and gas reserves are estimated in accordance with the regulations and guidance of the SEC and the FASB which, among other things, require reserves to be evaluated using prices in effect on the day the reserves are estimated.

The additions to crude oil and NGL proved reserves from discoveries, extensions, improved recovery and technical revisions in 2005 amounted to 154 million barrels and were primarily from the White Rose oilfield in the Jeanne d’Arc Basin offshore Newfoundland, the Tucker Oil Sands project in the Cold Lake region of Alberta and the Lloydminster heavy oil region.

The additions to natural gas proved reserves from discoveries, extensions and improved recovery amounted to 286 billion cubic feet which was partially offset by net technical revisions of negative 68 billion cubic feet due to well performance. The positive results were primarily related to our drilling program in the foothills and deep basin areas of Alberta and northeastern British Columbia and the negative technical revisions were recorded at properties throughout the Western Canada Sedimentary Basin.


			Canada																	International					Total

			Western Canada														East
																	Coast
			Light
			Crude			Medium			Heavy								Light			Light					Crude
Reconciliation of Proved			Oil &			Crude			Crude			Natural					Crude			Crude			Natural		Oil &			Natural
Reserves			NGL			Oil			Oil			gas			Bitumen		Oil			Oil			Gas		NGL			Gas

			(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)		(mmbbls)			(mmbbls)			(bcf)		(mmbbls)			(bcf)			(mmboe)
			(constant price before royalties)
Proved reserves at December 31, 2004				171			86			225			2,172			—		47			20			—		549			2,172			911
		Heavy oil price revision		—			—			(120	)		(3	)		—		—			—			—		(120	)		(3	)		(120	)

Proved reserves at December 31, 2004				171			86			105			2,169			—		47			20			—		429			2,169			791
		Technical revisions		3			9			1			(68	)		—		9			2			—		24			(68	)		13
		Heavy oil price revision		—			—			120			3			—		—			—			—		120			3			120
		Purchase of reserves in place		—			—			7			3			—		—			—			—		7			3			7
		Sale of reserves in place		—			(3	)		(4	)		(9	)		—		—			—			—		(7	)		(9	)		(9	)
		Discoveries, extensions and improved recovery		5			10			27			286			48		39			1			—		130			286			178
		Production		(12	)		(11	)		(39	)		(248	)		—		(6	)		(6	)		—		(74	)		(248	)		(115	)

Proved reserves at December 31, 2005				167			91			217			2,136			48		89			17			—		629			2,136			985

Proved and probable reserves
	At December 31, 2005			225			105			291			2,542			951		207			30			167		1,809			2,709			2,260

	At December 31, 2004			229			96			150			2,557			79		203			33			167		790			2,724			1,244


		Canada																	International			Total

																East
		Western Canada														Coast

		Light
		Crude			Medium			Heavy								Light						Crude
Reconciliation of Proved Developed		Oil &			Crude			Crude			Natural					Crude			Light Crude			Oil &			Natural
Reserves		NGL			Oil			Oil			Gas			Bitumen		Oil			Oil			NGL			Gas

		(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)		(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmboe)
		(constant price before royalties)
Proved developed reserves at December 31, 2004			155			80			91			1,745			—		16			20			362			1,745			653
	Revision of previous estimate		7			11			71			77			—		27			2			118			77			130
	Purchase of reserves in place		—			—			2			2			—		—			—			2			2			3
	Sale of reserves in place		(1	)		(2	)		(3	)		(8	)		—		—			—			(6	)		(8	)		(7	)
	Improved recovery		2			2			18			142			—		22			—			44			142			67
	Production		(12	)		(11	)		(39	)		(248	)		—		(6	)		(6	)		(74	)		(248	)		(115	)

Proved developed reserves at December 31, 2005			151			80			140			1,710			—		59			16			446			1,710			731

Upstream Capital Expenditures


			Year ended December 31

Capital Expenditures⁽¹⁾			2005		2004		2003

			($ millions)
Upstream
	Exploration
		Western Canada	$	389	$	322	$	326
		East Coast Canada and Frontier		66		24		24
		International		55		18		26

				510		364		376

	Development Western Canada			1,618		1,211		869
		East Coast Canada		579		515		533
		International		23		67		—

				2,220		1,793		1,402

			$	2,730	$	2,157	$	1,778


(1)	Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions.


		Year ended December 31

		2005				2004				2003

Western Canada Drilling		Gross		Net		Gross		Net		Gross		Net

		(wells)
Exploration
	Oil		89		85		45		39		12		11
	Gas		392		196		234		180		147		124
	Dry		36		36		34		33		22		21

			517		317		313		252		181		156

Development
	Oil		466		433		552		499		520		490
	Gas		610		551		807		740		540		518
	Dry		42		39		57		53		60		57

			1,118		1,023		1,416		1,292		1,120		1,065

Total			1,635		1,340		1,729		1,544		1,301		1,221

Canada

In 2005, upstream capital spending in Canada amounted to $2,652 million, up from $2,072 million in 2004. Capital spending in 2005 comprised $1,217 million on Western Canada conventional areas, $424 million in the Lloydminster heavy oil region, $366 million in the Alberta oil sands regions, $579 million for East Coast development and $66 million for East Coast and Northwest Territories exploration.

In 2005, spending on exploration activities comprised $213 million in the foothills and deep basin regions, $57 million in the Lloydminster heavy oil region, $24 million in the Alberta oil sands regions and $95 million in the remainder of the conventional Western Canada Sedimentary Basin.

In the Lloydminster heavy oil production region capital spending amounted to $424 million in 2005, $57 million of which was classified as exploration. Spending in this area is primarily focused on steam-assisted gravity drainage (“SAGD”), cyclic steam and cold production techniques that are utilized to produce the 12 to 14 degree API heavy crude oil. Production of heavy crude oil is more capital intensive due to the extensive infrastructure required to produce the large amounts of steam used to heat the crude oilin-situ prior to pumping to the surface.

Exploration spending in the foothills and deep portion of the greater Western Canada Sedimentary Basin amounted to $213 million in 2005, up from $167 million in 2004. 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 $366 million in 2005, up from $53 million in 2004. Our Tucker SAGD Oil Sands project is well underway andon-schedule to commence operations before the end of 2006. We spent $342 million on the Tucker project in 2005. The Sunrise Oil Sands project was approved by Alberta regulatory authorities at the end of 2005 and the front-end engineering and design is underway. During 2005 we spent $21 million on Sunrise and $3 million on other oil sands prospects.

During November 2005, the White Rose oilfield in the Jeanne d’Arc Basin offshore Newfoundland produced first oil. The project will now continue to ramp up production with the drilling of at least nine additional production and injection wells through 2006 and 2007. During 2005, exploration activities involved one exploration well at Lewis Hill in the South Whale Basin, which was abandoned without testing, and a delineation well in the White Rose field. In 2005 capital spending for exploration and development activities in this region amounted to $645 million, up from $539 million in 2004.

International

Exploration spending in China involved the drilling of two wells in the South China Sea. The first well encountered hydrocarbon and the results are being evaluated; the second well was plugged and abandoned without testing. In Indonesiafront-end engineering and design for the Madura Strait natural gas and NGL project is underway. Total capital spending on international activities amounted to $78 million, a similar level compared with 2004.

MIDSTREAM


*Upgrader*	*Pipelines*

Upgrading Earnings Summary and 2005 Variance Analysis


	Year ended December 31

Upgrading Earnings Summary	2005			2004			2003

	($ millions, except
	where indicated)
Gross margin	$	692		$	383		$	313
Operating costs		228			214			205
Other recoveries		(6	)		(5	)		(4	)
Depreciation and amortization		21			19			20
Income taxes		136			43			21

Earnings	$	313		$	112		$	71

Upgrader throughput⁽¹⁾ (mbbls/day)		66.6			64.6			72.5
Synthetic crude oil sales (mbbls/day)		57.5			53.7			63.6
Upgrading differential ($/bbl)	$	30.70		$	17.79		$	12.88
Unit margin ($/bbl)	$	33.01		$	19.48		$	13.51
Unit operating cost⁽²⁾ ($/bbl)	$	9.38		$	9.07		$	7.77

(1) Throughput includes diluent returned to the field.

(2) Based on throughput.

Upgrading earnings increased by $201 million in 2005 primarily due to:


	•	wider upgrading differential, which averaged $30.70/bbl in 2005 compared with $17.79/bbl in 2004; and

	•	higher sales volume of synthetic crude oil. The upgrader was down in both 2005 and 2004 for scheduled maintenance.

Partially offset by:


	•	higher energy and non-energy related unit operating costs.


Upgrading Earnings Variance Analysis
		($ millions)
Year ended December 31, 2003		$	71
	Volume		(48	)
	Differential		118
	Operating costs — non-energy related		(9	)
	Other		1
	Depreciation and amortization		1
	Income taxes		(22	)

Year ended December 31, 2004			112
	Volume		25
	Differential		284
	Operating costs — energy related		(18	)
	Operating costs — non-energy related		5
	Depreciation and amortization		(2	)
	Income taxes		(93	)

Year ended December 31, 2005		$	313

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 operating 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 that trades at a discount to light crude oil, and any negative effect of a narrower differential on upgrading

operations 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 2005 Variance Analysis


		Year ended December 31

Infrastructure and Marketing Earnings Summary		2005		2004		2003

		($ millions, except where
		indicated)
Gross margin
	Pipeline	$	92	$	84	$	66
	Other infrastructure and marketing		217		136		141

			309		220		207
Other expenses			10		8		8
Depreciation and amortization			21		21		21
Income taxes			96		63		64

Earnings		$	182	$	128	$	114

Aggregate pipeline throughput (mbbls/day)			474		492		484

Infrastructure and marketing earnings increased by $54 million in 2005 primarily due to:


	•	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.

Partially offset by:


	•	lower heavy crude oil pipeline throughput; and

	•	higher operating costs due primarily to higher energy costs.

Midstream Capital Expenditures

Midstream capital expenditures of $157 million in 2005 were primarily for upgrader debottlenecking and pipeline upgrades compared with $93 million in 2004.

REFINED PRODUCTS


*Light Oil Product Marketing*	*Asphalt Products*

Earnings Summary and Variance Analysis


		Year ended December 31

Refined Products Earnings Summary		2005		2004		2003

		($ millions, except where
		indicated)
Gross margin
	Fuel sales	$	126	$	93	$	71
	Ancillary sales		34		30		28
	Asphalt sales		91		51		51

			251		174		150
Operating and other expenses			75		71		74
Depreciation and amortization			47		38		26
Income taxes			47		24		18

Earnings		$	82	$	41	$	32

Number of fuel outlets			515		531		552
Refined products sales volume
	Light oil products (million litres/day)		8.9		8.4		8.2
	Light oil products per outlet (thousand litres/day)		12.7		11.7		10.8
	Asphalt products (mbbls/day)		22.5		22.8		22.0
Refinery throughput
	Prince George refinery (mbbls/day)		9.7		9.8		10.3
	Lloydminster refinery (mbbls/day)		25.5		25.3		25.7

Refined products earnings increased by $41 million in 2005 primarily due to:


	•	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; and

	•	higher depreciation and amortization.

Refined Products Margins

The margins realized by Husky for refined products are affected by crude oil price fluctuations, which affect refinery feedstock costs, and third-party light oil refined product purchases. Husky’s ability to maintain refined

products margins in an environment of higher feedstock costs is contingent upon the ability to pass on higher costs to our customers.

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.

Refined Products Capital Expenditures

Refined products capital expenditures in 2005 of $191 million were primarily for marketing outlet improvements, refinery upgrades and construction of an ethanol plant compared with $106 million in 2004.

CORPORATE


	Year ended December 31

Corporate Earnings Summary⁽¹⁾	2005			2004			2003

	($ millions) income
	(expenses)
Intersegment eliminations — net	$	(50	)	$	(14	)	$	14
Administration expenses		(19	)		(27	)		(22	)
Stock-based compensation		(171	)		(67	)		—
Accretion		(2	)		(2	)		—
Other — net		49			(8	)		(3	)
Depreciation and amortization		(23	)		(24	)		(36	)
Interest on debt		(146	)		(135	)		(154	)
Interest capitalized		114			75			52
Foreign exchange		31			120			282
Income taxes		119			94			(47	)

Earnings (loss)	$	(98	)	$	12		$	86

(1) 2004 and 2003 amounts as restated. Refer to Notes 3 and 11 to the Consolidated Financial Statements.

Corporate expense increased by $110 million in 2005 compared with 2004 primarily due to:


	•	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.


		Year ended December 31
Foreign Exchange Summary⁽¹⁾		2005			2004			2003

		($ millions)
(Gain) loss on translation of U.S. dollar denominated long-term debt
	Realized	$	(13	)	$	(10	)	$	11
	Unrealized		(38	)		(140	)		(393	)

			(51	)		(150	)		(382	)

Cross currency swaps
	Realized		—			—			32
	Unrealized		14			27			41

			14			27			73

Other losses			6			3			27

		$	(31	)	$	(120	)	$	(282	)

U.S./ Canadian dollar exchange rates:
	At beginning of year	U.S. $	0.831		U.S. $	0.774		U.S. $	0.633
	At end of year	U.S. $	0.858		U.S. $	0.831		U.S. $	0.774


(1)	2004 and 2003 amounts as restated. Refer to Notes 3 and 11 to the Consolidated Financial Statements.

Foreign Exchange Risk

Consolidated Income Taxes

Consolidated income taxes increased in 2005 to $809 million from $399 million in 2004 primarily as a result of higher pre-tax earnings.

In 2004 the indicative income tax rate was higher than in the previous year as a result of the 2003 amendments to the Federal and Alberta income tax acts. During 2004, the enactment of Bill 27-Alberta Corporate Tax Amendment Act, 2004 resulted in a non-recurring benefit of $40 million. During 2003, an amendment to the Federal Income Tax Act reduced the income tax rate on resource income by seven percent, provided for the deduction from income of crown royalties and eliminated the resource allowance deduction. This amendment resulted in a total benefit being recorded in 2003 of $141 million. In addition, in 2003 a non-recurring benefit totalling $20 million was recorded pursuant to Bill 41, the Alberta Corporate Tax Amendment Act, 2003. All benefits reduced future income taxes.

In 2005 current income taxes totalled $297 million and comprised $84 million in respect of the Wenchang oilfield operation, $15 million of capital taxes and $198 million of Canadian income tax.

The following table shows the effect of non-recurring tax benefits for the periods noted:


	2005		2004

	($ millions)
Income taxes before tax amendments	$	813	$	439
Canadian federal and provincial tax amendments		4		40

Income taxes as reported	$	809	$	399


	Year ended
	December 31

Husky’s Canadian Tax Pools	2005		2004

	($ millions)
Canadian exploration expense	$	78	$	—
Canadian development expense		2,033		1,616
Canadian oil and gas property expense		721		557
Foreign exploration and development expense		240		212
Undepreciated capital costs		4,249		3,269
Other		27		22

	$	7,348	$	5,676

Corporate Capital Expenditures

Corporate capital expenditures of $21 million in 2005 were primarily for computer hardware and software and office furniture and equipment and compared with $23 million in 2004.

4. LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CASH FLOW


		Year ended December 31

		2005			2004			2003

Cash flow — operating activities ($ millions)		$	3,672		$	2,326		$	2,509
	— financing activities ($ millions)	$	(616	)	$	175		$	(771	)
	— investing activities ($ millions)	$	(2,814	)	$	(2,497	)	$	(2,041	)
Debt to capital employed (percent)			20.1			25.8			26.9
Corporate reinvestment ratio⁽¹⁾			0.8			1.1			0.9

(1) Reinvestment ratio is based on net capital expenditures including corporate acquisitions.

Cash Flow from Operating Activities

In 2005 cash generated by operating activities was $3,672 million, an increase of $1,346 million from the $2,326 million recorded in 2004. The higher cash from operating activities in 2005 was primarily due to higher earnings, partially offset by increasednon-cash working capital associated with operating activities.

Cash Flow from (used for) Financing Activities

In 2005 cash used in financing activities amounted to $616 million. The cash used was composed of the repayment oflong-term debt of $3,401 million and a $49 million repayment of operating lines, dividends of $700 million, including a $1.00 per share special dividend and other costs of $1 million. Cash provided by financing activities in 2005 comprised $3,235 million issuance of long-term debt, $6 million of proceeds from the exercise of stock options, proceeds from monetization of financial instruments totalling $39 million and a change of $255 million innon-cash working capital. Debt issuances and repayments include multiple drawings and repayments under revolving debt facilities.

Husky’s long-term debt balances were also reduced by $51 million during 2005 primarily as a result of 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 $2,814 million in 2005, an increase of $317 million from the $2,497 million in 2004. Cash invested in 2005 was composed of capital expenditures of $3,068 million, partially offset by $74 million of proceeds from asset sales. Change innon-cash working capital and other adjustments amounted to $180 million used in investing activities.

FINANCIAL POSITION

Sources and Uses of Cash

Liquidity describes a company’s ability to access 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 proved 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 continually examine our options with respect to sources of long and short-term capital resources. In addition, from time to time we engage in hedging a portion of our production to protect cash flow in the event of commodity price declines.

The following illustrates the Company’s sources and uses of cash during the years ended December 31, 2005, 2004 and 2003:


Sources and Uses of Cash		2005			2004			2003

		($ millions)
Cash sourced
	Cash flow from operations⁽¹⁾	$	3,785		$	2,197		$	2,430
	Debt issue		3,235			2,200			669
	Asset sales		74			36			511
	Proceeds from exercise of stock options		6			18			51
	Proceeds from monetization of financial instruments		39			8			44
	Other		—			—			5

			7,139			4,459			3,710

Cash used
	Capital expenditures		3,068			2,349			1,868
	Corporate acquisitions		—			102			809
	Debt repayment		3,450			1,959			971
	Special dividend on common shares		424			229			420
	Ordinary dividends on common shares		276			195			160
	Settlement of asset retirement obligations		41			40			34
	Settlement of cross currency swap		—			—			32
	Other		32			24			—

			7,291			4,898			4,294

Net cash (deficiency)			(152	)		(439	)		(584	)
Increase (decrease) in non-cash working capital			394			443			281

Increase (decrease) in cash and cash equivalents			242			4			(303	)
Cash and cash equivalents — beginning of year			7			3			306

Cash and cash equivalents — end of year		$	249		$	7		$	3


(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.

Sources and Uses of Cash (continued)


			2005		2004		2003

			($ millions)
Increase (decrease) in non-cash working capital
	Cash positive working capital change
		Accounts receivable decrease	$	—	$	209	$	—
		Inventory decrease		—		—		28
		Prepaid expense decrease		17		—		—
		Accounts payable and accrued liabilities increase		984		323		270

				1,001		532		298
	Cash negative working capital change
		Accounts receivable increase		410		—		7
		Inventory increase		197		77		—
		Prepaid expense increase		—		12		10

				607		89		17

Increase (decrease) in non-cash working capital			$	394	$	443	$	281

Capital Structure


		December 31, 2005

		Outstanding				Available

		(U.S. $)		(Cdn $)		(Cdn $)
		($ millions)
Short-term bank debt		$	—	$	—	$	177
Long-term bank debt
	Syndicated credit facility		��		—		1,000
	Bilateral credit facility		—		—		150
	Medium-term notes		—		300
	Capital securities		225		262
	U.S. public notes		1,050		1,225
	U.S. senior secured bonds		85		99

Total short-term and long-term debt		$	1,360	$	1,886	$	1,327

Common shares and retained earnings				$	7,520

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2005, our working capital deficiency was $1.0 billion compared with $824 million at December 31, 2004. The increase in the deficiency is primarily due to the $1.00 per share special dividend declared on October 19, 2005 and the increase in payables for capital and commodity purchases. It is not unusual for Husky to have working capital deficits at the end of a reporting period. These working capital deficits are primarily the result of accounts payable related to capital expenditures for exploration and development. Settlement of these current liabilities is funded by cash provided by operating activities and to the extent necessary by bank borrowings. This position is a common characteristic of the oil and gas industry which, by the nature of its business, spends large amounts of capital.

As at December 31, 2005, our outstanding long-term debt totalled $1.9 billion, including amounts due within one year, compared with $2.1 billion at December 31, 2004.

At December 31, 2005, we had no drawings under our $1 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 three times and a consolidated tangible net worth, as of December 31, 2005, of at least $4.4 billion.

At December 31, 2005, 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, 2005, we had borrowed $0.4 million and utilized $18 million in support of letters of credit under our $195 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 utilized $105 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, 2005, $350 million in outstanding accounts receivable had been sold under this agreement. The arrangement matures on January 31, 2009.

Based on our 2006 commodity price forecast, we believe that our non-cancellable contractual obligations and other commercial commitments and our 2006 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 that aggregated $1.65 per share totalling $700 million in 2005, including a special dividend of $1.00 per share. The Board of Directors of Husky has established a dividend policy that pays quarterly dividends of $0.25 ($1.00 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, 2005 totalled $249 million compared with $7 million at the beginning of the year.

On February 1, 2006, we announced the redemption of the 8.45 percent senior secured bonds amounting to U.S. $85 million.

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.

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		2006		2007-2008		2009-2010		Thereafter

	($ millions)
Long-term debt and interest⁽¹⁾	$	2,700	$	403	$	565	$	350	$	1,382
Operating leases		502		81		158		131		132
Firm transportation agreements		679		169		243		118		149
Unconditional purchase obligations⁽²⁾		2,017		616		1,221		171		9
Lease rentals and exploration work agreements		427		50		98		125		154
Engineering and construction commitments		531		365		166		—		—

	$	6,856	$	1,684	$	2,451	$	895	$	1,826


(1)	Includes interest on fixed rate debt.

(2)	Includes purchase of refined petroleum products, processing services, distribution services, insurance premiums and natural gas purchases.

Estimated Obligations Not Included in the Table


	•	Asset retirement obligations


	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 asset retirement obligations. See Note 12 to the Consolidated Financial Statements.


	•	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 200 active employees and 460 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.

2006 Capital Program

Husky plans to invest capital in the following segments in 2006:


		Year ended
		December 31, 2006

		Estimate

		($ millions)
Upstream
	Western Canada	$	1,730
	East Coast Canada		350
	International		140

			2,220
Midstream			340
Refined Products			260
Corporate			30

		$	2,850

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. Our receivable securitization program is fully utilized at $350 million. The securitization agreement terminates on January 31, 2009. The accounts receivable are sold to an unrelated third party on a revolving basis. 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 the section “Financial Risk and Risk Management.”

TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS

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 percent of total sales and operating revenues during 2005.

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. under “The Business Environment in 2005.” 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 its oil and gas production and firm commitments for the purchase or sale of crude oil and natural gas.

We implemented a corporate hedging program for 2004 to manage the volatility of natural gas and crude oil prices.

Natural Gas

As a result of a corporate acquisition, we assumed a natural gas derivative contract for a notional 7.5 mmcf/day that matured at the end of 2005. During 2005, we recorded payments totalling $17 million on this contract.

Power Consumption

During 2005, we received payments totalling $4 million on our power consumption hedges.

Foreign Currency Risk Management

At December 31, 2005, Husky had the following cross currency debt swaps in place:


	•	U.S. $150 million at 7.125 percent swapped at $1.45 to $218 million at 8.74 percent until November 15, 2006.

	•	U.S. $150 million at 6.250 percent swapped at $1.41 to $212 million at 7.41 percent until June 15, 2012.

	•	U.S. $75 million at 6.250 percent swapped at $1.19 to $90 million at 5.65 percent until June 15, 2012.

	•	U.S. $50 million at 6.250 percent swapped at $1.17 to $59 million at 5.67 percent until June 15, 2012.

	•	U.S. $75 million at 6.250 percent swapped at $1.17 to $88 million at 5.61 percent until June 15, 2012.

At December 31, 2005 the cost of a U.S. dollar in Canadian currency was $1.1659.

In 2005 the cross currency swaps resulted in an offset to foreign exchange gains on translation of U.S. dollar denominated debt amounting to $14 million.

In addition, we entered into U.S. dollar forward contracts, which resulted in realized gains totalling approximately $15 million in 2005. 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 2005 interest rate risk management activities resulted in a decrease to interest expense of $13 million.

The cross currency swaps resulted in an addition to interest expense of $10 million in 2005.

We have interest rate swaps on $200 million of long-term debt, effective February 8, 2002, whereby 6.95 percent was swapped for CDOR + 175 bps until July 14, 2009. During 2005, these swaps resulted in an offset to interest expense amounting to $5 million.

In May 2005, Husky unwound the interest rate swaps on U.S. $300 million of long-term debt due June 15, 2019. Proceeds of $30 million have been deferred and are being amortized to income over the remaining term of the underlying debt. During 2005, the impact of these swaps before they were unwound was an offset to interest expense amounting to $3 million.

In November 2005, Husky unwound the interest rate swaps on U.S. $200 million of long-term debt due November 15, 2016. Proceeds of $7 million have been deferred and are being amortized to income over the remaining term of the underlying debt. During 2005, the impact of these swaps before they were unwound was an offset to interest expense amounting to $6 million.

The amortization of previous interest rate swap terminations resulted in an additional $9 million offset to interest expense in 2005.

OUTSTANDING SHARE DATA

Authorized:


	•	unlimited number of common shares

	•	unlimited number of preferred shares

Issued and outstanding: February 21, 2006


	•	common shares 424,147,746

	•	preferred shares none

	•	stock options 7,200,457

	•	stock options exercisable 1,193,153

At February 21, 2006, 20,045,663 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.

5. 2006 OUTLOOK

GENERAL ECONOMY

The factors that produced the supply and demand dynamics affecting 2004 and 2005 are expected to continue into 2006. This belief is, in part, derived from the predictions of the International Monetary Fund which forecast continued global economic growth led by the emerging Asian economies, particularly China. The world’s more developed economies are not expected to interfere with this prediction. The largest consumer of petroleum, the United States, is expected to grow and Japan appears to be recovering.

General inflation is expected to continue to rise as higher petroleum costs ripple throughout the cost inputs of virtually all other products and services, including the cost of capital. Although higher petroleum prices are beneficial to creating shareholder value for oil and gas enterprises, they also impact us, since we consume vast amounts of goods and services, not the least of which is energy itself.

UPSTREAM


Production Outlook	2006		2005 Actual

Light crude oil and NGL (mbbls/day)		103 - 116		65
Medium crude oil (mbbls/day)		29 - 32		31
Heavy crude oil (mbbls/day)		115 - 120		106

Total crude oil and NGL (mbbls/day)		247 - 268		202
Natural gas (mmcf/day)		680 - 730		680
Barrels of oil equivalent (6:1) (mboe/day)		360 - 390		315

Western Canada Conventional

Although the conventional production areas of the Western Canada Sedimentary Basin are considered relatively mature, current exploration and development activity is unprecedented. Production from this area is expected to account for less than 80 percent of our production in 2006, down from 90 percent in 2005 but will still be Husky’s cash generating foundation. By 2010, we expect conventional production from Western Canada, including heavy oil, to account for less than 60 percent of our total production.

We expect to replace a large portion of our conventional production from development of new areas in Canada, the oil sands, basins off the East Coast and the Northwest Territories and from China and Indonesia.

Capital expenditures for development and exploration on our conventional Western Canada properties are expected to account for 66 percent of the total $2.2 billion in upstream capital expenditures in 2006; up from 60 percent in 2005. This is because of the slowing of White Rose capital spending, which was completed to first oil in 2005, and the slowing of Tucker capital spending, which will reach first oil in 2006. This represents a short dip in spending outside of the Western Canada conventional area prior to the development of the Sunrise Oil Sands and Madura natural gas and NGL projects. We expect that by 2010 capital expenditures on conventional properties in Western Canada will drop to approximately 37 percent of total upstream capital spending.

We will also continue to pursue additional natural gas reserves and production using unconventional production technology from coal beds, shale and tight formations. Based on activity in 2005, production of natural gas from coal beds is encouraging.

Oil Sands

In 2006, we will continue with and complete to first oil the development of Tucker and proceed with the front-end engineering and design of Sunrise, which will be developed in phases to reach total capacity by approximately 2012.

Cost

Timing

Capacity

Tucker

500 million

2006

30,000 bbls/day

Sunrise

To be finalized

2010-12

200,000 bbls/day

Canada — East Coast and Northwest Territories

On the East Coast we will continue with the development and extension of the White Rose field, including monitoring the economics and technical feasibility of natural gas developments off the East Coast, in particular the natural gas resources in the north 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 where we recently acquired additional exploration rights on 38,600 acres, with a minimum work program commitment of $36.5 million.

In 2006, we will proceed with delineation and evaluation of the Summit Creek B-44 discovery which 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.

China and Indonesia

In China, we will continue to pursue offshore prospects.

In Indonesia, we expect to conclude negotiating a natural gas sales contract and an extension to the production sharing agreement. We will continue to validate previous engineering work and make appropriate modifications during 2006. We expect that development construction will take approximately three years following project sanction.

MIDSTREAM

In 2006, 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. In particular, we will continue the debottlenecking projects and operating performance initiatives at the Lloydminster Heavy Oil Upgrader.

REFINED PRODUCTS

In 2006, we will complete the Prince George Refinery modification, which will permit production of fuels that meet Federal requirements and we will complete the Lloydminster Ethanol Plant. We will also continue with construction of a second ethanol plant at Minnedosa, Manitoba, which will replace a small existing plant and is expected to be operational by mid-2007. We will continue to improve technology, appearance and product offerings at our marketing outlets. We will also continue to optimize the number and location of our retail outlets.

6. 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 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 variousrule-making bodies.

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 depletion, depreciation and amortization (“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 asset retirement obligation 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

Husky uses the full cost method of accounting for exploration and development activities as recommended by the CICA. In accordance with this 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 using the unit of production method based on estimated 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.

FULL COST ACCOUNTING

Effective January 1, 2004, we adopted Accounting Guideline 16, “Oil and Gas Accounting — Full Cost”. The new guideline modified the ceiling test, which requires, for each cost centre, 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.

IMPAIRMENT OFLONG-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 thelong-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 thelong-lived asset is charged to earnings.

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 certain hedging derivatives requires considerable judgement. The estimation of the fair value of commodity price hedges requires sophisticated financial models that incorporate forward price and volatility data and which when compared with Husky’s open hedging contracts, produce cash inflow or outflow variances over the contract period. The estimate of fair value for interest rate and foreign currency hedges is determined primarily through quotes from financial institutions.

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.

ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2004, we adopted the recommendations of CICA section 3110, “Asset Retirement Obligations” (“ARO”), which is essentially identical to the United States accounting requirements of FAS 143.

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 percent 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 andsub-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 public relations considerations.

The new ARO rules require that an asset retirement obligation associated with the retirement of a tangiblelong-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, futurethird-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.

LEGAL, ENVIRONMENTAL REMEDIATION AND OTHER CONTINGENT MATTERS

We are required to both determine whether a loss is probable based on judgement and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined it is charged to earnings. The Company’s management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.

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.

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 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 primarily relies on placing a value on the oil and gas reserves. The valuation of oil and gas reserves entails the process described in Section 3. “Results of Operations — 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.

GOODWILL

The process of accounting for the purchase of a company, described above, results in recognizing the fair value of the acquired company’s 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 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 periodically 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 judgement.

7. NEW ACCOUNTING STANDARDS

LIABILITIES AND EQUITY

In November 2004, the Accounting Standards Board (“AcSB”) revised recommendations in CICA section 3860, “Financial Instruments — Disclosure and Presentation”, on the classification of obligations that must or could be settled with an entity’s own equity instruments. The new recommendations were effective January 1, 2005 and resulted in Husky’s capital securities being classified as liabilities instead of equity. The accrued return on the capital securities and the issue costs are classified outside of shareholders’ equity. The return on the capital securities is a charge to earnings. The revision was applied retroactively effective January 1, 2005.

NON-MONETARY TRANSACTIONS

In June 2005 the AcSB issued CICA section 3831,“Non-monetary Transactions” which replaced section 3830 of the same name. The new recommendations require that allnon-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. The guidance is effective for allnon-monetary transactions initiated in periods beginning on or after January 1, 2006.

8. PENDING ACCOUNTING STANDARDS

In April 2005, the CICA released three new Handbook sections which 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 held for trading financial instruments are recognized immediately in net income. 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.

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 realized.

Hedge accounting continues to be an option 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 October 1, 2006.

9. SUMMARY OF VARIANCES FOR 2004 COMPARED WITH 2003

Net earnings in 2004 were $1,006 million compared with $1,370 million in 2003. The decrease of $364 million was attributable to the following:

Upstream —decrease of $354 million


	•	hedging losses;

	•	higher operating costs and DD&A;

	•	higher royalties; and

	•	higher income taxes.

Partially offset by:


	•	higher crude oil and natural gas prices; and

	•	higher sales volume of heavy crude oil and natural gas.

Midstream —increase of $55 million


	•	wider upgrading differential;

	•	higher heavy crude oil pipeline throughput and tariffs;

	•	higher crude oil and NGL trading; and

	•	higher income taxes.

Partially offset by:


	•	lower upgrader throughput and sales volume;

	•	higher unit operating costs, which were primarily energy related; and

	•	lower cogeneration income.

Refined Products —increase of $9 million


	•	higher light oil product margins; and

	•	higher restaurant and convenience store income.

Partially offset by:


	•	higher depreciation and amortization; and

	•	higher income taxes.

Corporate —decrease of $74 million


	•	lower foreign exchange gains;

	•	stock-based compensation first recorded in June 2004;

	•	higher intersegment profit eliminated; and

	•	higher administration expenses.

Partially offset by:


	•	lower depreciation and amortization;

	•	lower interest expense resulting from lower rates; and

	•	higher capitalized interest resulting from a higher capital base for the White Rose project.

10. FORWARD-LOOKING STATEMENTS

This MD&A contains certainforward-looking statements relating, but not limited, to Husky’s operations, anticipated financial performance, levels of production, business prospects and strategies and which are based on our expectations, estimates, projections and assumptions and were made by us in light of experience and perception of historical trends. All statements that address expectations or projections about the future, including statements about strategy for growth, expected expenditures, commodity prices, costs, production volumes and operating or financial results, areforward-looking statements. Some of ourforward-looking statements may be identified by words like “expects”, “anticipates”, “plans”, “intends”, “believes”, “projects”, “could”, “vision”, “goal”, “objective” and similar expressions. In addition, our production forecast and our estimate of productive capacity for White Rose, Tucker and Sunrise and plans associated with our exploration programs areforward-looking statements. Our business is subject to risks and uncertainties, some of which are similar to other energy companies and some of which are unique to Husky. Our actual results may differ materially from those expressed or implied by Husky’s forward-looking statements as a result of known and unknown risks, uncertainties and other factors.

The reader is cautioned not to place undue reliance on Husky’s 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; and

	•	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.

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 the 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”. 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 National Instrument 51-101.

Husky 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 oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Husky uses certain terms in this MD&A, such as probable that the SEC’s guidelines strictly prohibit from inclusion in filings with the SEC.

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 othernon-cash items. The following table shows the reconciliation of cash flow from operations to cash flow — operating activities for the years ended December 31:


		2005			2004			2003

		($ millions)
Non-GAAP
	Cash flow from operations	$	3,785		$	2,197		$	2,430
	Settlement of asset retirement obligations		(41	)		(40	)		(34	)
	Change in non-cash working capital		(72	)		169			113

GAAP
	Cash flow — operating activities	$	3,672		$	2,326		$	2,509

13. EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Husky’s Chief Executive Officer, acting also in his capacity as Acting Chief Financial Officer, has concluded, based on his evaluation as of a date within 90 days prior to the filing of this MD&A (the “evaluation date”), that Husky’s disclosure controls and procedures are effective to ensure that information required to be disclosed by it in reports filed or submitted by it under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by it in such reports is accumulated and communicated to Husky’s management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no significant changes to Husky’s disclosure controls or in other factors that could significantly affect these controls subsequent to the evaluation date and the filing date of this MD&A.

PUBLIC SECURITIES FILINGS

You may access additional information about our Company, including our Annual Information Form, which is filed with the Canadian Securities Administrators at www.sedar.com and the Form 40-F, which is filed with the United States Securities and Exchange Commission at www.sec.gov.

EXHIBIT INDEX


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 and Acting 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 and Acting 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).

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Husky Energy (CVE+A) 40-F2005 FY Annual report (Canada)

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