2003 Annual Information Form

EX-1 3 o12154exv1.htm 2003 ANNUAL INFORMATION FORM 2003 Annual Information Form

Exhibit 1

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2003

Exhibit 1

HUSKY ENERGY INC.

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2003

March 18, 2004

TABLE OF CONTENTS


		Page

Exchange Rate Information		2
Abbreviations		3
Disclosure Exemption Under National Instrument 51-101		4
Corporate Structure
	Husky Energy Inc.	5
	Intercorporate Relationships	5
General Development of Husky
	Three Year History of Husky	6
	Business Environment Trends	7
Description of Husky’s Business
	General	8
	Social and Environmental Policy	9
	Risk Factors	9
	Upstream Operations — Disclosures for Oil and Gas Activities	11
	Supplemental Information on Oil and Gas Exploration and Production Activities	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		33
	Description of Major Properties and Facilities	35
	Distribution of Oil and Gas Production	49
	Midstream Operations	50
	Refined Products	52
	Human Resources	56
	Selected Consolidated Financial Information	56
Dividends		57
Description of Capital Structure		57
Market for Securities		57
Management’s Discussion and Analysis of Financial Condition and Results of Operations		59
Directors and Officers		60
Legal Proceedings		63
Interest of Management and Others in Material Transactions		63
Transfer Agent and Registrars		64
Additional Information		64
Special Note Regarding Forward-looking Statements		64
2003 Annual Information Form
2003 Consolidated Audited Financial Statements
2003 Management's Discussion and Analysis
Certification of CEO
Certification of CFO
Certification of CEO - Sarbanes Oxley Act
Certification of CFO - Sarbanes Oxley Act
Consent of Independent Chartered Accountants
Consent of Independent Engineers

EXCHANGE RATE INFORMATION

Except where otherwise indicated, all dollar amounts stated in this Annual Information Form 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,

	2003		2002		2001

Year end		1.292		1.580		1.593
Low		1.292		1.519		1.499
High		1.575		1.605		1.593
Average		1.386		1.570		1.551

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.

ABBREVIATIONS

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


Units of Measure

Bbl Bbls mbbls mmbbls Bbls/day mbbls/day Boe boe/day Mcf mmcf Bcf mmcf/day mcfge lt mlt lt/day mlt/day mmbtu MW		-barrel -barrels -thousand barrels -million barrels -barrels per calendar day -thousand barrels per calendar day -barrels of oil equivalent -barrels of oil equivalent per calendar day -thousand cubic feet -million cubic feet -billion cubic feet -million cubic feet per calendar day -thousand cubic feet of gas equivalent -long ton -thousand long tons -long tons per calendar day -thousand long tons per calendar day -million British thermal units -megawatts


Acronyms

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

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. The reader is cautioned that a boe conversion rate of six to one is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

DISCLOSURE 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, Husky applied for and was 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 Husky to substitute disclosures required by and consistent with those of the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) in the United States 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 Husky’s oil and gas activities in this Annual Information Form are presented in accordance with the following requirements:

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

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

• SEC Industry Guide 2;

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

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

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

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

NI 51-101 specifies that proved reserves be in accordance with the COGE Handbook definitions. There were no material differences between the oil and gas reserves determined and evaluated using the SEC definitions and the COGE Handbook 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. 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.

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 not to approach the SEC rules and regulations as merely a blank form but encourages registrants to provide such additional information that is necessary to further an investor’s understanding of the registrant’s business.

Husky believes that it’s reserves evaluators are qualified and it has a well established reserves evaluation process that is at least as rigorous as would be the case were it to rely upon independent reserves evaluators. Husky has adopted written evaluation practices and procedures using the COGE Handbook modified to the extent necessary to reflect the definitions and standards under U.S. disclosure requirements.

CORPORATE STRUCTURE

Husky Energy Inc.

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

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

In this Annual Information Form the term “Husky” or “the Company” means Husky Energy 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% owned.


Name		Jurisdiction


Subsidiaries of Husky Energy Inc. Husky Oil Operations Limited Subsidiaries of Husky Oil Operations Limited Husky Oil Limited Husky Energy Marketing Inc. Husky (U.S.A.) Inc. HOI Resources Co. Husky Energy International Sulphur Corporation 147212 Canada Ltd.		Alberta Canada Alberta Delaware Nova Scotia Alberta Canada


Name		Jurisdiction


Subsidiaries of Husky (U.S.A.) Inc. Husky Gas Marketing Inc. Subsidiaries of HOI Resources Co. Husky Energy International Corporation Subsidiaries of Husky Energy International Corporation Husky Oil China Ltd. Husky Oil (Madura) Ltd. Husky Oil Overseas Ltd.		Delaware Alberta Alberta Alberta Alberta

GENERAL DEVELOPMENT OF HUSKY

Three Year History

On July 4, 2001, Husky acquired all of the outstanding Class A Common Shares and Class B Common Shares of Avid Oil & Gas Ltd. (“Avid”), which it did not already own, pursuant to an offer to purchase dated March 23, 2001. The acquisition of Avid was completed pursuant to a Pre-Acquisition Agreement which provided for the acquisition of the Class A Common Shares of Avid at a price of $5.85 per share and the Class B Common Shares of Avid at a price of $10.00 per share for a total consideration of approximately $82.6 million. Husky had previously owned approximately 38% of the Class A Common Shares of Avid as a result of the acquisition of Renaissance in August 2000.

In December 2001, the White Rose project had received government sanction from the Canada-Newfoundland Offshore Petroleum Board and the Provincial and Federal governments. In March 2002, Husky and its co-venturer announced that they had decided to proceed with the development of the White Rose oil field.

In January 2002, the Terra Nova development project commenced production. This project was the first Grand Banks field to be developed with a floating production, storage and offloading system. In addition, the first well in the Terra Nova Far East block was successfully drilled in 2001.

In June 2002, Husky issued U.S. $400 million of 6.25% senior notes due June 15, 2012. The notes were sold at a discount price of 99.545% per note to yield 6.312%. The notes were issued under a U.S. $1 billion base shelf prospectus dated June 6, 2002. The proceeds were used to repay existing bank indebtedness and for general corporate purposes.

On July 7, 2002, the Wenchang oil fields, 13-1 and 13-2, produced first oil. These oil fields produce light crude oil similar to the benchmark Minas blend from two production platforms into a floating production, storage and offloading vessel stationed between the two fields.

In September 2002, Husky signed contracts with the China National Offshore Oil Corporation (“CNOOC”) for two exploration blocks in the South China Sea. The 23/15 block comprises 1,327 square kilometres and the 23/20 block comprises 1,543 square kilometres. The contracts require one well to be drilled on each block within three years.

In November 2002, Husky announced a significant discovery of natural gas at Shackleton, Saskatchewan. The Company announced that development of the Shackleton area could add 250 bcf to proved reserves within two to three years. Husky held more than 400 sections of land comprising 300,000 acres in this area in 2002.

In December 2002, Husky signed a contract with CNOOC for the 40/30 exploration block in the South China Sea. The block comprises approximately 6,704 square kilometres and the contract requires one well to be drilled within three years.

In December 2002, Husky swapped, with its co-venturer, its working interest in the mining portion of its Kearl oil sands property for its co-venturer’s interest in the in-situ portion of the property. As a result Husky now holds 100% working interest in 57,600 acres of lands with in-situ potential. Husky’s property has been named “Sunrise.”

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 north-eastern British Columbia. The acquisition added approximately 39.8 mmboe of gross proved reserves, of which 75% 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.

In November 2003, Husky 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.

Business Environment Trends

There are a number of trends that appear to be developing, which may have both long and short-term effects on the oil and gas industry. The Western Canada Sedimentary Basin continues to mature and a large number of major producing regions have been highly developed, thereby reducing the exploration opportunities in this area.

There is a continued trend relating to the volatility of commodity prices. It appears that natural gas prices have entered an era of extreme volatility. With the supply and demand balance for natural gas being extremely tight, the market is experiencing a great deal of elasticity in pricing due to a number of factors, including weather, drilling activity, declines, storage levels, fuel switching and demand.

Oil prices are clearly dependent on the world economy and the reaction of OPEC to demand. OPEC’s stated position is to maintain its average basket price between U.S.$22.00-$28.00 per bbl and, if successful, will remove some volatility in the WTI price. This does not, however, affect a major oil trend developing in Canada. The trend in Canada involves increasing production of heavy oil that is priced at a differential to WTI. This differential is presently wide but as the North American refineries are forced to accept more of the heavy crude there should be a narrowing of the differential. This may result in a trend that will see heavy crude priced at a differential that will only include the price of diluent to move the produce from the delivery point to the refineries.

DESCRIPTION OF HUSKY’S BUSINESS

General

Husky is a publicly held integrated energy and energy related company headquartered in Calgary, Alberta. Husky’s 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 that produce light (30 API and lighter), medium (between 20 and 30 API) and heavy (below 20 and above 10 API) gravity crude oil, NGL, natural gas and sulphur. As operator of the majority of its properties Husky exercises a high degree of control in its upstream operations. Husky has production, gathering and processing facilities throughout the Western Canada Sedimentary Basin. 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.

At December 31, 2003, Husky was the operator of properties which accounted for approximately 87% of its total gross production in Western Canada. Husky’s undeveloped landholdings in the Western Canada Sedimentary Basin totalled 7.3 million net acres at December 31, 2003.

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

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

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

Husky has extensive experience in development, production, transportation and upgrading of heavy crude oil. Husky also has experience in enhanced recovery of crude oil and horizontal drilling, as well as in natural gas exploration in the deep basin, foothills and along the eastern slopes of the Canadian Rocky Mountains, also known as the overthrust belt.

On the east coast of Canada Husky holds a 12.51% working interest in the Terra Nova oil field, which began producing light crude oil in January 2002, and a 72.5% working interest in the White Rose oil field, which was sanctioned by the co-venturers in March 2002 and is currently under development. First oil from the White Rose oil field is currently expected by the end of 2005 or early 2006. Husky also holds interests in several exploration and significant discovery licenses in the Jeanne d’Arc Basin and the South Whale Basin.

Husky holds a 40% working interest in the Wenchang oil fields located offshore in the South China Sea. Production at the Wenchang oil fields began in July 2002. Husky also holds interests in four exploration blocks in the South China Sea with an aggregate areal extent of approximately 15,000 square kilometres and one exploration block in the East China Sea of approximately 4,800 square kilometres.

Husky also holds an interest in a natural gas and liquids PSC located in the Madura strait offshore Java, Indonesia.

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 and for continued compliance with environmental legislation and minimize future and current costs. Husky’s policies apply equally to employees, subsidiaries and contractors.

Risk Factors

The following factors should be considered in evaluating Husky:

Adequacy of crude oil and natural gas prices

Husky’s results of operations and financial condition are dependent on the prices received for its crude oil and natural gas production.

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 OPEC and their adherence to agreed production quotas, non-OPEC crude oil supply, social conditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, prevailing weather patterns and the availability of alternate sources of energy.

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

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

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

Husky’s ability to replace reserves

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

Competition

The energy industry is highly competitive. 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 competitors comprise all types of energy companies, some of which have greater resources.

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 at its operations of green house gases such as carbon dioxide, which may increase capital expenditures, details regarding the implementation of the Kyoto Protocol remain unclear.

Uncertainty of oil and gas proved reserves estimates

There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves, including many factors beyond Husky’s control. The reserves information included in and incorporated by reference in this Annual Information Form are Husky’s estimates. In general, estimates of economically recoverable oil and natural gas reserves and the estimated future net cash flow therefrom are based on a number of variables in effect as of 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 the estimated oil and natural gas reserves will likely 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

Production

The following table shows Husky’s average gross and net daily production of crude oil and NGL and natural gas for the periods indicated:



	2003

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	Crude oil — mbbls/day
	Natural gas — mmcf/day
*Crude Oil*
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*
Gross		610.6		610.6		—		610.6		—		—

Net		473.7		473.7		—		473.7		—		—



	2002

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	Crude oil — mbbls/day
	Natural gas — mmcf/day
*Crude Oil*
Light crude oil and NGL		65.4		39.8		13.2		53.0		12.2		0.2
Medium crude oil		44.8		44.8		—		44.8		—		—
Heavy crude oil		95.1		95.1		—		95.1		—		—

Total gross		205.3		179.7		13.2		192.9		12.2		0.2

Total net		179.3		154.8		12.8		167.6		11.5		0.2

*Natural Gas*
Gross		569.2		569.2		—		569.2		—		—

Net		426.6		426.6		—		426.6		—		—



	2001

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	Crude oil — mbbls/day
	Natural gas — mmcf/day
*Crude Oil*
Light crude oil and NGL		46.4		46.1		—		46.1		—		0.3
Medium crude oil		47.2		47.2		—		47.2		—		—
Heavy crude oil		83.8		83.8		—		83.8		—		—

Total gross		177.4		177.1		—		177.1		—		0.3

Total net		154.4		154.1		—		154.1		—		0.3

*Natural Gas*
Gross		572.6		572.6		—		572.6		—		—

Net		417.8		417.8		—		417.8		—		—

Notes:

(1) Light crude oil includes crude oil that is lighter than 30 API, medium crude oil is between 20 and 30 API gravity and heavy crude oil includes crude oil that is lower than 20 API and lighter than 10 API gravity in the Lloydminster area.

(2) 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

The following table shows the revenue by upstream product group for the years indicated:



	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		—		—



	2002

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	($ millions)
*Crude Oil*
Light crude oil and NGL		866		494		171		665		198		3
Medium crude oil		496		496		—		496		—		—
Heavy crude oil		924		924		—		924		—		—

Total gross		2,286		1,914		171		2,085		198		3

Total net		1,974		1,616		169		1,785		186		3

*Natural Gas*
Gross		801		801		—		801		—		—

Net		653		653		—		653		—		—

Processing		38		38		—		38		—		—



	2001

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	($ millions)
*Crude Oil*
Light crude oil and NGL		561		557		—		557		—		4
Medium crude oil		408		408		—		408		—		—
Heavy crude oil		521		521		—		521		—		—

Total gross		1,490		1,486		—		1,486		—		4

Total net		1,249		1,245		—		1,245		—		4

*Natural Gas*
Gross		1,142		1,142		—		1,142		—		—

Net		882		882		—		882		—		—

Processing		35		35		—		35		—		—

Note:

Sales Prices

The following table shows the Company’s average sales prices, before and after the effect of production hedging, for light crude oil and NGL, medium crude oil, heavy crude oil and natural gas for the periods indicated.



	2003

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	$/bbl

	$/mcf
*Crude Oil*
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*
Before hedging		5.86		5.86		—		5.86		—		—

After hedging		5.94		5.94		—		5.94		—		—



	2002

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	$/bbl

	$/mcf
*Crude Oil*
Light crude oil and NGL		36.17		33.86		35.47		34.26		44.36		40.37
Medium crude oil		30.16		30.16		—		30.16		—		—
Heavy crude oil		26.60		26.60		—		26.60		—		—
Total crude oil and NGL (before hedging)		30.47		29.14		35.47		29.57		44.36		40.37

Total crude oil and NGL (after hedging)		30.50		29.17		35.47		29.61		44.36		40.37

*Natural Gas*
Before hedging		3.83		3.83		—		3.83		—		—

After hedging		3.83		3.83		—		3.83		—		—



	2001

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	$/bbl

	$/mcf
*Crude Oil*
Light crude oil and NGL		33.15		33.13		—		33.13		—		37.72
Medium crude oil		23.69		23.69		—		23.69		—		—
Heavy crude oil		17.02		17.02		—		17.02		—		—
Total crude oil and NGL (before hedging)		23.01		22.99		—		22.99		—		37.72

Total crude oil and NGL (after hedging)		23.01		22.99		—		22.99		—		37.72

*Natural Gas*
Before hedging		5.47		5.47		—		5.47		—		—

After hedging		5.47		5.47		—		5.47		—		—

Note:

Capital Expenditures

The following table shows the dollar amounts expended by the Company on property acquisitions, exploration and development for the periods indicated:



	2003

			Western		East
	Total		Canada		Coast		Canada		China		Indonesia		Libya


	($ millions)
Property acquisition (1)		75		75		—		75		—		—		—
Exploration		324		274		24		298		26		—		—
Development		1,382		849		533		1,382		—		—		—



	2002

			Western		East
	Total		Canada		Coast		Canada		China		Indonesia		Libya


	($ millions)
Property acquisitions		108		108		—		108		—		—		—
Exploration		266		216		41		257		9		—		—
Development		1,193		710		417		1,127		66		—		—



	2001

			Western		East
	Total		Canada		Coast		Canada		China		Indonesia		Libya


	($ millions)
Property acquisitions (2)		177		177		—		177		—		—		—
Exploration		267		181		81		262		5		—		—
Development		873		664		110		774		99		—		—

Notes:

(1) Does not include the acquisition of Marathon.

(2) Does not include the acquisition of Titanium Oil & Gas Ltd. and Avid

Oil and Gas Netbacks⁽¹⁾

The following table shows the Company’s average netback for operations classified as light, medium and heavy crude oil operations, and natural gas operations for the periods indicated. The classification is based on the oil/gas ratio such that predominantly oil leases are classified with oil operations and predominantly natural gas leases are classified with natural gas operations.



	2003

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	$/bbl

	$/mcf
*Crude Oil*
*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

Netback after hedging		29.49		22.80		32.99		26.50		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		—		—
Net back before hedging		16.76		16.76		—		16.76		—		—

Netback after hedging		14.97		14.97		—		14.97		—		—

*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		—		—

Netback after 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*
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		—		—

Note:

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



	2002

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	$/bbl

	$/mcf
*Crude Oil*
*Light crude oil*
Sales revenue		36.22		33.66		35.47		34.15		44.36		40.37
Royalties		3.25		4.55		0.36		3.41		2.65		—
Operating costs		7.33		10.46		3.62		8.60		2.15		13.13
Netback before hedging		25.64		18.65		31.49		22.14		39.56		27.24

Netback after hedging		25.74		18.82		31.49		22.26		39.56		27.24

*Medium crude oil*
Sales revenue		29.92		29.92		—		29.92		—		—
Royalties		5.59		5.59		—		5.59		—		—
Operating costs		7.19		7.19		—		7.19		—		—
Netback before hedging		17.14		17.14		—		17.14		—		—

Netback after hedging		17.33		17.33		—		17.33		—		—

*Heavy crude oil*
Sales revenue		26.48		26.48		—		26.48		—		—
Royalties		3.45		3.45		—		3.45		—		—
Operating costs		7.18		7.18		—		7.18		—		—
Net back before hedging		15.85		15.85		—		15.85		—		—

Netback after hedging		15.85		15.85		—		15.85		—		—

*Total crude oil*
Sales revenue		30.19		28.81		35.47		29.26		44.36		40.37
Royalties		3.87		4.22		0.36		3.96		2.65		—
Operating costs		7.23		7.84		3.62		7.54		2.15		13.13
Netback before hedging		19.09		16.75		31.49		17.76		39.56		27.24

Netback after hedging		19.16		16.83		31.49		17.84		39.56		27.24

*Natural Gas*
Sales revenue		3.97		3.97		—		3.97		—		—
Royalties		0.81		0.81		—		0.81		—		—
Operating costs		0.70		0.70		—		0.70		—		—
Netback before hedging		2.46		2.46		—		2.46		—		—

Netback after hedging		2.46		2.46		—		2.46		—		—

Note:



	2001

			Western		East
	Total		Canada		Coast		Canada		China		Libya


	$/bbl

	$/mcf
*Crude Oil*
*Light crude oil*
Sales revenue		34.28		34.25		—		34.25		—		37.72
Royalties		5.72		5.76		—		5.76		—		—
Operating costs		8.19		8.15		—		8.15		—		14.56
Netback before hedging		20.37		20.34		—		20.34		—		23.16

Netback after hedging		20.37		20.34		—		20.34		—		23.16

*Medium crude oil*
Sales revenue		23.86		23.86		—		23.86		—		—
Royalties		4.39		4.39		—		4.39		—		—
Operating costs		7.18		7.18		—		7.18		—		—
Netback before hedging		12.29		12.29		—		12.29		—		—

Netback after hedging		12.29		12.29		—		12.29		—		—

*Heavy crude oil*
Sales revenue		17.20		17.20		—		17.20		—		—
Royalties		1.93		1.93		—		1.93		—		—
Operating costs		7.40		7.40		—		7.40		—		—
Netback before hedging		7.87		7.87		—		7.87		—		—

Netback after hedging		7.87		7.87		—		7.87		—		—

*Total crude oil*
Sales revenue		23.13		23.09		—		23.09		—		37.72
Royalties		3.52		3.52		—		3.52		—		—
Operating costs		7.53		7.51		—		7.51		—		14.56
Netback before hedging		12.08		12.06		—		12.06		—		23.16

Netback after hedging		12.08		12.06		—		12.06		—		23.16

*Natural Gas*
Sales revenue		5.39		5.39		—		5.39		—		—
Royalties		1.30		1.30		—		1.30		—		—
Operating costs		0.58		0.58		—		0.58		—		—
Netback before hedging		3.51		3.51		—		3.51		—		—

Netback after hedging		3.51		3.51		—		3.51		—		—

Note:

Producing Wells

The following table presents the number of wells that were producing or capable of producing at December 31, 2003 and 2002 in which Husky held a working interest:



		Oil Wells				Natural Gas Wells				Total

		Gross (1)(2)		Net (1)		Gross (1)(2)		Net (1)		Gross (1)(2)		Net (1)

Canada
	Alberta		5,098		3,410		5,660		2,877		10,758		6,287
	Saskatchewan		4,835		3,596		675		422		5,510		4,018
	British Columbia		211		63		111		48		322		111
	Manitoba		2		1		—		—		2		1
	Newfoundland		8		1		—		—		8		1

			10,154		7,071		6,446		3,347		16,600		10,418
International
	China		21		8		—		—		21		8
	Libya		2		1		—		—		2		1

			23		9		—		—		23		9

As at December 31, 2003			10,177		7,080		6,446		3,347		16,623		10,427

Canada
	Alberta		5,129		3,491		4,382		2,128		9,511		5,619
	Saskatchewan		4,568		3,276		479		261		5,047		3,537
	British Columbia		200		56		27		11		227		67
	Manitoba		3		1		—		—		3		1
	Newfoundland		6		1		—		—		6		1

			9,906		6,825		4,888		2,400		14,794		9,225
International
	China		21		8		—		—		21		8
	Libya		2		1		—		—		2		1

			23		9		—		—		23		9

As at December 31, 2002			9,929		6,834		4,888		2,400		14,817		9,234

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.

(2) 2003 includes 271 gross, 241 net oil wells and 424 gross, 207 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.

2002 includes 197 gross oil wells and 278 gross 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.

Landholdings

The following table presents Husky’s developed acreage as at December 31, 2003 and 2002:



		Developed Acreage

		Gross		Net


		(thousands of acres)
As at December 31, 2003
Western Canada
	Alberta		3,208		2,684
	Saskatchewan		550		485
	British Columbia		161		92
	Manitoba		1		1

			3,920		3,262
Eastern Canada			35		4

Total Canada			3,955		3,266

China			17		7
Libya			7		2

			3,979		3,275

As at December 31, 2002
Western Canada
	Alberta		2,863		2,443
	Saskatchewan		523		465
	British Columbia		101		63
	Manitoba		1		1

			3,488		2,972
Eastern Canada			35		4

Total Canada			3,523		2,976

China			17		7
Libya			7		2
			3,547		2,985

The following table presents Husky’s undeveloped acreage as at December 31, 2003 and 2002:



		Undeveloped Acreage

		Gross		Net


		(thousands of acres)
As at December 31, 2003
Western Canada
	Alberta		5,508		4,852
	Saskatchewan		2,057		1,911
	British Columbia		713		491
	Manitoba		9		8

			8,287		7,262
Northwest Territories and Arctic			527		184
Eastern Canada			2,414		2,104

Total Canada			11,228		9,550
International			4,464		2,066

			15,692		11,616

As at December 31, 2002
Western Canada
	Alberta		5,416		4,907
	Saskatchewan		2,098		1,986
	British Columbia		314		273
	Manitoba		13		13

			7,841		7,179
Northwest Territories and Arctic			463		175
Eastern Canada			2,414		2,104

Total Canada			10,718		9,458
International			4,464		2,066

			15,182		11,524

Drilling Activity

Husky’s gross and net exploratory and development drilling activities in Western Canada for the years ended December 31, 2003, 2002 and 2001 are set forth below:



		Year ended December 31


		2003				2002				2001

		Gross		Net		Gross		Net		Gross		Net

Western Canada Drilling
Exploration
	Oil		12		11		21		20		78		76
	Gas		147		124		139		131		102		90
	Dry		22		21		15		14		36		34

			181		156		175		165		216		200

Development
	Oil		520		490		497		453		594		542
	Gas		540		518		485		453		251		221
	Dry		60		57		58		55		68		63

			1,120		1,065		1,040		961		913		826

			1,301		1,221		1,215		1,126		1,129		1,026

The following table presents the number of gross and net exploratory and development wells that were drilling at December 31, 2003:

Present Activities



	Exploratory			Development

Wells Drilling	Gross		Net	Gross		Net

Western Canada		8	6.750		17	15.150
East Coast		—	—		1	0.175
China		—	—		—	—

		8	6.750		18	15.325

Reserves Data and Other Information

Husky’s oil and gas reserves as of December 31, 2003 are based on constant prices and costs as prepared internally by Husky’s engineers. 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 technical experts.

Reserves Reported to Other Agencies

There have been no reserves reported to any U.S. federal authority or agency since the beginning of the last fiscal year.

Audit of Oil and Gas Reserves

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 COGE Handbook.

Oil and Gas Reserves Data

The following table presents in summary Husky’s proved developed reserves, proved undeveloped reserves and associated future net cash flows as at December 31, 2003. Future revenues, based on constant prices and costs, are presented net of royalties. Estimated future net revenues based on constant prices and costs 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.



									Future Net
									Cash Flows
	Crude oil & NGL				Natural Gas				Before Tax (3)(4)

	Gross (1)		Net (1)		Gross (1)		Net (1)		0%		10%


	(mmbbls)				(bcf)				($ millions)
Proved developed (2)		442.1		394.5		1,712.4		1,422.9		13,930		8,232
Proved undeveloped (2)		102.2		91.0		346.5		293.7		2,209		1,144

Proved total (2)		544.3		485.5		2,058.9		1,716.6		16,139		9,376

Notes:

(1) 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.

(2) These reserve categories have the same meanings as those set out in SEC Regulation S-X.

(3) The discounted future net cash flows at December 31, 2003 were based on the year-end spot NYMEX natural gas price of U.S. $5.96/mmbtu and on a spot WTI crude oil price of U.S. $32.51/bbl.

(4) Future Development Costs



	As at December 31, 2003

	Total		2004		2005		2006		2007		2008		Thereafter


	($ millions undiscounted)
Western Canada		1,229		366		241		108		68		49		397
Eastern Canada		39		28		4		3		1		—		3
China		—		—		—		—		—		—		—
Indonesia		—		—		—		—		—		—		—

		1,265		338		245		111		69		49		400



	As at December 31, 2002

	Total		2003		2004		2005		2006		2007		Thereafter

Western Canada		1,100		325		160		116		63		56		380
Eastern Canada		41		32		2		2		1		2		2
China		—		—		—		—		—		—		—
Indonesia		154		—		41		73		40		—		—

		1,295		357		203		191		104		58		382

Future development costs include estimated development capital expenditures necessary to gain access to proved undeveloped reserves.

Reserves and Production by Principal Area

Husky’s estimate of its proved reserves by area as of December 31, 2003 and daily average production of crude oil, NGL and natural gas by area are as follows:


Crude Oil and NGL			Proved Reserves		Production

			(mmbbls)		(mbbls/day)
Western Canada
	British Columbia and Foothills
		Alberta and BC Plains area		31.8		6.4
		Foothills Deep Gas area		24.0		7.1
		Ram River and Kaybob areas		6.5		2.0
	Northwest Alberta Plains
		Rainbow Lake area		85.0		7.8
		Peace River Arch area		11.2		3.4
	East Central Alberta
		Provost area		33.8		20.8
		North area		2.0		0.7
		South area		6.4		2.7
	Southern Alberta and Saskatchewan
		South Alberta area		21.8		11.7
		South Saskatchewan area		76.1		18.4
	Lloydminster Area
		Primary production		132.3		75.0
		Thermal production		62.6		14.8
	Other			0.7		0.6

				494.2		171.4

East Coast Canada
	Terra Nova			25.7		16.8
China
	Wenchang			23.9		22.4
Libya
	Shatirah			0.5		0.1

				544.3		210.7


Natural Gas			Proved Reserves		Production

			(bcf)		(mmcf/day)
Western Canada
	British Columbia and Foothills
		Alberta and BC Plains area		153.1		34.9
		Foothills Deep Gas area		262.0		101.5
		Ram River and Kaybob areas		275.2		67.2
	Northwest Alberta Plains
		Rainbow Lake area		295.4		35.9
		Peace River Arch		68.6		22.0
		Northern Alberta area		313.9		101.1
	East Central Alberta
		Provost area		57.8		12.2
		North area		142.8		52.8
		South area		164.8		53.6
	Southern Alberta and Saskatchewan
		South Alberta area		61.5		19.6
		South Saskatchewan area		173.2		53.8
	Lloydminster Area			80.8		51.2
	Other			9.8		4.8

				2,058.9		610.6

The following tables present Husky’s finding and development costs for Western Canada and for the total Company for each of the three years ended December 31, 2003 and the aggregate average finding and development costs for the three year period:

Finding and Development Costs



	Year ended December 31,

Western Canada (1)	2003 - 2001		2003		2002		2001

Total capitalized costs ($ millions)		3,019.1		1,132.7		994.2		892.2
Proved reserve additions and revisions (mmboe)		284.3		76.6		94.8		112.9

Average costs per boe		10.62		14.79		10.49		7.90

Note:

(1) Excludes oil sands and acquisitions/divestitures.



	Year ended December 31,

Total Company	2003 - 2001		2003		2002		2001

Total capitalized costs ($ millions)		4.370.5		1.705.6		1,520.8		1,144.1
Proved reserve additions and revisions (mmboe)		284.0		49.1		114.5		120.4

Average costs per boe		15.39		34.74		13.28		9.50

The following table presents Husky’s total crude oil, NGL and natural gas probable reserves for each of the three years ended December 31, 2003, 2002 and 2001:

Probable Oil and Gas Reserves⁽¹⁾



	Crude Oil & NGL								Natural Gas

Probable	Western Canada		East coast		International		Total		Western Canada		International		Total


	(mmbbls)								(bcf)
2003		246.1		182.2		7.0		435.3		381.3		66.5		447.8
2002		246.4		201.6		4.2		452.2		383.9		18.9		402.8
2001		213.0		213.3		4.2		430.5		405.6		18.9		424.5

Notes:

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

(2) 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 pursuant to an exemption order granted with respect to Part 8 of NI 51-101.

(3) Bitumen probable reserves are included under the caption Western Canada.

Supplemental Information on Oil and Gas Exploration and Production Activities

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

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

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 the Company’s estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Company’s share of future production from Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2003, 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

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas producing activities for the years ended December 31:



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

Results of operations		2003		2002		2001		2003		2002		2001			2003		2002		2001


		($ millions except per boe amounts)
Revenue
	Sales		2,090		1,738		1,771		310		190		4			2,400		1,928		1,775
	Transfers		786		737		390		—		—		—			786		737		390

			2,876		2,475		2,161		310		190		4			3,186		2,665		2,165

Operating expenses
	Productions costs		794		676		617		17		10		—			811		686		617
	Depletion, depreciation and amortization		892		813		721		66		38		7			958		851		728
	Income taxes		527		387		334		102		64		(1	)		629		451		333

Total			2,213		1,876		1,672		185		112		6			2,398		1,988		1,678

			663		599		489		125		78		(2	)		788		677		487

Amortization rate in dollars per gross boe			8.43		7.74		7.24		8.00		8.33		80.61			8.40		7.76		7.31

Note:

(1) The costs in this schedule exclude corporate overhead, interest expense and other operating costs, which are not directly related to producing activities.

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

Capitalized costs incurred in oil and gas producing activities for the years ended December 31 were as follows:


Costs Incurred		2003		2002		2001


		($ millions)
Property acquisition
	Proved (1) — Canada		541		20		366
	Unproved — Canada		106		88		55

			647		108		421

	Exploration — Canada		298		257		262
	— Other		26		9		5

			324		266		267

Development — Canada			1,381		1,127		774
	— China		—		66		99

			1,381		1,193		873

			2,352		1,567		1,561

Note:

(1) Property acquisition costs related to corporate acquisitions for proved properties in 2003 included $517 million; 2002 — nil; 2001 included $244 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 and facilities to extract, treat and gather and store oil and gas.

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, 2003, by the year in which the costs were incurred:


										Prior to
Withheld Costs		Total		2003		2002		2001		2001


		($ millions)
Property acquisitions
	Canada		406		56		37		17		296
	International		14		—		—		—		14

			420		56		37		17		310

Exploration
	Canada		324		131		40		57		96
	International		22		16		6		—		—

			346		147		46		57		96

Development
	Canada		886		477		392		17		—
	International		18		1		—		—		17

			904		478		392		17		17

Capitalized interest
	Canada		198		52		26		51		69

			1,868		733		501		142		492

Capitalized Costs Relating to Oil and Gas Producing Activities

The capitalized costs and related accumulated depletion, depreciation and amortization, including impairments, relating to the Company’s oil and gas exploration, development and producing activities at December 31 consisted of:


Capitalized Costs		2003		2002		2001 (1)


		($ millions)
Unproved oil and gas properties
	Canada		1,814		1,318		1,052
	International		54		37		235

			1,868		1,355		1,287

Proved oil and gas properties
	Canada		11,787		10,207		9,301
	International		442		432		159

			12,229		10,639		9,460

			14,097		11,994		10,747

Less accumulated depletion, depreciation and amortization
	Canada		4,633		3,894		3,272
	International		250		185		147

			4,883		4,079		3,419

			9,214		7,915		7,328

Net capitalized costs
	Canada		8,968		7,631		7081
	International		246		284		247

			9,214		7,915		7,328

Note:

(1) Capital related to 17 mmbbls of proved reserves at Terra Nova transferred to proved oil and gas properties. In 2001, Terra Nova was a major development project off the East Coast of Canada.

Oil and Gas Reserve Information

In Canada, the Company’s proved crude oil, natural gas liquids, natural gas and sulphur reserves are located in the provinces of Alberta, Saskatchewan and British Columbia, and offshore the East Coast. The Company’s international proved reserves are located in China and Libya. The Company’s proved developed and undeveloped reserves after deductions of royalties are summarized below:



		Canada									International						Total

		Crude			Natural						Crude			Natural			Crude			Natural
Reserves		Oil & NGL			Gas			Sulphur			Oil & NGL			Gas			Oil & NGL			Gas			Sulphur

		(mmbbls)			(bcf)			(mmlt)			(mmbbls)			(bcf)			(mmbbls)			(bcf)			(mmlt)
Net proved developed and undeveloped reserves, after royalties (1)(2)(3)(4)
End of year 2000			445.5			1,434.6			4.7			35.1			110.1			480.6			1,544.7			4.7
	Revisions		37.0			74.0			0.1			0.7			5.1			37.7			79.1			0.1
	Purchases		33.6			20.4			—			—			—			33.6			20.4			—
	Sales		(1.6	)		(18.4	)		—			—			—			(1.6	)		(18.4	)		—
	Discoveries and extensions		44.8			200.1			0.1			1.1			—			45.9			200.1			0.1
	Production		(56.3	)		(152.1	)		(0.2	)		(0.1	)		—			(56.4	)		(152.1	)		(0.2	)

End of year 2001			503.0			1,558.6			4.7			36.8			115.2			539.8			1,673.8			4.7
	Revisions		—			14.7			0.3			(0.8	)		(14.3	)		(0.8	)		0.4			0.3
	Purchases		4.2			5.4			—			—			—			4.2			5.4			—
	Sales		(14.5	)		(16.6	)		—			—			—			(14.5	)		(16.6	)		—
	Discoveries and extensions		37.2			205.4			—			1.1			—			38.3			205.4			—
	Production		(61.8	)		(155.7	)		(0.4	)		(4.3	)		—			(66.1	)		(155.7	)		(0.4	)

End of year 2002			468.1			1,611.8			4.6			32.8			100.9			500.9			1,712.7			4.6
	Revisions		18.4			(88.9	)		0.1			(2.8	)		(100.9	)		15.6			(189.8	)		0.1
	Purchases		9.2			146.2			—			—			—			9.2			146.2			—
	Sales		(4.2	)		(15.9	)		(0.1	)		—			—			(4.2	)		(15.9	)		(0.1	)
	Discoveries and extensions		32.6			245.6			0.1			—			—			32.6			245.6			0.1
	Production		(61.1	)		(182.2	)		(0.5	)		(7.5	)		—			(68.6	)		(182.2	)		(0.5	)

End of year 2003			463.0			1,716.6			4.2			22.5			—			485.5			1,716.6			4.2

Net proved developed reserves, after royalties (1)(2)(3)(4)
	End of year 2000		345.2			1,275.5			4.5			0.5			—			345.7			1,275.5			4.5
	End of year 2001		378.1			1,342.2			4.6			0.6			—			378.7			1,342.2			4.6
	End of year 2002		360.9			1,272.8			3.7			28.2			—			389.1			1,272.8			3.7
	End of year 2003		372.0			1,422.9			3.8			22.5			—			394.5			1,422.9			3.8

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 the engineering staff of the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company 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 the Company’s reserves.

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

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

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2003 was based on the NYMEX year-end natural gas spot price of U.S. $5.96/mmbtu (2002 — U.S. $4.60/mmbtu; 2001 — U.S. $2.75/mmbtu) and on crude oil prices computed with reference to the year-end WTI price of U.S. $32.51/bbl (2002 — U.S. $31.21/bbl; 2001 — U.S. $19.96/bbl). The price of WTI in Canadian dollars was lower December 31, 2003 than at December 31, 2002 as a result of the Cdn./ U.S. dollar exchange rate, which was $1.29 at December 31, 2003 compared with $1.58 at December 31, 2002.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s proved crude oil and natural gas reserves at December 31, for the years presented:



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

Standardized Measure		2003		2002		2001		2003		2002		2001		2003		2002		2001


		($ millions)
Future cash inflows			24,003		25,830		14,102		928		2,719		1,600		24,931		28,549		15,702
Future costs
	Future production and development costs		8,645		7,239		7,541		146		502		523		8,791		7,741		8,064
	Future income taxes		5,696		7,278		2,540		247		860		310		5,943		8,138		2,850

Future net cash flows			9,662		11,313		4,021		535		1,357		767		10,197		12,670		4,788
Deduct 10% annual discount factor			4,242		4,966		1,667		117		518		329		4,359		5,484		1,996

Standardized measure of discounted Future net cash flows			5,420		6,347		2,354		418		839		438		5,838		7,186		2,792

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.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating

to Proved Oil and Gas Reserves

The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented.



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

Changes in Standardized Measure	2003			2002			2001			2003			2002			2001			2003			2002			2001


	($ millions)
Present value at January 1		6,347			2,354			5,462			839			438			372			7,186			2,792			5,834
Sales and transfers, net of production costs		(2,097	)		(1,802	)		(1,556	)		(293	)		(179	)		(2	)		(2,390	)		(1,981	)		(1,558	)
Net change in sales and transfer prices, net of development and production costs		(1,379	)		7,752			(5,843	)		(376	)		732			(48	)		(1,755	)		8,484			(5,891	)
Extensions, discoveries and improved recovery, net of related costs		541			676			356			—			40			17			541			716			373
Revisions of quantity estimates		76			(30	)		237			(97	)		(28	)		10			(21	)		(58	)		247
Accretion of discount		1,055			390			949			130			59			55			1,185			449			1,004
Sale of reserves in place		(47	)		(189	)		(6	)		—			—			—			(47	)		(189	)		(6	)
Purchase of reserves in place		304			45			174			—			—			—			304			45			174
Changes in timing of future net cash flows and other		(237	)		(191	)		95			(49	)		80			10			(286	)		(111	)		105
Net change in income taxes		857			(2,658	)		2,486			264			(303	)		24			1,121			(2,961	)		2,510

Present value at December 31		5,420			6,347			2,354			418			839			438			5,838			7,186			2,792

Note:

INDEPENDENT ENGINEER’S AUDIT OPINION

February 2, 2004

Husky Energy Inc.

707 – 8th Avenue S.W.

Calgary, Alberta

T2P 3G7

Gentlemen:

Pursuant to your 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, 2003. 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 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/ B. H. EMSLIE

B. H. Emslie, P. Eng.

Senior Vice President

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 oil and gas reserves data as at December 31, 2003. The reserves data consist of the following:

(a) proved oil and gas reserve quantities estimated as at December 31, 2003 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, 2003:


	Discounted Future Net Cash Flows
Location of Reserves	(before income taxes, 10% discount rate)

Canada		5,420
China		411
Libya		7

		5,838

We have filed the Company’s disclosures in accordance with Financial Accounting Standards Board Statement No. 69 reserve disclosure 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.


/s/ PRESTON KRAFT		/s/ LARRY BELL

Preston Kraft P.Eng		Larry Bell
Manager of Reservoir Engineering		Vice President, Exploration & Production Services
Calgary, Alberta		Calgary, Alberta
February 2, 2004		February 2, 2004

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

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

(1) proved oil and gas reserve quantities estimated as at December 31, 2003 using constant prices and costs; and

(2) the related standardized measure of discounted future net cash flows.

Our 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”). Our Manager of Reservoir Engineering, who is an employee of the Company, has evaluated the Company’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 and Vice President, Exploration and Production Services will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the Board of Directors has:

(a) reviewed the Company’s procedures for providing information to the internal and external qualified oil and gas reserves evaluators;

(b) met with the internal and, if applicable, external qualified oil and gas reserves evaluator(s) to determine whether any restrictions placed by management affect the ability of the internal qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the internal qualified oil and gas reserves evaluators.

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

(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.

The Company has sought and was granted by securities regulatory authorities an exemption from the requirement under securities legislation to involve independent qualified oil and gas reserves evaluators or auditors. Notwithstanding this exemption, we involve independent qualified reserve auditors as part of our corporate governance practices. Such independent auditors audited over 75% of reserves data and reviewed the remaining proved and probable oil and gas reserves based on value. Their involvement helps assure that our internal oil and gas reserves estimates are materially correct.

In our view, the reliability of the internally generated oil and gas reserves data is not materially different than would be afforded by our involving independent qualified reserves evaluators to evaluate and review the reserves data. A portion of our oil and gas reserves data is international in nature. Husky is an SEC registrant and therefore our reserves data is developed in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as modified or replaced by the applicable U.S. Financial Accounting Standards Board standards and the legal requirements of the SEC. Our procedures, records and controls relating to the accumulation of source data and preparation of reserves data by our internal reserves evaluation staff have been established, refined and documented over many years. Our internal reserves evaluation staff includes 106 individuals, including support staff, of whom 65 individuals are qualified reserves evaluators as defined in the Canadian Oil and Gas Evaluation Handbook, with an average of 15 years of relevant experience in evaluating reserves. Our internal reserves evaluation management personnel includes 25 individuals with an average of 14 years of relevant experience in evaluating oil and gas and managing the evaluation process.

Reserves data are estimates only, and are not exact quantities. Because the reserves data are based on 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 18, 2004

/s/ NEIL D. MCGEE Neil D. McGee Vice President & Chief Financial Officer				March 18, 2004

/s/ MARTIN J. G. GLYNN Martin J. G. Glynn Director				March 18, 2004

/s/ R. DONALD FULLERTON R. Donald Fullerton Director				March 18, 2004

Description of Major Properties and Facilities

Husky’s portfolio of assets includes properties that produce light (30 API and lighter), medium (between 20 and 30 API and heavy (below 20 and above 10 API) gravity crude oil, NGL, natural gas and sulphur. Production figures include daily production from Marathon properties based on the period October 1, 2003 to December 31, 2003.

At December 31, 2003, Husky had gross proved crude oil and NGL reserves totalling 544.3 mmbbls (485.5 mmbbls net) and gross proved natural gas reserves totalling 2,058.9 bcf (1,716.6 bcf net).

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 provinces of Saskatchewan and Alberta. Approximately 85% 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, Baldwinton 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. Husky maintains a land position of approximately 1.5 million net acres in the Lloydminster area, of which approximately two-thirds is undeveloped.

Husky currently produces from oil and gas wells ranging in depth from 450 to 650 metres and holds a 100% working interest in the majority of these wells. Husky produces heavy oil from the Lloydminster area using a variety of techniques, including standard primary production methods, as well as steam injection and horizontal well technology. Husky has 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. Husky’s gross heavy and medium crude oil production from the area totalled 89.8 mbbls/day in 2003. Approximately 70.9 mbbls/day of that total was primary production of heavy crude oil, approximately 14.8 mbbls/day was production from Husky’s thermal operations at Pikes Peak (cyclic steam) and Bolney/ Celtic (SAGD) and approximately 4.1 mbbls/day was from the medium gravity waterflooded fields in the Wainwright and Wildmere areas. Husky believes that the future growth from this area will be driven by primary heavy oil production and new thermal projects.

In the Lloydminster area Husky owns and operates 16 oil treating facilities, all of which are tied into Husky’s heavy oil pipeline systems. These pipeline systems transport heavy crude oil from the field locations to Husky’s Lloydminster asphalt refinery, to the Husky Lloydminster Upgrader and to the Enbridge Pipeline and Express Pipeline systems at Hardisty, Alberta.

Husky is focused on increasing its heavy oil production and believes that its 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.

Husky also produces natural gas from numerous small shallow natural gas pools in the Lloydminster area (approximately 1 to 2 bcf of proved reserves). Husky’s total gross natural gas production from the area during 2003 was 51.2 mmcf/day.

Lloydminster Area

(LLOYDMINSTER AREA MAP)

Northwest Alberta Plains

Rainbow Lake Area

Rainbow Lake, located approximately 700 kilometres north-west of Edmonton, Alberta, is the site of Husky’s 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%. Husky’s production in this area is derived from more than 50 oil and gas pools extending over 1,300 square kilometres.

Husky uses 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 miscible floods, has increased the estimated amount of recoverable crude oil-in-place from 50% to 70% of the original crude oil-in-place in certain pools. 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, Husky initiated the recovery of natural gas from several pools. NGL recovery is forecast to begin in the 2008-2010 timeframe and is expected to generate revenues as the crude oil production from the pools is completed. Husky uses horizontal drilling techniques, including the re-entry of existing wellbores, to maintain the level of crude oil production and to increase recovery rates. Husky plans to continue exploration efforts to supplement its development initiatives in the Rainbow Lake area. Husky’s gross production from this area averaged 7.7 mbbls/day of light crude oil and NGL and 33.6 mmcf/day of natural gas during 2003.

Husky holds a 50% interest in, and operates, 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 2003, a 20 mmcf/day sales gas compressor and a sales gas coalescer were added to the plant, increasing sales gas capacity from 17 mmcf/day to 34 mmcf/day. The area serviced by the Rainbow plant was expanded in 2003 with the construction of a 16.5 centimetre diameter gathering system into the Bivouac area in north-eastern British Columbia, where Husky operates gas wells and a compressor station.

Husky acquired two significant non-operated properties in the Rainbow area through the acquisition of Marathon. They included the Ekwan/ Sierra property in north-eastern British Columbia and the Bistcho/ Cameron Hills property straddling the Alberta and Northwest Territories border. Husky’s gross production from these properties currently averages 9 mmcf/day of natural gas and 68 bbls/day of liquid hydrocarbons. Husky also acquired a working interest in the Encana Sierra gas plant and the Paramount Bistcho gas plant. Husky is active in both these areas with development and exploration drilling. These two areas have growth potential with 95,000 net undeveloped acres at Ekwan/ Sierra and 110,000 net undeveloped acres at Bistcho/ Cameron Hills.

Peace River Arch Area

The Peace River Arch area of northern Alberta, which includes the Slave Lake, Sawn Lake, Red Earth, Lubicon, Nipisi, Utikuma and other properties, has been a major light oil producing area located approximately 370 kilometres north-west of Edmonton. Husky operates and holds an average 80% working interest in several properties in this area. Over the last three years, Husky has maintained net production from properties in this area, at approximately 3.8 mbbls/day of crude oil, through acquisitions, step-out drilling and waterflood optimization. With Husky’s acquisition of Marathon in 2003, the Slave Lake and Red Earth properties were added to the asset base, increasing 2003 gross liquid production by approximately 1,160 bbls/day and natural gas production by 10.3 mmcf/day. The average working interest in these lands is 80%, for a net 166,200 acres. Infrastructure includes a 100% working interest in a 30 mmcf/day sour gas plant and three oil batteries. Husky plans to continue development drilling and waterflood optimization for both crude oil and natural gas targets in this area.

Boyer Area

The Boyer area of Alberta is approximately 600 kilometres north-west of Edmonton, Alberta. Husky is the operator and holds close to 100% working interest in approximately 623,000 net acres. The area holds a shallow, Bluesky gas reservoir that is characterized as low deliverability and low decline that is being developed with a drilling density of three wells per section. Husky intends to continue to develop this area by drilling undeveloped sections, infill drilling, land acquisitions and step out exploration. Gross production from this area in 2003 averaged 32 mmcf/day of natural gas.

Sloat Creek Area

The Sloat Creek or Chinchaga area of Alberta is located close to the British Columbia border approximately 570 kilometres north-west of Edmonton, Alberta. Husky is the operator and holds an approximate 95% working interest in 230,000 acres of gas prone land. The Bluesky, DeBolt, Elkton and Shunda zones that lie an average of approximately 1,030 metres deep and the Slave Point zone at an average depth of 1,800 metres characterize the area. Husky intends to continue to develop this area with infill, step-out and exploratory drilling so that existing pools can be optimized and new pools can be placed on production.

Husky owns a 30 mmcf/day high pressure booster compression plant that feeds a third party operated sour gas plant and is 50% owner in a 12 mmcf/day low pressure booster that feeds a 40% owned sweet gas processing facility operated by a third party. Gross production from this area averaged 8.9 mmcf/day of natural gas in 2003.

Marten Hills/ Muskwa Area

The Marten Hills and Muskwa areas of Alberta are located 212 kilometres north-west of Edmonton, Alberta. Husky is the operator and holds 578,000 net acres of gas prone land. The Clearwater, Colony, McMurray and Wabiskaw zones that lie at an average depth of 600 metres characterize the area. Husky intends to continue to develop this area with infill, step-out and exploratory drilling so that existing pools can be optimized and new pools can be placed on production.

Husky owns a 100% interest in a series of nine sales gas compressor stations (compressors at sales points) and a number of field booster stations, a 95% interest in a compressor station at Rock Island, a 37.5% interest in a third party

operated facility at Peerless and a 3% interest in the third party operated Marten Hills unit. Gross production from this area averaged 35.9 mmcf/day of natural gas in 2003.

Cherpeta and Saleski Areas

The Cherpeta area of Alberta is located 230 kilometres north of Edmonton, Alberta and the Saleski area is located approximately 140 kilometres further north from Cherpeta. Husky is the operator and holds an interest in 580,000 net acres of gas prone land. The Nisku, Clearwater, Colony, McMurray and Wabiskaw zones that lie at an average depth of 600 metres characterize the area. The Grosmont zone that lies between 450 and 500 metres characterizes the Saleski area. Husky intends to continue to develop this area with infill, step-out and exploratory drilling so that existing pools can be optimized and new pools can be placed on production.

Husky holds working interests ranging from 60-95% in the Cherpeta area and 49% of the Saleski area and operates a series of sales compressor stations, gas plants and sales pipeline. Gross production from these areas averaged 37.8 mmcf/day of natural gas in 2003.

Simons Lake Area

The Simons Lake area of Alberta is located 386 kilometres north-west of Edmonton, Alberta. Husky is the operator and holds 275,000 net acres of gas prone land. The Bluesky, DeBolt, Elkton and Shunda zones that lie at an average depth of 600 metres characterize the area.

Husky holds 100% working interest in a 10 mmcf/day sour gas processing facility and 34% working interest in a high pressure booster station operated by a third party that feeds a separate third party owned sour gas processing facility. Gross production from this area averaged 4.5 mmcf/day of natural gas in 2003.

Northeast British Columbia and Alberta Foothills

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 105 mmcf/day. Husky holds a 34% interest in two unitized wells, a 24% and a 50% interest in two non-unit wells, and acts as the contract operator of the Blackstone wells. Production from these wells is processed at the Husky operated Ram River gas plant.

Husky holds an average 72% interest in, and is 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 2003, the plant operated at approximately 86% of its design rate capacity. The Ram River plant processes in excess of 10% of Husky’s total gross natural gas production, which includes an average of 48 mmcf/day of Husky gross sales gas from the Blackstone, Brown Creek, Cordel and Stolberg fields and an average of 22 mmcf/day of Husky 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 another gas plant, averaged 5.7 mmcf/day of natural gas bringing the total Husky interest production of natural gas from the Ram River area to 64 mmcf/day in 2003.

Husky’s sour gas pipeline network supports the Ram River plant. Husky operates a network of 845 kilometres of sour gas pipelines in the Ram River area and holds a 30% interest in 684 kilometres of this pipeline system. The sour gas processed at the Ram River plant is produced from 18 sour gas fields located as far as 145 kilometres from the Ram River plant.

Husky believes 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 Husky 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.

Kaybob

The Kaybob area was acquired through Husky’s acquisition of Marathon on October 1, 2003. The Kaybob area consists of lands located in the Fox Creek area of Alberta. The Kaybob area consists of four main areas. These are:

• Kaybob South Beaverhill Lake Unit 1 (35.6% working interest)

• Kaybob South Triassic Unit 1 (40.5% working interest)

• Kaybob South Triassic Unit 2 (26.8% working interest)

• Non-unit lands (various, from gross overriding royalty to 100% working interest)

The majority of the gas is gathered and processed through the Kaybob South Amalgamated Gas Plants 1 and 2. Husky has an approximate 17.8% working interest in the sour portion and an approximate 20.4% working interest in the sweet gas portion of the plant. Husky also has various working interests in sweet gas gathering and compression facilities in the area. Husky’s gross production from the area is 525 bbls/day of oil, 650 bbls/day of NGL and 13 mmcf/day of natural gas during 2003.

Boundary Lake Area

Husky holds a 50% working interest in the Boundary Lake Gas Unit and 34% and 19% interest in the Boundary Lake oil unit 1 and 2, respectively, in north-east British Columbia. Husky’s natural gas production from this area is derived from five Belloy sour gas pools, which is processed at the nearby Boundary Lake processing plant. Husky’s gross production from this area was 14.5 mmcf/day of natural gas and 1.9 mbbls/day crude oil and NGL from the Boundary Lake units during 2003.

Valhalla and Wapiti Area

Husky holds a 30% interest in three Valhalla oil units, a 100% interest in 350 Valhalla non-unit waterflood wells and a 100% interest in the Wapiti property. Production is primarily from the Doe Creek and Cardium zones and consists of light crude oil, NGL and natural gas. Husky’s gross production from these properties averaged 4.4 mbbls/day of crude oil and NGL and 6.1 mmcf/day of natural gas in 2003.

Kakwa Area

Husky acquired, through the acquisition of Marathon, an average 60% working interest in oil and gas processing facilities and associated oil and gas gathering systems in the Kakwa area. Husky operated lands in the Kakwa area total approximately 47,700 gross acres. Husky has an interest in approximately 65 Cardium wells in this area with average gross production of 11.1 mmcf/day of natural gas, 508 bbls/day NGL and 485 bbls/day of oil in 2003.

Caroline Area

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

Husky also holds an 11% interest in the Caroline sour gas processing facility. The plant is presently running at a license limit of 113% of design capacity and is processing approximately 124 mmcf/day of total plant sales gas and 39 mbbls/day of NGL. The plant and liquid acceleration gas recycle plant were at 87% capacity in 2003 which resulted in Husky gross production of 4.4 mbbls/day NGL and 13.6 mmcf/day natural gas in 2003.

Edson Area

Husky holds an average 85% working interest in two gas processing facilities and associated gas gathering systems in the Edson area. Husky operated lands in the Edson area total approximately 56,000 gross acres. Husky has an interest in approximately 160 Cardium wells in this area that averaged gross production of 35.1 mmcf/day of natural gas and 1.7 mbbls/day of NGL in 2003.

Sikanni Area

Husky holds approximately 32,000 net acres in the Sikanni and Federal area of north-east British Columbia, which averaged gross production of 23.3 mmcf/day of natural gas from four wells in 2003. The production flows through Husky owned gathering systems for processing at third party plants at Sikanni and McMahon.

Graham Area

Husky acquired, through the acquisition of Marathon, a 40% working interest in approximately 71,000 gross acres of developed and undeveloped lands in the Graham area of north-eastern British Columbia. The property produced at an average of 10.4 mmcf/day gross natural gas sales in 2003 from a total of 22 wells. Production from the property is from one Halfway and seven Baldonnel pools. Husky also acquired interests 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. Husky holds a 33.2% interest in the gas treating unit, 28.2% interest in the amine unit and 28% interest in the sulphur unit.

East Central Alberta

Athabasca 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 455 to 910 metres, in the multi-zone Palaeozoic Mannville. The main producing areas are Athabasca, Craigend and Cold Lake. Husky operates 31 facilities with an pipeline system and an average working interest of 90% in the producing wells. Husky holds approximately 539,000 net acres of undeveloped land and 409,000 net acres of developed land in this area. Husky intends to continue to develop this area with infill, stepout and exploratory wells to optimize recovery and develop new pools in order to keep the facilities operating at capacity. Husky’s gross production from this area averaged 52.8 mmcf/day of natural gas and 682 bbls/day of crude oil in 2003.

Red Deer and Hussar Area

The core of the Red Deer and Hussar area is between Calgary, Drumheller and Sylvan Lake. Husky operates 18 facilities with gas gathering systems in this area. Gross production from this area averaged 53.7 mmcf/day of natural gas and crude oil and NGL of 2.7 mbbls/day in 2003. Husky intends to continue to develop the natural gas potential of this area with infill, stepout and exploratory wells to optimize gas recovery and develop new pools in order to operate the facilities at capacity. In 2003 Husky participated in a coal bed methane pilot project. In 2004, Husky will develop a commercial coal bed methane project, based on the successful results of the pilot project.

Provost Area

The centre of the Provost area is approximately 240 kilometres south-east of Edmonton. It is predominantly a medium crude oil area that averaged gross production of 20.8 mbbls/day of crude oil and 12.2 mmcf/day of natural gas in 2003. Husky intends to selectively drill lower risk oil locations and focus on managing operating costs and improving oil recovery. In 2004 Husky intends to develop several of its 2003 natural gas discoveries. There is significant competition in the area for land as well as infrastructure. Husky has a large land position and maintains close to 100% working interest in most of its facilities.

Southern Alberta and Southern Saskatchewan

As of December 31, 2003, the Company held 250,000 net developed acres and 1.1 million undeveloped acres in Southern Saskatchewan and 280,000 net developed acres and 240,000 net undeveloped acres in Southern Alberta. The Company also has a small landholding in Manitoba.

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 this area averaged 18.4 mbbls/day of crude oil and of 53.8 mmcf/day of natural gas during 2003.

Husky operates 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, 128 wells were drilled and one new gas facility was built in 2003. The project was producing at a rate of 52 mmcf/day at December 31, 2003 from a total of 225 wells. In 2004, Husky plans to drill 100 additional wells and construct one natural gas processing facility.

Southern Alberta Area

Taber, Brooks and Jenner/ Suffield are Husky’s three core areas in southern Alberta. Husky operates 28 oil facilities and three natural gas facilities with an average working interest of 95%. Oil production is mainly medium gravity crude with the majority of reserves being supported by waterfloods or active aquifers. Natural gas production is from a mixture of deep and shallow formations. At Taber, Husky is operating an alkaline-polymer flood to increase recovery from the Cretaceous Mannville reservoir. Gross production from this area averaged 11.7 mbbls/day of crude oil and 14.6 mmcf/day of natural gas during 2003.

The acquisition of Marathon on October 1, 2003 added a new core area at Queenstown that includes five natural gas facilities producing over 20 mmcf/day. Husky intends to drill 40 wells in this area in 2004.

Western Canada

(OIL SANDS MAP)

Athabasca, Cold Lake and Peace River

Oil Sands

Husky currently holds interests in 433,610 acres in the bitumen prone areas of Athabasca, Cold Lake and Peace River. Husky is currently conducting evaluation drilling and production feasibility studies in the Cold Lake and Athabasca areas. Recent improvements in fiscal regimes for these types of projects, together with advances in technology which have reduced costs for in situ projects, have enhanced the commercial viability of these projects. In situ projects are currently being designed for the Tucker and Sunrise (formerly Kearl) areas.

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

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

64,034

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

11,360

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

527,267

433,610

Notes:

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

(2) Husky also has the exclusive right to acquire an additional 65,280 acres in the Caribou area.

(3) Included in the gross and net amounts are an additional 1,280 acres of petroleum and natural gas rights held as protection acreage for gas over bitumen issues.

Oil Sands

(MAP WESTERN CANADA)

Offshore East Coast — Canada

Husky’s offshore East Coast exploration and development program is focused primarily in the Jeanne d’Arc Basin on the Grand Banks offshore the coast of Newfoundland and Labrador, which contains the Hibernia, Terra Nova and White Rose oil fields. Husky has ownership interests in the Terra Nova and White Rose oil fields as well as in a number of smaller fields in the central part of the basin. Husky presently holds working interests ranging from 5.33% to 90% in 14 Significant Discovery License areas in the Jeanne d’Arc Basin. Husky is also the operator of seven Exploration Licenses (“EL”) on the Grand Banks and two in the South Whale Basin. Husky believes that its geotechnical expertise, drilling experience and extensive database with respect to offshore the East Coast of Canada provide a strong foundation for future exploration and development. Husky believes that there is exploration potential in the area, and that its position off the East Coast of Canada will provide growth opportunities for light crude oil production in the medium to long-term.

Husky will continue technical evaluation of its East Coast exploration acreage. Depending on drilling rig availability, Husky plans to drill one exploration type stratigraphic test well in 2004 on the EL1059 block in the South Whale Basin.

Terra Nova Oil Field

The Terra Nova oil field is located approximately 350 kilometres east south-east of St. John’s, Newfoundland, 35 kilometres south-east of the Hibernia oil field, in 91 to 100 metres of water. The Terra Nova oil field is divided into three distinct areas, known as the Graben, the East Flank and the Far East.

As at December 31, 2003, there were eight development wells drilled in the Graben area, five producing wells and three injection wells. In the East Flank area there were seven development wells including four production wells and three injection wells. Drilling operations are expected to continue based on an updated 36 well depletion plan for the Graben and East Flank areas. A 2001 delineation well in the Far East area encountered 82 metres of net pay confirming the reservoir sands extend to this area in 2003. A second well, that was intended to be a water injection well, was drilled in the Far East area. This well encountered poor porosity in the target horizon and was plugged back. The well may be re-drilled to a different location in the future. During 2003, a third delineation well was drilled to assess the northern fault blocks. The well encountered water suggesting a common oil-water contact throughout the Far East reservoir. Additional delineation wells in the Far East area are currently being considered as part of the 2004 drilling program. At December 31, 2003, Husky had booked 17.2 mmbbls of gross light crude oil to the proved developed category and 8.5 mmbbls proved undeveloped. These reserves are estimated to be capable of being produced using primary and secondary (waterflood and gasflood) production techniques.

Husky’s initial pooled interest in the Terra Nova field is 12.51%. This interest is subject to change, pending redetermination once the field has been further delineated. Production at Terra Nova commenced in January 2002. Husky’s gross production from Terra Nova averaged approximately 17.8 mbbls/day in the fourth quarter of 2003. Husky’s gross share of production from Terra Nova was 6.1 mmbbls in 2003.

White Rose Oil Field

The White Rose oil field, which is operated by Husky, is located 354 kilometres off the coast of Newfoundland, approximately 48 kilometres east of the Hibernia oil field on the eastern section of the Jeanne d’Arc basin.

During 2003, progress was achieved in several areas of the White Rose development project. All of the glory holes were excavated in the seabed to the required nine metre depth. The glory holes will protect the subsea wellhead equipment and associated production facilities from scouring icebergs. With the glory hole completion, development drilling has commenced for the White Rose oil field and will consist of nine wells prior to first oil — four producing wells, four water injection wells and one gas injection well, to be completed over the next two years.

The hull of the FPSO was launched in South Korea in July 2003. The turret, which was fabricated in Abu Dhabi, was successfully transported to South Korea in mid-August and now has been installed in the FPSO. The FPSO is expected to arrive in Marystown, Newfoundland and Labrador in the second quarter of 2004 where the installation of the topsides, hook up and commissioning will take place. The FPSO topsides are being engineered and fabricated in St. John’s and Marystown, Newfoundland and Labrador. Fabrication of the subsea production systems, including risers, flowlines and umbilicals, manifolds and wellheads are well under way. The first subsea well head assembly was completed in 2003.

Current plans provide for a total of 19 to 21 development wells to be drilled to recover crude oil over a 10 to 15 year period. Peak production is expected to be approximately 92,000 barrels of oil per day sustained for approximately four years before declining.

Also in 2003, a delineation well, White Rose F-04, was drilled on a separate geological structure at the southern end of the White Rose oil field. The initial F-04 well encountered approximately 180 metres of hydrocarbon bearing sandstone, comprising 140 metres of gas and 40 metres of oil. Husky and its co-venturer drilled a successful sidetrack location (F-04Z) to delineate the structure. In 2004, planning and design work will begin to determine the optimum method of producing the oil reserves from the F-04 structure through the White Rose FPSO.

East Coast

Grand Banks — Jeanne d’Arc Basin

(GRAND BANKS - JEANNE D'ARC BASIN)

International

South China Sea

Wenchang

The Wenchang oil field is located in the western Pearl River Mouth Basin, approximately 300 kilometres south of Hong Kong and 135 kilometres east of Hainan Island. The Company holds a 40% working interest in the project and spent approximately $253 million, including acquisition costs, to first oil. Production commenced in July 2002. The Wenchang 13-1 and 13-2 oil fields are producing from 21 wells in 100 metres of water into a floating production, storage and offloading vessel stationed between fixed platforms located in the fields. The blended crude oil from the two fields averages approximately 35 API, similar to the benchmark Minas blend. At December 31, 2003, Husky’s proved reserves at Wenchang were calculated to be 23.9 mmbbls of crude oil. Husky’s gross production averaged 22.4 mbbls/day during 2003.

Block 39/05

Husky 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 13 1/2 fields with a commencement date of October 1, 2001. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In January 2003, the Qionghai 18-1-3 exploration type stratigraphic well 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. Husky is evaluating the geological information for this block and expects to complete this assessment by the end of 2004.

Blocks 23/15 and 23/20

Husky executed production sharing contracts with CNOOC for the 23-15 and 23-20 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 oil fields. The 23-15 block is 1,327 square kilometres and the 23-20 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% working interest. In 2003, Husky completed a 1,000 square kilometre 3-D seismic survey shot over a portion of block 23-15. This survey has been processed and is now being interpreted. Technical evaluations are currently underway to determine a possible seismic survey on block 23-20 in 2004.

Block 40/30

Husky 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 13-1 and 13-2 oil fields. The block covers an area of 6,704 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% working interest. A deep-water drilling rig has been contracted for one well, the ChangChang 12-1-1, which will commence drilling in the first half of 2004.

East China Sea

Block 04/35

Husky executed a production sharing contract with CNOOC for the 04-35 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 4,835 square kilometres. The production sharing contract requires the drilling of a single exploration well 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 have commenced. CNOOC has the right to participate in development of any discoveries up to a 51% working interest.

China

(CHINA MAP)

Madura Strait, Indonesia

Husky is party to a production sharing contract (“PSC”), which provides for various cost and production sharing arrangements, relating to a 2,794 square kilometre block in the Madura Strait offshore Java, Indonesia. Ten exploration and appraisal wells have been drilled in the block, resulting in discoveries of two natural gas fields. The Indonesian state oil company granted commercial status and approved a plan of development for one of these fields in order to supply natural gas to a proposed independent power plant near Pasuruan, East Java. Construction of the power plant did not proceed due to economic issues that occurred in Indonesia shortly after the natural gas sales contract was signed. In 2003 the natural gas sales contract was cancelled with the approval of the Indonesian authorities. In January 2003, Husky signed a memorandum of understanding to begin discussions intended to finalize another natural gas sales agreement for the Madura production. Negotiations progressed during 2003. Assuming successful negotiation of the gas sales agreement, a revised Plan of Development will be submitted to the Indonesian regulatory authority for approval. At December 31, 2003, the calculated proved undeveloped reserves at Madura, which totalled 142.9 bcf of natural gas and 6.4 mmbbls of natural gas liquids, were removed from the proved category pending the completion of a new gas sales contract and negotiation with the Indonesian regulatory authority for an extension to the PSC.

Shatirah, Libya

Husky has an 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 85% of Husky’s heavy crude oil production from the Lloydminster area. Husky also markets heavy crude oil production directly to refiners located in the U.S. mid-west and eastern U.S. and Canada. Husky markets its light and synthetic crude oil production to third party refiners in both Canada and the United States. Natural gas liquids are sold to local petrochemical end users and 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,

		2003		2002		2001


		(mmcf/day)
Sales to end users
	United States		382		375		413
	Canada		156		115		106
			538		490		519
Sales to aggregators			43		49		40
Internal use (1)			30		30		14

			611		569		573

Note:

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

Husky also markets third party natural gas production in addition to its own production.

Delivery Commitments

The following table shows the future commitments to deliver natural gas from Husky’s reserves in Western Canada. Husky’s 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

2004		25.5		3.26		51.1
2005		25.5		3.60		26.3
2006		25.5		3.76		23.6
2007		20.0		4.36		16.9
2008		20.0		4.60		4.9
2009		20.0		4.85		0.5
2010		20.0		5.12		—
2011		20.0		5.41		—
2012		20.0		5.73		—
2013		20.0		6.06		—
2014		6.2		3.72		—

		222.7				123.3

Midstream Operations

Overview

The midstream operations of Husky include:

• Upgrading — the upgrading of heavy crude oil feedstock into synthetic 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

• 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, which is a heavy oil upgrading facility located in Lloydminster, Saskatchewan.

The Husky Lloydminster 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 Husky Lloydminster Upgrader recovers the diluent, which facilitates pipeline transportation of heavy crude oil.

The Husky Lloydminster Upgrader provides heavy crude oil access to a new market, which Husky believes 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 Husky Lloydminster 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 61 mbbls/day of synthetic crude oil. Production at the upgrader averaged 61.4 mbbls/day of synthetic crude oil and 10.9 mbbls/day of diluent in 2003 compared with 55.7 mbbls/day of synthetic crude oil and 9.7 mbbls/day of diluent in 2002. Throughput at the upgrader in 2003 was higher than 2002 due to a scheduled maintenance turnaround during 2002. In addition to synthetic crude oil and diluent, the Husky Lloydminster Upgrader also produced, as by-products of its upgrading operations, approximately 340 lt/day of sulphur and 760 lt/day of petroleum coke during 2003. These products are sold in local and international markets. The profitability of Husky’s upgrading operations is primarily dependent upon the differential between the price of synthetic crude oil and the price of heavy crude oil.

Infrastructure and Marketing

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. Husky’s 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 Husky Lloydminster Upgrader and Husky’s 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 to the Enbridge Pipeline system and the Express Pipeline system. The crude oil is transported to eastern and southern markets on these pipelines. Husky’s 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,

2003

2002

2001

(mbbls/day)

Combined pipeline throughput

484

457

537

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.

Husky considers the expansion and optimization of its pipeline systems in the Lloydminster area to be necessary to further its 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.

Husky operates 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

(Heavy Oil Pipeline Systems Map)

Cogeneration

Husky has a 50% interest in a 215 MW natural gas fired cogeneration facility at the site of the Husky Lloydminster 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 Husky Lloydminster Upgrader.

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

Natural Gas Storage Facilities

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

Commodity Marketing

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

Husky markets light and medium crude oil and NGL sourced from its own production and third party production. Light crude oil is acquired for processing by third party refiners at Edmonton, Alberta and by the Company’s refinery at Prince George, British Columbia. Husky markets the synthetic crude oil produced at its upgrader in Lloydminster to refiners in Canada and the United States.

Husky markets natural gas sourced from its own production and third party production. Husky is currently committed to gas sales contracts with third parties, which in aggregate do not exceed amounts forecast to be deliverable from Husky’s reserves. Husky’s contracts are with customers located in eastern Canada/north-eastern United States (30%), mid-west United States (37%), Western Canada (29%) and west coast United States (4%). The natural gas volumes sales contracted are primarily at market price (90%). The terms of the contracts remaining at December 31, 2003 are up to one year (74%), one year to five years (16%) and over five years (10%). Husky has acquired rights to firm pipeline capacity to transport the natural gas to most of these markets.

Husky has developed its commodity marketing operations to include the acquisition of third party volumes in order to increase volumes and enhance the value of its midstream assets. Husky plans to expand its marketing operations by continuing to increase marketing activities. Husky believes that this increase will generate synergies with the marketing of its own production volumes and the optimization of its assets.

Refined Products

Overview

Husky’s refined products operations include refining and retail, commercial and wholesale marketing of refined petroleum products. This network provides a platform for substantial non-fuel related businesses.

Light oil refined products are produced at Husky’s refinery at Prince George, British Columbia and are also acquired from other 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 marketed directly or through Husky’s 10 terminals located throughout Western Canada.

Branded Petroleum Outlets and Commercial Distribution

Distribution

As of December 31, 2003, there were 550 independently operated Husky and Mohawk branded petroleum outlets and two independent restaurants. These petroleum outlets include service stations, travel centres and bulk distribution facilities located from Vancouver Island on the West Coast of Canada to the eastern border of Ontario. The travel centre network is strategically located on major highways and serves the retail market and commercial transporters 24 hours per day, 365 days per 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 Outlets

(Branded Petroleum Outlets)

Independent retailers or agents operate all Husky and Mohawk branded 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, 2003:


		British
		Columbia &												2002
Retail Outlets		Yukon		Alberta		Sask.		Manitoba		Ontario		Total		Total

	Travel Centres		9		8		5		2		13		37		37
	Full Serve		15		18		3		8		2		46		50
	Full/ Self Serve		12		23		5		6		2		48		51
	Self Serve		20		11		1		1		2		35		35
	Bulk Distributor		1		7		4		1		1		14		15
	Card/ Key Locks		1		4		—		—		2		7		6

			58		71		18		18		22		187		194

Leased
	Travel Centre		1		—		—		—		—		1		1
	Full Serve		5		12		6		7		—		30		32
	Full/ Self Serve		13		23		4		4		—		44		47
	Self Serve		29		17		—		1		—		47		47
	Bulk Distributor		3		—		—		—		—		3		3
	Card/ Key Locks		3		1		—		3		1		8		8

			54		53		10		15		1		133		138

Independent Retailers
	Travel Centre		1		1		—		—		4		6		4
	Full Serve		24		26		10		16		8		84		89
	Full/ Self Serve		28		5		5		1		1		40		40
	Self Serve		29		52		3		3		2		89		94
	Bulk Distributor		2		4		1		—		—		7		7
	Card/ Key Locks		1		1		—		—		2		4		3

			85		89		19		20		17		230		237

Total
	Travel Centres		11		9		5		2		17		44		42
	Full Serve		44		56		19		31		10		160		171
	Full/ Self Serve		53		51		14		11		3		132		138
	Self Serve		78		80		4		5		4		171		176
	Bulk Distributor		6		11		5		1		1		24		25
	Card/ Key Locks		5		6		—		3		5		19		17

			197		213		47		53		40		550		569

Cardlocks (1)			22		17		5		6		22		72		60
Convenience Stores (1)			186		196		42		49		34		507		524
Restaurants (2)			9		11		5		2		14		41		42

Notes:

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

(2) At December 31, 2003 and 2002, two Husky House restaurants in Alberta were not located at a petroleum outlet.

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

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



	Years ended December 31,

	2003		2002		2001


	(mbbls/day)
Gasoline		28.5		26.3		25.4
Diesel fuel		22.1		20.7		21.1
Liquefied petroleum gas		1.2		1.3		1.3

		51.8		48.3		47.8

Husky’s current strategy in respect of its 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. Husky also plans 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. Husky is pursuing acquisitions and joint venture opportunities to further enhance its existing distribution network.

Supply

Prince George Refinery. Husky owns and operates a refinery at Prince George, British Columbia, which has capacity to refine more than 10,000 bbls/day of light crude oil into a full range of refined petroleum products. The crude oil feedstock for the Prince George refinery is produced primarily in north-eastern British Columbia by other producers and delivered to Husky’s refinery by pipeline. Husky is pursuing acquisitions and trading opportunities to further enhance its existing refining capacity. Husky is currently assessing plans to upgrade the refinery to meet Federal regulations governing sulphur content in fuel.

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 Husky 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 Husky through its retail networks and to its wholesale customers. During 2003, these refiners processed an average of approximately 36.2 mbbls/day of crude oil for Husky, yielding approximately 32.7 mbbls/day of refined petroleum products. During 2003, Husky also purchased approximately 7.8 mbbls/day of refined petroleum products from refiners and acquired approximately 6.6 mbbls/day of refined petroleum products pursuant to exchange agreements with third party refiners.

Minnedosa, Manitoba — Ethanol Plant. Husky owns an ethanol plant at Minnedosa, Manitoba that produces nine million litres per year of fuel ethanol and one million litres per year of industrial alcohol. Ethanol is produced primarily from wheat and other grains. It is an oxygenate, which when added to gasoline, promotes fuel combustion, raises octane levels and inhibits water from freezing in fuel lines. The ethanol blended gasoline (Mother Nature’s Fuel) has received federal government recognition for its low combustion emissions. Husky is actively planning to expand its ethanol production to meet provincial government mandates and internal demands. Ethanol-blended gasoline is now available at all Husky and Mohawk retail outlets. Husky also supplies E85 (85% ethanol content blended gasoline) to some Federal Government fleet vehicles across Western Canada.

Asphalt Products

Husky has been in the paving and specialty asphalt business for over 50 years. Husky supplies asphalt products to customers across Western Canada and the north-western and midwestern United States. Husky has a significant market share for paving asphalt, emulsified asphalt and asphalt products sold in Western Canada. Most of the asphalt sold is used for paving and other industrial purposes. Husky’s Pounder Emulsions division manufactures modified and conventional road application emulsion products. Additional non-asphalt based road maintenance products are marketed and distributed through the Western Road Management division of Husky. Demand for higher quality asphalt products has allowed Husky to increase sales into the United States and Eastern Canada, with products occasionally being shipped as far away as Texas, Florida and New Brunswick. In 2003, 45 percent of Husky’s asphalt production was exported to the United States. Husky plans to continue its efforts to improve its asphalt business by increasing its

modified asphalt production capacity to produce better products at a lower cost. Husky is also studying the feasibility of expanding its production and distribution capacity.

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

All of Husky’s asphalt requirements are supplied by its Lloydminster, Alberta asphalt refinery. The refinery was commissioned in 1983, replacing a Husky facility that had been operating since 1947. The refinery was designed specifically to produce asphalt from heavy crude oil at a rate of 25 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 the average daily sales volumes of products produced at the Lloydminster refinery, for the years indicated:



	Years ended December 31,

	2003		2002		2001


	(mbbls/day)
Asphalt		12.9		12.7		12.6
Residual and other		9.1		8.1		8.8

		22.0		20.8		21.4

Refinery throughput averaged 25.7 mbbls/day of blended heavy crude oil feedstock during 2003. 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. Husky has 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.

Human Resources

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



	December 31,

	2003		2002

Upstream		1,753		1,560
Midstream		326		344
Refined Products		349		329
Corporate and business support		471		520

		2,899		2,753

Selected Consolidated Financial Information



		Years Ended December 31,

		2003		2002		2001


		($ millions except
		per share amounts)
Statement of earnings data
	Sales and operating revenue		7,658		6,384		6,596
	Cash from operating activities		2,572		1,892		1,930
	Net earnings		1,321		804		654
	Per share — basic		3.23		1.88		1.49
	Per share — diluted		3.22		1.88		1.48
Balance sheet data
	Total assets		11,782		10,575		9,370
	Shareholders’ equity		5,889		5,127		4,486
	Total long-term debt		1,439		1,964		1,948

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:


	2003		2002		2001

Cash Dividends Declared per Common Share	$	1.38	$	0.36	$	0.36

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 has paid a quarterly dividend of $0.09 ($0.36 annually) per common share. This policy was reviewed by the Board in July 2003 and the quarterly dividend was increased to $0.10 ($0.40 annually) per common share. The Board, also declared a special cash dividend of $1.00 per common share in July, 2003. The special dividend was paid on October 1, 2003. Husky’s dividend policy will continue to be reviewed and there can be no assurance that further dividends will be declared. The declaration and payment of dividends will be at the discretion of the Board, which will consider earnings, capital requirements and financial condition of Husky, the satisfaction of the applicable solvency test in Husky’s governing corporate statute, the Business Corporations Act, (Alberta), and other relevant factors.

DESCRIPTION OF CAPITAL STRUCTURE

Common Shares

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

Preferred Shares

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

Credit Ratings

Disclosure with respect to the credit ratings Husky has received for its senior unsecured debt, Capital Securities and 8.45% senior secured bonds is set forth in Husky’s 2003 Management’s Discussion and Analysis and is incorporated herein by reference.

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, 2003:


					Volume
	High		Low		(000’s)

January		17.15		16.03		5,800
February		17.49		16.07		5,547
March		17.35		16.36		7,024
April		17.20		16.15		6,819
May		16.81		16.31		8,397
June		18.14		16.60		9,641
July		19.58		17.35		10,656
August		20.95		18.43		13,795
September		20.85		19.30		11,001
October		23.30		20.40		9,822
November		22.75		21.48		5,821
December		23.95		21.35		6,528

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Husky’s Management’s Discussion and Analysis for the fiscal years ended December 31, 2003 and December 31, 2002 is incorporated herein by reference and is available on SEDAR at www.sedar.com.

Comparability of Annual Data

Changes in accounting policies, major acquisitions and divestitures, or major changes in the nature of Husky’s business that affect the comparability of the annual data in this Annual Information Form, are listed below:

(i) the adoption of the recommendations of the Canadian Institute of Chartered Accountants with respect to accounting for foreign exchange effective January 1, 2002,

(ii) the acquisition of Marathon Canada Limited; and

(iii) the adoption of the recommendations of the Canadian Institute of Chartered Accountants in respect of the calculation and presentation of earnings per share.

Description of these changes are contained in Notes 3(j) and (k), 7 and 16 respectively, to the Consolidated Financial Statements of Husky for the year ended December 31, 2003 and are incorporated herein by reference. The Consolidated Financial Statements are available on SEDAR at www.sedar.com.

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

Li, Victor T.K.	Co-Chairman	August 25, 2000	Managing Director of Cheung Kong
Hong Kong	and Director		(Holdings) Limited (an investment holding 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, as well as Chairman of Cheung Kong Infrastructure Holdings Limited (an infrastructure development company) since 1996 and of CK Life Sciences Int’l., (Holdings) Inc. (a biotechnology company) since 2002. Mr. Li is also an Executive Director of Hongkong Electric Holdings Limited (a holding company) and a Director of The Hong Kong and Shanghai Banking Corporation Limited. Mr. Li is a member of the Chinese People’s Political Consultative Conference of the People’s Republic of China and he is also a member of the Commission on Strategic Development and the Business Advisory Group 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.	Co-Chairman	August 25, 2000	Group Managing Director of Hutchison
Hong Kong	and Director		Whampoa Limited since 1993 and Executive Director since 1984. Mr. Fok has been the Chairman of Hutchison Harbour Ring Limited (an investment holding company) since 2002, Hutchison Telecommunications (Australia) Limited (a telecommunications company) since 1999, Partner Communications Company Ltd. (a telecommunications company) since 1998 and Vanda Systems & Communications Holdings Limited (an investment holdings company) since 2003. Mr. Fok is also the Deputy Chairman of Cheung Kong Infrastructure Holdings Limited and 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 holds a Bachelor of Arts degree and is a member of the Australian Institute of Chartered Accountants.
Fullerton, R. Donald	Director	May 1, 2003	Corporate Director. From 1992 until 1999
Toronto, Ontario			he chaired the Executive Committee of
Canada			CIBC’s Board and retired as a director in February 2004. He currently serves on the Boards of George Weston Limited (a holding company) since 1991, Asia Satellite Telecommunications Holdings Ltd. since 1996 and Partner Communications Ltd. since 2003.


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

Glynn, Martin J.G.	Director	August 25, 2000	President and Chief Executive Officer of
New York, New York			HSBC Bank USA since 2003 and a
U.S.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 has been a Director of HSBC North America Inc. since 2002, and a Director of HSBC USA Inc. Mr. Glynn is also a director of Wells Fargo HSBC Trade Bank N.A.
Hui, Terence C.Y.	Director	August 25, 2000	Director, President & Chief Executive
Vancouver, British Columbia			Officer, Concord Pacific Group Inc.
Canada			(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. Mr. Hui was President and Chief Executive Officer of Pacific Place Developments Corp. (a real estate development company) from 1992 to 2001.
Kinney, Brent D.	Director	August 25, 2000	Independent businessman. Mr. Kinney is a
Dubai, United Arab Emirates			director of Dragon Oil plc in the United Arab Emirates and Aurado Energy Inc. since 2003.
Kluge, Holger	Director	August 25, 2000	Corporate Director. Mr. Kluge was
Toronto, Ontario			President, Personal and Commercial Bank,
Canada			CIBC from 1990 to 1999 and a director from 1992 to 1999. Mr. Kluge is a director of Hongkong Electric Holdings Limited, Hutchison Telecommunications (Australia) Limited, Loring Ward International Limited (a financial planning company) since 2004 and TOM.COM LIMITED. Mr. Kluge holds a Bachelor of Commerce degree and a Master’s degree in Business Administration.
Koh, Poh Chan	Director	August 25, 2000	Finance Director, Harbour Plaza Hotel
Hong Kong			Management (International) Ltd.
Kwok, Eva L.	Director	August 25, 2000	Chairman, a director and Chief Executive
Vancouver, British Columbia			Officer, Amara International Investment
Canada			Corp. (an investment holding company) since 1992 and President from 1992 to 1996. Mrs. Kwok is a director of Bank of Montreal Group of Companies and since 2002 of CK Life Sciences Int’l., (Holdings) Inc.
Kwok, Stanley T.L.	Director	August 25, 2000	President, Stanley Kwok Consultants (an
Vancouver, British Columbia			architecture, planning and development
Canada			company) since 1993. Mr. Kwok has been a director since 1997, and was Chairman from 1996 to 1998 of Amara International Investment Corp. Mr. Kwok is a director of Cheung Kong (Holdings) Limited and CTC Bank of Canada.
Lau, John C.S.	President &	August 25, 2000	President & Chief Executive Officer of
Calgary, Alberta	Chief Executive		Husky Energy Inc. since August 2000.
Canada	Officer and		Prior thereto, Mr. Lau was Chief
	Director		Executive Officer of Husky Oil Limited since 1993.


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

Shaw, Wayne E.	Director	August 25, 2000	Senior Partner, Stikeman Elliott LLP,
Toronto, Ontario			Barristers and Solicitors
Canada
Shurniak, William	Deputy Chairman	August 25, 2000	Director and Chairman of ETSA Utilities
Australia	and Director		(a utility company) since 2000, Powercor Australia Limited (a utility company) since 2000 and CitiPower Pty Ltd. (a utility company) since 2001. Mr. Shurniak has been a director of Hutchison Whampoa Limited since 1984, Envestra Limited (a natural gas distributor) since 2000 and CrossCity Motorways Pty Ltd. (an infrastructure and transportation company) since 2003. Mr. Shurniak was a director and Deputy Chairman of Asia Satellite Telecommunications Holdings Ltd. from 1996 to 1999. Mr. Shurniak holds an Honorary Doctor of Laws degree from the University of Saskatchewan and from The University of Western Ontario.
Sixt, Frank J.	Director	August 25, 2000	Group Finance Director of Hutchison
Hong Kong			Whampoa Limited since 1998 and Executive Director since 1991. Mr. Sixt is the Chairman of TOM.COM LIMITED since 1999. Mr. Sixt is also an 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 Orange plc. from 1998 to 2000 and of Voice Stream 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

McGee, Neil D. Calgary, Alberta	Vice President & Chief Financial Officer	Vice President & Chief Financial Officer of Husky since August 2000. Prior thereto Mr. McGee was Vice President & Chief Financial Officer of Husky Oil Limited since 1998.
Ingram, Donald R. Calgary, Alberta	Senior Vice President, Midstream & Refined Products	Senior Vice President, Midstream and Refined Products of Husky since August 2000. Prior thereto Mr. Ingram was Vice President, Downstream of Husky Oil Limited from 1994 until 1999 when he became Vice President of Midstream of Husky Oil Limited.
Girgulis, James D. Calgary, Alberta	Vice President, Legal & Corporate Secretary	Vice President, Legal & Corporate Secretary of Husky since August 2000. Mr. Girgulis joined Husky Oil Limited in 1994 as part of the legal group and became General Counsel and Corporate Secretary in 1999.

The Board of Directors has an Audit Committee (as required by the Business Corporations Act (Alberta)) currently consisting of M.J.G. Glynn (Chair), T. C.Y. Hui, R.D. Fullerton 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 17, 2004, the directors and officers of Husky, as a group, owned beneficially, directly or indirectly, or exercised control or direction over 386,011 common shares of Husky representing less than 1% of the issued and outstanding common shares.

Conflicts of Interest

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

Corporate Cease Trade Order or Bankruptcies

None of those persons who are directors, officers or promoters of the Company is, or has been within the past ten years, a director, officer or promoter of any other corporation 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 access to any statutory exemptions for a period of more than 30 consecutive days, or was declared bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation relating to bankruptcy or insolvency or been subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that person, other than Eva Kwok who was a director of Air Canada in 2003 at the time it became subject to creditor protection under the Companies’ Creditors Arrangement Act (Canada).

Penalties or Sanctions

None of the persons who are directors, officers or promoters of the Company have, within the ten years prior to the date of this Annual Information Form, been subject to any penalties or sanctions imposed by a court or securities regulatory authority relating to trading in securities, promotion or management of a publicly traded corporation, or theft or fraud.

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.

The Company leases 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 and Vice President & Chief Financial Officer are also a directors and officers 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 a lease for an eight year term effective September 1, 2000, with Western Canadian Place Ltd. on commercial terms consistent with those for leases of comparable space in Class A office buildings in Calgary.

The Company has also entered into a management agreement with Western Canadian Place Ltd. for general management of the building. The Company was paid fees of $36,663 in 2003 (down from $238,017 in 2002 due to credits in favour of Western Canadian Place Ltd.) 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).

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration, principal shareholders of Husky’s common shares and options to purchase common shares and interests of insiders in material transactions is contained in Husky’s Management Information Circular dated March 18, 2004 (the “Information Circular”), prepared in connection with the annual meeting of shareholders to be held on April 22, 2004.

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, 2003, contained in Husky’s 2003 Annual Report.

Copies of the Information Circular, the financial statements, including any interim financial statements, additional copies of this Annual Information Form, including one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form, and if Husky is in the course of a distribution pursuant to a preliminary short form prospectus or a short form prospectus, any other documents incorporated therein by reference may be obtained upon request from the Vice President, Legal & Corporate Secretary of Husky, 40th Floor, 707 8th Avenue S.W., Calgary, Alberta T2P 1H5, Telephone: (403) 298-7333; Facsimile: (403) 298-7323.

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Information Form are forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995, 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,” “intends,” “plans,” “projection” 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. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this Annual Information Form. Among the key factors that have a direct bearing on the Company’s results of operation are the nature of the Company’s involvement in the business of exploration, development and production of oil and natural gas reserves and the fluctuation of the exchange rate between the Canadian dollar and the United States dollar. These and other factors are discussed herein under “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, incorporated by reference in this Annual Information Form. and available on SEDAR at www.sedar.com.

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. Further, any forward-looking statement speaks only as of the date on which such statement is made, and 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, except as required by applicable securities laws. 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.


(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.


	•	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 and .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).


(1)	Light crude oil includes crude oil that is lighter than 30 API, medium crude oil is between 20 and 30 API gravity and heavy crude oil includes crude oil that is lower than 20 API and lighter than 10 API gravity in the Lloydminster area.

(2)	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.


(1)	Does not include the acquisition of Marathon.

(2)	Does not include the acquisition of Titanium Oil & Gas Ltd. and Avid


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


(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.

(2)	2003 includes 271 gross, 241 net oil wells and 424 gross, 207 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.


(1)	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.

(2)	These reserve categories have the same meanings as those set out in SEC Regulation S-X.

(3)	The discounted future net cash flows at December 31, 2003 were based on the year-end spot NYMEX natural gas price of U.S. $5.96/mmbtu and on a spot WTI crude oil price of U.S. $32.51/bbl.


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

(2)	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 pursuant to an exemption order granted with respect to Part 8 of NI 51-101.

(3)	Bitumen probable reserves are included under the caption Western Canada.


(1)	The costs in this schedule exclude corporate overhead, interest expense and other operating costs, which are not directly related to producing activities.


(1)	Property acquisition costs related to corporate acquisitions for proved properties in 2003 included $517 million; 2002 — nil; 2001 included $244 million.


(1)	Capital related to 17 mmbbls of proved reserves at Terra Nova transferred to proved oil and gas properties. In 2001, Terra Nova was a major development project off the East Coast of Canada.


(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.


(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.


	Sincerely,

	MCDANIEL & ASSOCIATES CONSULTANTS LTD.

	/s/ B. H. EMSLIE

	B. H. Emslie, P. Eng.
	Senior Vice President


1.	Our staff has evaluated the Company’s oil and gas reserves data as at December 31, 2003. The reserves data consist of the following:


	(a)	proved oil and gas reserve quantities estimated as at December 31, 2003 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, 2003:


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.


	(a)	reviewed the Company’s procedures for providing information to the internal and external qualified oil and gas reserves evaluators;

	(b)	met with the internal and, if applicable, external qualified oil and gas reserves evaluator(s) to determine whether any restrictions placed by management affect the ability of the internal qualified reserves evaluator to report without reservation; and

	(c)	reviewed the reserves data with management and the internal qualified oil and gas reserves evaluators.


	(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.


	•	Kaybob South Beaverhill Lake Unit 1 (35.6% working interest)

	•	Kaybob South Triassic Unit 1 (40.5% working interest)

	•	Kaybob South Triassic Unit 2 (26.8% working interest)

	•	Non-unit lands (various, from gross overriding royalty to 100% working interest)


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

(2)	Husky also has the exclusive right to acquire an additional 65,280 acres in the Caribou area.

(3)	Included in the gross and net amounts are an additional 1,280 acres of petroleum and natural gas rights held as protection acreage for gas over bitumen issues.


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


	•	Upgrading — the upgrading of heavy crude oil feedstock into synthetic 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

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


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

(2)	At December 31, 2003 and 2002, two Husky House restaurants in Alberta were not located at a petroleum outlet.


	(i)	the adoption of the recommendations of the Canadian Institute of Chartered Accountants with respect to accounting for foreign exchange effective January 1, 2002,


	(iii)	the adoption of the recommendations of the Canadian Institute of Chartered Accountants in respect of the calculation and presentation of earnings per share.