Exhibit 3

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the Year Ended December 31, 2003

Exhibit 3

MANAGEMENT’S DISCUSSION AND ANALYSIS

February 2, 2004

      Management’s Discussion and Analysis is the Company’s explanation of its financial performance for the period covered by the financial statements along with an analysis of the Company’s financial position and prospects. It should be read in conjunction with the Consolidated Financial Statements and notes thereto and the Supplemental Information on Oil and Gas Exploration and Production Activities. The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada. The effect of significant differences between Canadian and United States accounting principles is disclosed in note 20 of the Consolidated Financial Statements. The following discussion and analysis refers primarily to 2003 as compared with 2002, unless otherwise indicated. Refer to the section “Results of Operations for 2002 Compared with 2001” for an abridged discussion. All dollar amounts are in millions of Canadian dollars, unless otherwise indicated. The calculations of barrels of oil equivalent (“boe”) and thousand cubic feet of gas equivalent (“mcfge”) are based on a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Unless otherwise indicated, all production volumes quoted are gross, which represent the Company’s working interest share before royalties, and prices are those realized by the Company, which include the effect of hedging gains and losses.

      Management’s Discussion and Analysis contains the term “cash flow from operations”, which should not be considered an alternative to, or more meaningful than “cash flow from operating activities” as determined in accordance with generally accepted accounting principles as an indicator of the Company’s financial performance. The Company’s determination of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations generated by each business segment represents a measurement of financial performance for which each reporting business segment is responsible. The other items required to arrive at consolidated cash flow from operations are considered to be a corporate responsibility.

      Certain of the statements set forth under “Management’s Discussion and Analysis” and elsewhere in this Annual Report, including statements which may contain words such as “could”, “expect”, “believe”, “will” and similar expressions and statements relating to matters that are not historical facts, are forward-looking and are based upon the Company’s current belief as to the outcome and timing of such future events. There are numerous risks and uncertainties that can affect the outcome and timing of such events, including many factors beyond the control of the Company. These factors include, but are not limited to, the matters described under the heading “Business Environment”. Should one or more of these events occur, or should any of the underlying assumptions prove incorrect, the Company’s actual results and plans for 2004 and beyond could differ materially from those expressed in the forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-looking information. Such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995”. Refer to the section “Forward-looking Statements”.

OVERVIEW

Summary of Results

      Husky’s operations are organized into three major business segments:

• The upstream segment includes the exploration for and the development and production of crude oil and natural gas in Western Canada, offshore the Canadian East Coast and offshore China and other international areas.

• The midstream segment is organized into two reportable business segments; heavy crude oil upgrading operations, and infrastructure and commodity marketing operations. The infrastructure and commodity marketing segment comprises heavy crude oil pipeline and processing operations, natural gas storage, cogeneration operations, and marketing of crude oil, natural gas, natural gas liquids, sulphur and petroleum coke.

• The refined products segment includes the refining of crude oil and the marketing of refined petroleum products including asphalt products.

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Segmented Financial Summary

		Year ended December 31
				%						%
		2003		Change			2002			Change			2001
		($ millions, except where indicated)
Sales and operating revenues, net of royalties		$	7,658		20		$	6,384			(3	)	$	6,596
Cash flow from operations			2,459		17			2,096			8			1,946
Segmented earnings
	Upstream	$	1,048		52		$	688			43		$	482
	Midstream		185		15			161			(37	)		256
	Refined Products		28		(13	)		32			(49	)		63
	Corporate and eliminations		60		178			(77	)		48			(147	)
Net earnings		$	1,321		64		$	804			23		$	654
	Per share — Basic	$	3.23		72		$	1.88			26		$	1.49
— Diluted			3.22		71			1.88			27			1.48
Dividends declared per share			1.38		283			0.36			—			0.36
Return on equity (percent)			24.0					16.7						15.4
Return on average capital employed (percent)			18.0					12.2						10.9

Business Environment

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

• Crude oil and natural gas prices

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

• Demand for and ability to deliver natural gas

• The exchange rate between the Canadian and U.S. dollars

• Refined products margins

• Demand for Husky’s pipeline capacity

• Demand for refined petroleum products

• Government regulations

• Cost of capital

Average Benchmark Prices and U.S. Exchange Rate

		2003		2002		2001
West Texas Intermediate (“WTI”) (1)	(U.S.  $/bbl)	$	31.04	$	26.08	$	25.97
Canadian par light crude 0.3% sulphur	($/bbl)	$	43.56	$	40.28	$	39.39
NYMEX natural gas (1)	(U.S.  $/mmbtu)	$	5.39	$	3.25	$	4.38
NIT natural gas	($/GJ)	$	6.35	$	3.86	$	5.97
WTI/Lloyd blend differential	(U.S.  $/bbl)	$	8.55	$	6.47	$	10.74
U.S./Canadian dollar exchange rate	(U.S. $)	$	0.716	$	0.637	$	0.646

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

Commodity Price Risk

      Husky’s earnings depend largely on the profitability of its upstream business, which is significantly affected by fluctuations in oil and gas prices. Commodity prices have been, and are expected to continue to be, volatile due to a number of factors beyond Husky’s control. Refer to the section “Financial and Derivative Instruments” for a discussion of the Company’s use of hedging contracts.

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Crude Oil

      The prices received for the crude oil and NGL sold by Husky are related to the price of crude oil in world markets. Prices for heavy crude oil and other lesser quality crudes trade at a discount or differential to light crude oil. These prices are further affected by the use of hedging contracts, which provide for payments or receipts depending on whether the underlying commodity price is higher or lower than an agreed upon strike price.

      Benchmark crude oil prices averaged higher in 2003 compared with 2002. The price for West Texas Intermediate (“WTI”) crude oil averaged U.S. $32.70/bbl in January 2003 and fluctuated between monthly averages of U.S. $35.73/bbl and U.S. $28.07/bbl during the remainder of the year.

      During 2003 buoyant world crude oil prices resulted from production quotas set by the Organization of Petroleum Exporting Countries (“OPEC”), Nigerian and Venezuelan production restrictions and the war in Iraq. Iraqi production averaged approximately 350,000 bbls/day from April through July 2003. In August Iraqi production recovered considerably and averaged 1,400,000 bbls/day from August through October 2003 or approximately 70 percent of normal pre-war levels. OPEC has maintained a greater degree of production discipline over the past three years with the intention of maintaining prices within a U.S. $22/bbl — U.S. $28/bbl price range. Toward the end of 2003, OPEC announced cuts to its production quotas that were intended to keep prices within the price band. Numerous factors could affect world crude oil prices in the remainder of 2004. Early January 2004 commercial crude oil inventories were significantly lower than the five-year average. Low crude oil inventories restrict the refiners’ ability to increase distillate production, should protracted cold weather increase heating demand.

      During 2003 heavy crude oil differentials averaged U.S. $8.55/bbl for WTI/Lloyd blend compared with U.S. $6.47/bbl during 2002. The wider differential tends to reduce Husky’s overall financial results as the Company’s crude oil production is weighted toward heavier gravity crudes. In periods of wider differentials, Husky’s heavy oil upgrader offsets in part the impact of lower heavy crude prices.

WTI and Husky Realized Crude Oil Prices

Natural Gas

      The price of natural gas in North America is affected by regional supply and demand factors, particularly those affecting the United States such as weather conditions, pipeline delivery capacity, the availability of alternative sources of less costly energy supply, inventory levels and general industry activity levels. Periodic imbalances between supply and demand for natural gas are common and result in volatile pricing. The price of natural gas, unlike crude oil, is not subject to the influence of an organization such as OPEC.

      Throughout the last five months of 2003 natural gas prices on the New York Mercantile Exchange (“NYMEX”) drifted lower, averaging just over U.S. $5/mmbtu. With the arrival of colder weather at the end of November, prices on the NYMEX began to increase and the near-month price on December 31, 2003 for February 2004 delivery was U.S. $6.19/mmbtu. At the beginning of January 2004 natural gas storage in the U.S. was just above the five-year average.

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      The selling price for Husky’s natural gas is based either on fixed price contracts, spot prices, NYMEX or other regional market prices. The prices received are further affected by the Company’s hedging contracts, which provide for payments or receipts depending on whether the underlying commodity price is higher or lower than an agreed upon strike price. Refer to “Financial and Derivative Instruments” for a discussion of the Company’s use of hedging contracts.

NYMEX Natural Gas and Husky Realized Natural Gas Prices

Upgrading Differential

      The profitability of Husky’s heavy oil upgrading operations is dependent upon the amount by which revenues from the synthetic crude oil produced exceed the costs of the heavy oil feedstock plus the related operating costs. An increase in the price of blended heavy crude oil feedstock which is not accompanied by an equivalent increase in the price of synthetic crude oil would reduce the profitability of Husky’s upgrading operations. Husky has significant crude oil production that trades at a discount to light crude oil, and any negative effect of a narrower differential on upgrading operations would be more than offset by a positive effect on revenues in the upstream segment from heavy oil production.

Refined Products Margins

      The margins realized by Husky for refined products are affected by crude oil price fluctuations, which affect refinery feedstock costs, and third-party light oil refined product purchases. Husky’s ability to maintain refined products margins in an environment of higher feedstock costs is contingent upon its ability to pass on higher costs to its customers.

Integration

      Husky’s production of light, medium and heavy crude oil and natural gas and the efficient operation of its upgrader, refineries and other infrastructure provide opportunities to take advantage of any increases in commodity prices while assisting in managing commodity price volatility. Although predominantly an oil and gas producer, Husky’s integrated organization is such that the upstream business segment’s output provides input to the midstream and refined products segments.

Foreign Exchange Risk

      Husky’s results are affected by the exchange rate between the Canadian and U.S. dollars. The majority of Husky’s revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. A decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities and correspondingly an increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. The majority of Husky’s expenditures are in Canadian dollars. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky’s U.S. dollar denominated debt,

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as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2003, 74 percent or $1.5 billion of Husky’s long-term debt and capital securities was denominated in U.S. dollars. The Cdn./U.S. exchange rate at the end of 2003 was $1.29. The percentage of Husky’s long-term debt exposed to the Cdn./U.S. exchange rate decreases to 54 percent when the cross currency swaps are included. Refer to “Financial and Derivative Instruments”.

Interest Rates

      The Company maintains a portion of its debt in floating rate facilities which are exposed to interest rate fluctuations. The Company will occasionally fix its floating rate debt or create a variable rate for its fixed rate debt using derivative financial instruments. Refer to “Financial and Derivative Instruments”.

Environmental Regulation

      Most aspects of Husky’s business are subject to environmental laws and regulations. Similar to other companies in the oil and gas industry, Husky incurs costs for preventive and corrective actions. Changes to regulations could have an adverse effect on Husky’s results of operations and financial condition.

International Operations

      Husky’s international operations may be affected by a variety of factors including political and economic developments, exchange controls, currency fluctuations, royalty and tax increases, import and export regulations and other foreign laws or policies affecting foreign trade or investment.

Sensitivity Analysis

      The following table is indicative of the relative effect on net earnings and cash flow of changes in certain key variables. The analysis is based on business conditions and production volumes during 2003. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.

Sensitivity Analysis

				Effect on Pre-tax						Effect on
Item		Increase		Cash Flow						Net Earnings
				($ millions)			($/share) (4)			($ millions)			($/share) (4)
WTI benchmark crude oil price
	Excluding hedges		U.S. $1.00/bbl		93			0.22			63			0.15
	Including hedges		U.S. $1.00/bbl		54			0.13			34			0.08
NYMEX benchmark natural gas price (1)
	Excluding hedges		U.S.  $0.20/mmbtu		34			0.08			21			0.05
	Including hedges		U.S.  $0.20/mmbtu		18			0.04			10			0.02
Light/ heavy crude oil differential (2)			Cdn. $1.00/bbl		(25	)		(0.06	)		(16	)		(0.04	)
Light oil margins			Cdn. $0.005/litre		15			0.04			9			0.02
Asphalt margins			Cdn. $1.00/bbl		8			0.02			5			0.01
Exchange rate (U.S. $ per Cdn. $) (3)
	Including hedges		U.S. $0.01		(50	)		(0.12	)		(34	)		(0.08	)

(1)	Includes decrease in earnings related to natural gas consumption.
(2)	Includes impact of upstream and upgrading operations only.
(3)	Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items. The impact of the Canadian dollar strengthening by U.S. $0.01 would be an increase of $8 million in net earnings based on December 31, 2003 U.S. dollar denominated debt levels.
(4)	Based on December 31, 2003 common shares outstanding of 422 million.

Husky’s Business Plan

      Husky will continue to execute its long-term business plan, which is expected to increase reserves and production in the upstream business segment through selective acquisitions and effective exploration and development programs.

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Husky will also continue to enhance growth and returns through expansion, upgrading and optimization of the midstream and refined products businesses.

      The light and medium gravity crude oil potential of the Western Canada Sedimentary Basin, although considerable, is generally believed to be composed of smaller accumulations. Husky plans to optimize production from its properties in the Western Canada Sedimentary Basin through programs to improve recovery and through acquisitions and dispositions. Husky benefits from having a significant position in several key producing areas in Western Canada. Husky is the operator of the majority of its operations and has extensive infrastructure, which affords opportunities for cost control and economies of scale.

      Husky plans to more than offset production declines from light and medium crude oil properties in the Western Canada Sedimentary Basin by further exploitation of heavy oil in the Lloydminster area of Alberta and Saskatchewan, development of oil sands properties in Alberta, production from the White Rose offshore project and production from projects offshore China. In addition, 2004 plans include an oil exploration program in an area new to Husky in the central Mackenzie region of the Northwest Territories.

      The natural gas potential of the Western Canada Sedimentary Basin is considered to be favourable both for shallow gas on the undisturbed plains and larger deep accumulations in the Deep Basin and foothills overthrust areas. Husky’s natural gas production is expected to increase as a result of exploration concentrated in these areas west of the fifth meridian in Alberta and British Columbia and natural gas development activity throughout the Basin, as well as through selective acquisitions and asset rationalization.

      In 2004 Husky intends to invest $2.1 billion in capital programs. Capital totalling $1.15 billion is planned to be spent on upstream programs located throughout the Western Canada Sedimentary Basin, $585 million on programs offshore the East Coast of Canada and $65 million on international programs primarily offshore China. Capital programs in the midstream segment will total $100 million primarily for further debottlenecking of the Lloydminster Upgrader and $150 million in the refined products segment primarily for further upgrading of the marketing outlet system and construction of an ethanol production facility. Husky plans to invest $30 million in corporate areas in 2004.

      Husky’s 2004 business plan assumes that:

• WTI will average U.S. $26.50/bbl and the WTI/Lloyd blend differential will average U.S. $6.96/bbl

• NYMEX natural gas price will average U.S. $5.25/mcf

• the Canadian dollar will average U.S. $0.73

• U.S. $LIBOR will average 2.50 percent

• Husky’s total production will average 320 to 350 mboe/day. Production in 2004 comprises 67 to 76 mbbls/day of light crude oil and NGL, 35 to 40 mbbls/day of medium crude oil, 105 to 115 mbbls/day of heavy crude oil and 670 to 710 mmcf/day of natural gas

      Husky uses derivative financial instruments when deemed appropriate to hedge exposure to changes in the price of crude oil and natural gas and fluctuations in interest rates and foreign currency exchange rates. Husky does not engage in transactions involving derivative financial instruments for trading or speculative purposes.

      During 2003 Husky entered into contractual arrangements whereby between approximately 25 percent and 27 percent of 2004 planned annual production has been hedged. Crude oil production totalling 31 mmbbls has been hedged at an average price of U.S. $27.46/bbl throughout 2004 and 4.8 bcf of natural gas production has been hedged at an average price of U.S. $6.65/mmbtu from February to April 2004. This will protect cash flow and earnings in 2004 and facilitate the execution of 2004 capital programs. In addition, Husky has hedged a portion of its power purchases. From January to December 2004, 329,400 MWh have been hedged at an average price of $46.72/MWh.

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RESULTS OF OPERATIONS

Upstream

2003 Compared with 2002

      Husky’s earnings from the upstream segment increased by $360 million (52 percent) to $1,048 million in 2003 from $688 million in 2002.

Upstream Earnings Summary

	Year ended December 31
	2003		2002			2001
	($ millions)
Gross revenues	$	3,796	$	3,120		$	2,667
Royalties		584		460			502
Hedging (gain)/loss		26		(5	)		—
Net revenues		3,186		2,665			2,165
Operating and administrative expenses		855		729			648
DD&A		958		851			728
Income taxes		325		397			307
Earnings	$	1,048	$	688		$	482

      Husky’s total revenues from upstream operations were $3,796 million in 2003 compared with $3,120 million in 2002 primarily due to:

• higher price realization for crude oil and natural gas

• higher sales volumes of light and heavy crude oil and natural gas

the effect of which was partially offset by:

• lower sales volume of medium crude oil

• higher unit operating costs

      Higher production volumes of heavy crude oil were primarily due to:

• the ongoing Lloydminster heavy oil development programs and progress at the Bolney/ Celtic steam assisted gravity drainage thermal project

      Operating costs per unit of production increased 11 percent in 2003 compared with 2002 primarily as a result of:

• higher energy costs

• higher operating and maintenance costs for light/ medium crude oil properties under secondary and tertiary recovery schemes in Western Canada

• higher operating and maintenance costs for the extensive facilities associated with shallow gas production in Western Canada

partially offset by:

• lower unit operating costs at Terra Nova and Wenchang

      Depletion, depreciation and amortization (“DD&A”) increased to $8.40/boe in 2003 from $7.76/boe in 2002 and primarily resulted from:

• higher maintenance capital requirements for properties under secondary and tertiary recovery and shallow natural gas operations

• offshore operations that require substantial infrastructure capital

• acquired oil and gas properties which, in accordance with the purchase method of accounting, are recorded at fair value

      Income taxes with respect to the upstream business segment decreased in 2003 to $325 million from $397 million in 2002 despite higher pre-tax earnings. Income taxes in 2003 were partially offset by a number of non-recurring

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benefits. On June 13, 2003, Bill C-48 received first reading in the House of Commons and thus was considered to be substantively enacted. This amendment to the Income Tax Act reduces the income tax rate on resource income by seven percent, provides for the deduction from income of crown royalties and eliminates the resource allowance deduction. The amendment will be phased in over a five-year period. The total benefit recorded with respect to Bill C-48 was $141 million. In addition, a non-recurring upstream benefit totalling $18 million was recorded pursuant to Bill 41, the Alberta Corporate Tax Amendment Act, 2003. Both benefits reduced future income taxes related to upstream operations.

      During 2002, a non-recurring benefit of $23 million was recorded with respect to Alberta and British Columbia income tax rate reductions.

Net Revenue Variance Analysis

		Crude Oil			Natural
		& NGL			Gas			Other		Total
		($ millions)
Year ended December 31, 2001
Net revenues		$	1,262		$	873		$	30	$	2,165
	Price changes		573			(342	)		8		239
	Volume changes		218			(7	)		—		211
	Royalties		(71	)		113			—		42
	Hedging		5			—			—		5
	Processing		—			—			3		3
Year ended December 31, 2002
Net revenues			1,987			637			41		2,665
	Price changes		85			450			—		535
	Volume changes		59			58			—		117
	Royalties		16			(140	)		—		(124	)
	Hedging		(50	)		19			—		(31	)
	Processing		—			—			24		24
Year ended December 31, 2003
Net revenues		$	2,097		$	1,024		$	65	$	3,186

Daily Production, before Royalties

		Year ended December 31
		2003		2002		2001
Light crude oil & NGL	(mbbls/day)		71.6		65.4		46.4
Medium crude oil	(mbbls/day)		39.2		44.8		47.2
Heavy crude oil	(mbbls/day)		99.9		95.1		83.8
Natural gas	(mmcf/day)		610.6		569.2		572.6
Barrels of oil equivalent (6:1)	(mboe/day)		312.5		300.2		272.8

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Average Realized Prices

		Year ended December 31
		2003			2002			2001
Light crude oil & NGL	($/bbl)	$	39.53		$	36.17		$	33.15
Hedging (gain)/loss			0.80			(0.09	)		—
Light crude oil & NGL price realized		$	38.73		$	36.26		$	33.15
Medium crude oil	($/bbl)	$	31.42		$	30.16		$	23.69
Hedging (gain)/loss			1.85			(0.19	)		—
Medium crude oil price realized		$	29.57		$	30.35		$	23.69
Heavy crude oil price realized	($/bbl)	$	25.87		$	26.60		$	17.02
Natural gas price	($/mcf)	$	5.86		$	3.83		$	5.47
Hedging (gain)/loss			(0.08	)		—			—
Natural gas price realized		$	5.94		$	3.83		$	5.47

Upstream Revenue Mix

	Year ended December 31
	2003		2002		2001
Percentage of upstream sales revenues, after royalties
Light crude oil & NGL		28%		24%		14%
Medium crude oil		11%		25%		28%
Heavy crude oil		27%		25%		16%
Natural gas		34%		26%		42%
Total		100%		100%		100%

Effective Royalty Rates

	Year ended December 31
	2003		2002		2001
Percentage of upstream sales revenues
Light crude oil & NGL		12%		13%		21%
Medium crude oil		18%		17%		18%
Heavy crude oil		11%		11%		9%
Natural gas		21%		18%		23%
Total		16%		15%		19%

Operating Netbacks

Western Canada

Light Crude Oil Netbacks (1)

	Year ended December 31
	2003		2002			2001
	(per boe)
Sales revenues	$	39.91	$	33.66		$	34.25
Royalties		7.28		4.55			5.76
Hedging (gain)/loss		0.56		(0.17	)		—
Operating costs		9.27		10.46			8.15
Netback	$	22.80	$	18.82		$	20.34

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Medium Crude Oil Netbacks (1)

	Year ended December 31
	2003		2002			2001
	(per boe)
Sales revenues	$	31.57	$	29.92		$	23.86
Royalties		5.28		5.59			4.39
Hedging (gain)/loss		1.79		(0.19	)		—
Operating costs		9.53		7.19			7.18
Netback	$	14.97	$	17.33		$	12.29

Heavy Crude Oil Netbacks (1)

	Year ended December 31
	2003		2002		2001
	(per boe)
Sales revenues	$	25.98	$	26.48	$	17.20
Royalties		2.76		3.45		1.93
Operating costs		9.09		7.18		7.40
Netback	$	14.13	$	15.85	$	7.87

Natural Gas Netbacks (2)

	Year ended December 31
	2003			2002		2001
	(per mcfge)
Sales revenues	$	5.79		$	3.97	$	5.39
Royalties		1.29			0.81		1.30
Hedging (gain)/loss		(0.08	)		—		—
Operating costs		0.79			0.70		0.58
Netback	$	3.79		$	2.46	$	3.51

Total Western Canada Upstream Netbacks (1)

	Year ended December 31
	2003		2002			2001
	(per boe)
Sales revenues	$	31.58	$	27.04		$	26.42
Royalties		5.48		4.46			5.04
Hedging (gain)/loss		0.14		(0.05	)		—
Operating costs		7.56		6.54			6.08
Netback	$	18.40	$	16.09		$	15.30

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

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Terra Nova Crude Oil Netbacks

	Year ended December 31
	2003		2002		2001
	(per boe)
Sales revenues	$	38.91	$	35.47	$	—
Royalties		0.81		0.36		—
Hedging (gain)/loss		1.95		—		—
Operating costs		3.16		3.62		—
Netback	$	32.99	$	31.49	$	—

Wenchang Crude Oil Netbacks

	Year ended December 31
	2003		2002		2001
	(per boe)
Sales revenues	$	41.45	$	44.36	$	—
Royalties		3.80		2.65		—
Operating costs		1.94		2.15		—
Netback	$	35.71	$	39.56	$	—

Total Upstream Netbacks (1)

	Year ended December 31
	2003		2002			2001
	(per boe)
Sales revenues	$	32.69	$	28.12		$	26.42
Royalties		5.11		4.20			5.04
Hedging (gain)/loss		0.23		(0.05	)		—
Operating costs		6.92		6.24			6.08
Netback	$	20.43	$	17.73		$	15.30

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

Midstream

2003 Compared with 2002

      Total midstream earnings increased by $24 million (15 percent) to $185 million in 2003 from $161 million in 2002.

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Upgrading Earnings Summary

		Year ended December 31
		2003			2002			2001
		($ millions, except where indicated)
Gross margin		$	313		$	246		$	428
Operating costs			205			154			192
Other expenses (recoveries)			(4	)		(6	)		(12	)
DD&A			20			18			17
Income taxes			21			26			73
Earnings		$	71		$	54		$	158
Upgrader throughput (1)	(mbbls/day)		72.5			65.4			71.7
Synthetic crude oil sales	(mbbls/day)		63.6			59.3			59.5
Upgrading differential	($/bbl)	$	12.88		$	10.81		$	17.91
Unit margin	($/bbl)	$	13.51		$	11.05		$	19.79
Unit operating cost (2)	($/bbl)	$	7.77		$	6.48		$	7.35

(1)	Throughput includes diluent returned to the field.
(2)	Based on throughput.

     Upgrading earnings increased by 31 percent in 2003 primarily due to:

• wider upgrading differential, which averaged $12.88/bbl in 2003 versus $10.81/bbl in 2002

• higher throughput and sales volume

partially offset by:

• higher unit operating costs, which were primarily energy related

Upgrading Earnings Variance Analysis

		($ millions)
Year ended December 31, 2001		$	158
	Volume		(1	)
	Differential		(181	)
	Operating costs — energy related		39
	Operating costs — non-energy related		(1	)
	Other		(6	)
	DD&A		(1	)
	Income taxes		47
Year ended December 31, 2002			54
	Volume		18
	Differential		49
	Operating costs — energy related		(49	)
	Operating costs — non-energy related		(2	)
	Other		(2	)
	DD&A		(2	)
	Income taxes		5
Year ended December 31, 2003		$	71

12

Infrastructure and Marketing Earnings Summary

		Year ended December 31
		2003		2002		2001
		($ millions, except where
		indicated)
Gross margin
	Pipeline	$	66	$	55	$	86
	Other infrastructure and marketing		141		147		111
			207		202		197
Other expenses			8		10		10
DD&A			21		20		17
Income taxes			64		65		72
Earnings		$	114	$	107	$	98
Aggregate pipeline throughput (mbbls/day)			484		457		537

      Infrastructure and marketing earnings increased by seven percent in 2003 primarily due to:

• higher heavy crude oil pipeline throughput

• higher cogeneration income

partially offset by:

• lower crude oil and natural gas commodity marketing margins

Refined Products

2003 Compared with 2002

      Total refined products earnings decreased by $4 million (13 percent) to $28 million in 2003 from $32 million in 2002. Light oil refined products earnings decreased primarily due to lower fuel margins. Earnings from asphalt products operations increased reflecting strong margins and sales volumes.

Refined Products Earnings Summary

			Year ended December 31
			2003		2002		2001
			($ millions, except where
			indicated)
Gross margin
	Fuel sales		$	71	$	81	$	69
	Ancillary sales			28		26		27
	Asphalt sales			51		45		106
				150		152		202
Operating and other expenses				70		64		59
DD&A				34		34		31
Income taxes				18		22		49
Earnings			$	28	$	32	$	63
Number of fuel outlets				552		571		580
Refined products sales volume
	Light oil products	(million litres/day)		8.2		7.7		7.6
	Light oil products per outlet	(thousand litres/day)		10.8		10.0		9.5
	Asphalt products	(mbbls/day)		22.0		20.8		21.4
Refinery throughput
	Prince George refinery	(mbbls/day)		10.3		10.1		10.2
	Lloydminster refinery	(mbbls/day)		25.7		22.0		23.7

13

Corporate

2003 Compared with 2002

Interest

      Interest — net, which is total debt charges net of interest income and capitalized interest, was $73 million in 2003 compared with $104 million in 2002. Interest capitalized in 2003 was $52 million compared with $26 million in 2002 reflecting the higher aggregate capital invested in the White Rose development project in 2003. Interest income was $6 million in 2003 compared with $1 million in 2002. Total interest on short- and long-term debt in 2003 was $131 million, the same as in 2002. During 2003 interest on lower debt levels was offset by the effect of higher after swap interest rates. The impact of the interest rate risk management activities was a reduction to interest expense of $17 million in 2003. Husky’s effective interest rate for 2003 after the effect of interest rate swaps was 6.32 percent compared with 5.48 percent during 2002.

Foreign Exchange

      Foreign exchange gains of $215 million in 2003 comprised $315 million of gains on U.S. dollar denominated long-term debt partially offset by $73 million of cross currency swap losses and $27 million of foreign exchange losses on other monetary items.

Consolidated Income Taxes

      Consolidated income taxes increased in 2003 to $474 million from $420 million in 2002 as a result of higher pre-tax earnings. Income taxes in 2003 were partially offset by a number of non-recurring benefits. On June 13, 2003, Bill C-48 received first reading in the House of Commons and thus was considered to be substantively enacted. This amendment to the Income Tax Act reduces the income tax rate on resource income by seven percent, provides for the deduction from income of crown royalties and eliminates the resource allowance deduction. The amendment will be phased in over a five-year period. The total benefit recorded was $141 million. In addition, a non-recurring benefit totalling $20 million was recorded pursuant to Bill 41, the Alberta Corporate Tax Amendment Act, 2003. Both benefits reduced future income taxes. During 2002, a non-recurring benefit of $31 million was recorded with respect to federal, Alberta and British Columbia income tax rate reductions.

      In 2003 current income taxes totalled $147 million and comprised $73 million with respect to the Wenchang oil field operation, $22 million of capital taxes and $52 million of Canadian income tax.

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

	2003		2002
	($ millions)
Income taxes as reported	$	474	$	420
Canadian federal and provincial tax changes		161		31
Pro forma income taxes	$	635	$	451

      At December 31, 2003 and 2002, Husky’s Canadian tax pools consisted of the following:

	2003		2002
	($ millions)
Canadian exploration expense	$	42	$	440
Canadian development expense		1,103		967
Canadian oil and gas property expense		814		1,066
Foreign exploration and development expense		142		172
Undepreciated capital costs		2,909		2,305
Other		22		56
	$	5,032	$	5,006

14

CAPITAL RESOURCES

Operating Activities

      In 2003 cash generated by operating activities was $2,572 million, an increase of $680 million from the $1,892 million recorded in 2002. The higher cash from operating activities in 2003 was primarily due to higher commodity prices and a change in non-cash working capital.

Financing Activities

      In 2003 cash used in financing activities amounted to $800 million. The cash used was composed of the repayment of long-term debt of $971 million, payment of the return on capital securities of $29 million, dividends of $580 million, including a $1.00 per share special dividend and settlement of a cross currency swap of $32 million. Cash provided by financing activities in 2003 comprised $598 million issuance of long-term debt and $71 million utilization of operating lines, $51 million of proceeds from the exercise of stock options, proceeds from interest rate swaps totalling $44 million and a change of $48 million in non-cash working capital.

      Husky’s long-term debt balances were also reduced by $315 million during 2003 as a result of the narrowing of the exchange rate between Canadian and U.S. currencies.

Investing Activities

      Cash used in investing activities amounted to $2,075 million in 2003, an increase of $486 million from the $1,589 million in 2002. Cash invested in 2003 was composed of capital expenditures of $1,905 million, acquisition of Marathon Canada Limited and the Western Canadian assets of Marathon International Petroleum Canada, Ltd. (“Marathon Canada”) for $809 million partially offset by $511 million of proceeds from asset sales, primarily certain Marathon Canada properties. Change in non-cash working capital and other adjustments amounted to $128 million provided by investing activities.

Capital Expenditures

      The following table shows Husky’s capital expenditures for the years ended December 31:

			Year ended December 31
			2003 (1)		2002		2001
			($ millions)
Upstream
	Exploration
		Western Canada	$	326	$	304	$	236
		East Coast Canada		24		41		81
		International		26		9		5
				376		354		322
	Development
		Western Canada		872		730		786
		East Coast Canada		533		417		110
		International		—		66		99
				1,405		1,213		995
				1,781		1,567		1,317
Midstream
	Upgrader			25		41		47
	Infrastructure and marketing			18		17		58
				43		58		105
Refined Products				58		44		29
Corporate				23		23		22
			$	1,905	$	1,692	$	1,473

(1) 2003 does not include the acquisition of Marathon Canada.

15

Upstream Capital Expenditures

Western Canada

      During 2003 capital expenditures for exploration and development in Western Canada totalled $1,198 million compared with $1,034 million during 2002.

      Total development spending in Western Canada during 2003 amounted to $872 million compared with $730 million during 2002. In 2003 development capital was directed to the following areas:

• Alberta northwest plains area, $183 million for shallow natural gas drilling, completions and installation of facilities in the Boyer/ Cherpeta districts.

• Lloydminster heavy oil area, $303 million for continued exploitation and optimization including work on the Bolney/ Celtic thermal project, with a year-end exit rate of 10 mbbls/day. Lloydminster capital expenditures during 2002 and 2001 were $273 million and $324 million, respectively.

• East central and southern Alberta and southern Saskatchewan, $259 million primarily for in-fill drilling, facilities optimization, acquisitions and development of the Shackleton/ Lacadena natural gas project in southwestern Saskatchewan. By the end of 2003, 240 net wells had been drilled and completed in the Shackleton area. Capital expenditures in the east central and southern Alberta and southern Saskatchewan areas totalled $180 million and $193 million during 2002 and 2001, respectively.

• British Columbia and Alberta foothills area, $122 million for facilities optimization and in-fill drilling at major Alberta foothills natural gas properties. Capital expenditures in the British Columbia and Alberta foothills area totalled $105 million and $115 million during 2002 and 2001, respectively.

      Exploration expenditures on Husky’s prospects in the Western Canada Sedimentary Basin in 2003 amounted to $326 million compared with $304 million in 2002. The primary exploration targets were natural gas prospects in the Alberta foothills as well as step-out drilling throughout Husky’s properties in the Basin. In addition, pre-development spending during 2003 on the oil sands projects at Sunrise and Tucker, Alberta included in exploration capital expenditures amounted to $41 million. Capital expenditures on the oil sands projects totalled $20 million and $8 million during 2002 and 2001, respectively.

Western Canada Drilling

		Year ended December 31
		2003				2002				2001
		Gross		Net		Gross		Net		Gross		Net
		(wells)
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
Total			1,301		1,221		1,215		1,126		1,129		1,026

East Coast Canada

      Capital expenditures at Husky’s White Rose oil field development offshore Newfoundland and Labrador amounted to $505 million in 2003 compared with $395 million in 2002. Capital expenditures with respect to the Terra Nova oil field amounted to $28 million in 2003 compared with $22 million in 2002.

      Capital expenditures for the 2003 East Coast exploration program amounted to $24 million.

16

International

      Exploration spending in the South China Sea amounted to $26 million in 2003 compared with $9 million in 2002. Spending in 2003 was primarily related to drilling two exploration wells and preparation for an exploration program that involved shooting an extensive seismic program in blocks 23-15, 39-05 and 40-30 followed by interpretation of the data. Drilling is expected to commence in the fourth quarter of 2004.

Midstream Capital Expenditures

      Midstream capital expenditures in 2003 of $43 million were primarily for upgrader, pipeline and cogeneration plant upgrades and upgrader debottlenecking front-end engineering.

Refined Products Capital Expenditures

      Refined products capital expenditures in 2003 of $58 million were primarily for marketing outlet improvements and refinery maintenance.

Corporate Capital Expenditures

      Corporate capital expenditures amounted to $23 million in 2003 and 2002 and were primarily for computer hardware and software and office furniture and equipment.

Oil and Gas Reserves

      One of the fundamental measures of value creation is the efficient addition of oil and gas reserves. During the three years ended December 31, 2003, Husky replaced an average of 105 percent of production on a boe basis, inclusive of acquisitions and divestitures.

      During 2003, additions to proved natural gas reserves amounted to 485 bcf. Field extensions and improved recovery at Craigend, Alberta and Muskwa and Bivouac, British Columbia totalled 187 bcf, discoveries in the Alberta foothills area amounted to 114 bcf and acquisitions added 184 bcf, primarily from the acquisition of Marathon Canada, which accounted for 180 bcf. Natural gas revisions reduced reserves by 275 bcf due to a reclassification of proved natural gas reserves for Madura, Indonesia, water incursion at Ricinus in the Alberta foothills area and higher shallow gas declines at Caribou and Evergreen, Alberta. Non-core divestitures amounted to 23 bcf.

      During 2003, 57 mmbbls were added to proved crude oil and NGL reserves. Additions to proved reserves from discoveries and extensions totalled 36 mmbbls primarily in the Lloydminster heavy oil area. Revisions of 9 mmbbls reflect positive technical revisions of 14 mmbbls supported by improved performance primarily in the Lloydminster area partially offset by revisions of 5 mmbbls primarily due to a reclassification of NGL reserves at Madura, Indonesia. Acquisitions of proved reserves added 12 mmbbls, 9 mmbbls of which was acquired with Marathon Canada. Non-core property divestitures were 5 mmbbls in 2003.

      At December 31, 2003, the present value of future net cash flows after tax from the Company’s proved oil and gas reserves, based on prices and costs in effect at year-end and discounted at 10 percent, was $5.8 billion compared with $7.2 billion at the end of 2002.

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

17

Summary of Reserves

Light Crude Oil & NGL Reserves

	Year ended December 31
	2003				2002				2001
	Gross		Net		Gross		Net		Gross		Net
	(mmbbls)
Proved developed		200		177		193		171		175		153
Proved undeveloped		23		18		42		32		65		58
Total proved		223		195		235		203		240		211

Medium Crude Oil Reserves

	Year ended December 31
	2003				2002				2001
	Gross		Net		Gross		Net		Gross		Net
	(mmbbls)
Proved developed		86		73		94		79		109		95
Proved undeveloped		8		7		13		12		18		16
Total proved		94		80		107		91		127		111

Heavy Crude Oil Reserves

	Year ended December 31
	2003				2002				2001
	Gross		Net		Gross		Net		Gross		Net
	(mmbbls)
Proved developed		156		144		152		139		141		131
Proved undeveloped		71		66		75		68		91		87
Total proved		227		210		227		207		232		218

Natural Gas Reserves

	Year ended December 31
	2003				2002				2001
	Gross		Net		Gross		Net		Gross		Net
	(bcf)
Proved developed		1,712		1,423		1,547		1,273		1,577		1,342
Proved undeveloped		347		294		548		440		389		332
Total proved		2,059		1,717		2,095		1,713		1,966		1,674

Barrels of Oil Equivalent

	Year ended December 31
	2003				2002				2001
	Gross		Net		Gross		Net		Gross		Net
	(mmboe)
Proved developed		727		632		697		601		688		603
Proved undeveloped		160		140		221		185		239		216
Total proved		887		772		918		786		927		819

18

Reserve Life Index (1)

	Year ended December 31
	2003		2002		2001
	(years)
Light crude oil & NGL		8.6		9.8		14.1
Medium crude oil		6.6		6.5		7.4
Heavy crude oil		6.2		6.5		7.6
Natural gas		9.2		10.1		9.4
Barrels of oil equivalent		7.8		8.4		9.3

(1) Includes total proved reserves.

Reserve Reconciliation (1)

		Canada															International						Total
		Western Canada												East Coast
		Light															Light
		Crude Oil			Medium			Heavy			Natural			Light			Crude Oil			Natural			Crude Oil			Natural
		& NGL			Crude Oil			Crude Oil			Gas			Crude Oil			& NGL			Gas			& NGL			Gas
		(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(bcf)
Proved reserves, before royalties (2)
Proved reserves at December 31, 2000			181.2			135.7			186.7			1,766.1			11.3			39.1			142.9			554.0			1,909.0
	Revisions		6.5			0.3			18.9			22.5			1.2			0.2			—			27.1			22.5
	Purchases		2.4			9.5			23.7			23.7			—			—			—			35.6			23.7
	Sales		—			(1.8	)		—			(21.1	)		—			—			—			(1.8	)		(21.1	)
	Discoveries, extensions and improved recovery		9.0			1.0			33.3			240.7			4.8			1.2			—			49.3			240.7
	Production		(16.9	)		(17.2	)		(30.6	)		(209.0	)		—			(0.1	)		—			(64.8	)		(209.0	)
Proved reserves at December 31, 2001			182.2			127.5			232.0			1,822.9			17.3			40.4			142.9			599.4			1,965.8
	Revisions		(4.8	)		9.7			7.0			(37.2	)		—			—			—			11.9			(37.2	)
	Purchases		0.2			—			4.7			6.2			—			—			—			4.9			6.2
	Sales		(1.8	)		(14.2	)		(0.4	)		(19.0	)		—			—			—			(16.4	)		(19.0	)
	Discoveries, extensions and improved recovery		5.3			0.9			18.5			386.5			18.5			1.2			—			44.4			386.5
	Production		(14.6	)		(16.4	)		(34.7	)		(207.8	)		(4.8	)		(4.5	)		—			(75.0	)		(207.8	)
Proved reserves at December 31, 2002			166.5			107.5			227.1			1,951.6			31.0			37.1			142.9			569.2			2,094.5
	Revisions		5.0			1.3			6.4			(131.6	)		0.8			(4.5	)		(142.9	)		9.0			(274.5	)
	Purchases		9.3			—			2.8			183.9			—			—			—			12.1			183.9
	Sales		(0.9	)		(2.5	)		(1.4	)		(23.1	)		—			—			—			(4.8	)		(23.1	)
	Discoveries, extensions and improved recovery		5.4			1.9			28.4			301.0			—			—			—			35.7			301.0
	Production		(11.8	)		(14.3	)		(36.5	)		(222.9	)		(6.1	)		(8.2	)		—			(76.9	)		(222.9	)
Proved reserves at December 31, 2003			173.5			93.9			226.8			2,058.9			25.7			24.4			—			544.3			2,058.9
Proved developed reserves, before royalties (3)
	December 31, 2000		167.5			117.6			117.5			1,579.9			—			0.5			—			403.1			1,579.9
	December 31, 2001		168.6			108.7			141.0			1,576.5			6.2			0.6			—			425.1			1,576.5
	December 31, 2002		154.8			93.6			152.4			1,546.5			7.4			30.7			—			438.9			1,546.5
	December 31, 2003		158.5			85.8			156.2			1,712.4			17.2			24.4			—			442.1			1,712.4
Probable reserves, before royalties (4)(5)
	December 31, 2000		72.4			35.2			105.7			434.1			202.3			5.3			18.9			420.9			453.0
	December 31, 2001		72.0			36.0			105.0			405.6			213.3			4.2			18.9			430.5			424.5
	December 31, 2002		70.3			24.1			152.0			383.9			201.6			4.2			18.9			452.2			402.8
	December 31, 2003		61.0			13.8			171.3			381.3			182.2			7.0			66.5			435.3			447.8

(1)

Husky applied for and was granted an exemption from National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” to provide oil and gas reserves disclosures in accordance with the U.S. Securities and Exchange Commission guidelines and the U.S. Financial Accounting Standards Board disclosure standards. The information disclosed may differ from information prepared in accordance with National Instrument 51-101. Husky’s internally generated oil and gas reserves data was audited by an independent firm of consulting engineers.

(2)

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

19

(3)	Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
(4)	Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves (Canadian Oil and Gas Evaluation Handbook). The Securities and Exchange Commission in the United States does not generally permit disclosure of probable reserves to be included in filed documents due to the higher level of uncertainty associated with probable reserves.
(5)	Heavy crude oil probable reserves include bitumen located in the oil sands designated regions of Alberta.

Finding and Development Costs

Western Canada (1)

	Year ended December 31
	2001-2003		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 cost per boe	$	10.62	$	14.79	$	10.49	$	7.90

(1) Excludes oil sands and acquisitions/ divestitures.

Production Replacement

Total

	Year ended December 31
	2001-2003		2003		2002		2001
Production (mmboe)		323.3		114.1		109.6		99.6
Proved reserve additions and revisions (mmboe)		284.0		49.1		114.5		120.4
Production replacement ratio (excluding acquisitions/ divestitures) (percent)		88		43		104		121
Proved reserve additions and revisions (including acquisitions/ divestitures) (mmboe)		338.6		83.2		100.9		154.5
Production replacement ratio (including acquisitions/ divestitures) (percent)		105		73		92		155

Western Canada (1)

	Year ended December 31
	2001-2003		2003		2002		2001
Production (mmboe)		299.4		99.7		100.2		99.5
Proved reserve additions and revisions (mmboe)		284.3		76.6		94.8		112.9
Production replacement ratio (excluding acquisitions/ divestitures) (percent)		95		77		95		113
Proved reserve additions and revisions (including acquisitions/ divestitures) (mmboe)		338.9		110.7		81.2		147.0
Production replacement ratio (including acquisitions/ divestitures) (percent)		113		111		81		148

(1) Excludes oil sands.

Recycle Ratio

      The recycle ratio measures the efficiency of Husky’s capital program by comparing the cost of finding and developing proved reserves with the netback from production. The ratio is calculated by dividing the operating netback by the proved finding and development cost on a boe basis.

20

Western Canada (1)

	Year ended December 31
	2001-2003		2003		2002		2001
Operating netback ($/boe)	$	16.60	$	18.40	$	16.09	$	15.30
Proved finding and development cost ($/boe)	$	10.62	$	14.79	$	10.49	$	7.90
Recycle ratio		1.56		1.24		1.53		1.94

(1) Excludes oil sands.

Undeveloped Land Holdings

		Year ended December 31
		2003				2002
		Gross		Net		Gross		Net
		(thousands of acres)
Western Canada
	Alberta		5,508		4,852		5,416		4,907
	Saskatchewan		2,057		1,911		2,098		1,986
	British Columbia		713		491		314		273
	Manitoba		9		8		13		13
			8,287		7,262		7,841		7,179
Northwest Territories and Arctic			527		184		463		175
Eastern Canada			2,414		2,104		2,414		2,104
Total Canada			11,228		9,550		10,718		9,458
International			4,464		2,066		4,464		2,066
Total			15,692		11,616		15,182		11,524

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LIQUIDITY

Sources of Capital

      As at December 31, 2003 Husky’s outstanding long-term debt totalled $1,698 million, including amounts due within one year, compared with $2,385 million at December 31, 2002.

      At December 31, 2003 Husky had no funds drawn under its $830 million revolving syndicated credit facility. Interest rates under this facility vary and are based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected, credit ratings assigned by certain rating agencies to the Company’s senior unsecured debt and whether the facility is revolving or non-revolving. The syndicated credit facility requires Husky to maintain a debt to cash flow ratio of less than three times and a consolidated net worth of at least $3.6 billion.

      At December 31, 2003 Husky had no funds drawn under its $100 million credit facility. The terms of this facility are substantially the same as the syndicated credit facility.

      At December 31, 2003 the Company had drawn $71 million and utilized in support of letters of credit $18 million of its $195 million in short-term borrowing facilities. The interest rates applicable to these facilities vary and are based on Canadian prime, Bankers’ Acceptance, money market rates or U.S. dollar equivalents. In addition, Husky utilized $88 million under dedicated letter of credit facilities.

      The Company has an agreement to sell up to $250 million of net trade receivables on a revolving basis. The agreement calls for purchase discounts, based on Canadian commercial paper rates, to be paid on an ongoing basis. As at December 31, 2003, $250 million of net trade receivables had been sold under this agreement. The arrangement matures on January 31, 2009.

      The Company believes that, based on its current forecast for commodity prices for 2004, its 2004 capital program of $2.1 billion and non-cancellable cash contractual obligations and commitments will be funded by operating activities and, to the extent required, available credit facilities. In the event of significantly lower cash flow, the Company would be able to defer certain of its capital spending programs without penalty.

      The Company declared dividends that aggregated $1.38 per share ($580 million) in 2003 including a special dividend of $1.00 per share. The Board of Directors of Husky has established a dividend policy that pays quarterly dividends of $0.10 ($0.40 annually) per common share. The declaration of dividends will be at the discretion of the Board of Directors, which will consider earnings, capital requirements, financial condition of the Company and other relevant factors.

      Cash and cash equivalents at December 31, 2003 totalled $3 million compared with $306 million at the beginning of the year.

Financial Ratios

	Year ended December 31
	2003			2002			2001
Cash flow — operating activities ($ millions)	$	2,572		$	1,892		$	1,930
— financing activities ($ millions)	$	(800	)	$	3		$	(423	)
— investing activities ($ millions)	$	(2,075	)	$	(1,589	)	$	(1,507	)
Debt to capital employed (percent)		23.1			31.8			32.8
Debt to cash flow from operations (times)		0.7			1.1			1.1
Corporate reinvestment ratio (1)		0.9			0.8			0.8

(1) Capital and investment expenditures divided by cash flow from operations.

Credit Ratings

      Husky receives debt ratings from three major rating agencies. In determining Husky’s debt rating the agencies evaluate several factors including, but not limited to, the industry Husky operates in, volatility of the industry, the geographical and business diversity and quality of the Company’s asset base, near- and long-term production growth opportunities, capital allocation and cost structure issues, capital structure and character of oil and gas reserves. There are debt rating features in Husky’s debt covenants that cause a change in interest rates in certain debt facilities and may cause the issuance of letters of credit pursuant to the terms of certain commercial contracts. In addition the Company’s

22

debt ratings could affect the ability of the Company to secure new or additional credit facilities if the rating falls below investment grade.

      At December 31, 2003 Husky had the following credit ratings:

	Debt Rated	Rating
Standard and Poor’s Rating Service	Outlook		Positive
	Senior unsecured debt		BBB
	8.45% senior secured bonds		BBB
	Capital securities		BB+
Moody’s Investor Service	Outlook		Stable
	Senior unsecured debt		Baa2
	8.45% senior secured bonds		Baa2
	Capital securities		Ba1
Dominion Bond Rating Service	Outlook		Stable
	Senior unsecured long-term notes		BBB (high)
	Capital securities		BBB

Capital Requirements

      Husky plans to invest capital in the following segments in 2004:

		Year ended
		December 31
		2004 Estimate
		($ millions)
Upstream
	Western Canada	$	1,150
	East Coast Canada		585
	International		65
			1,800
Midstream			100
Refined Products			150
Corporate			30
		$	2,080

      In order to retain undeveloped acreage Husky is required to drill wells within a certain time frame otherwise the acreage is relinquished. In order to maintain its undeveloped acreage at current retention rates over the period 2004 to 2007, Husky estimates drilling expenditures of approximately $75 million in 2004, $65 million in 2005 and $45 million during both 2006 and 2007.

Contractual Obligations and Commercial Commitments

      In the normal course of business Husky is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.

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Contractual Obligations

			Payments Due by Period
	Total		2004-2006		2007-2008		Thereafter
			($ millions)
Long-term debt	$	1,698	$	545	$	146	$	1,007
Capital securities		291		—		—		291
Operating leases		514		194		145		175
Firm transportation agreements		1,788		679		369		740
Unconditional purchase obligations		915		776		124		15
Exploration lease agreements		497		167		97		233
Engineering and construction commitments		597		597		—		—
	$	6,300	$	2,958	$	881	$	2,461

Investment Canada Undertakings

      In respect of the acquisition of Marathon Canada, Husky confirmed certain undertakings to the Minister Responsible for the Investment Canada Act. The undertakings included capital expenditures on the purchased and retained Marathon Canada lands amounting to $65 million, spending on community activities amounting to $1.35 million and environmental expenditures of $40 million, all to occur in 2004.

Asset Retirement Obligations

      The above table does not include asset retirement obligations. The Company currently includes such obligations in the amortizing base of its oil and gas properties. Effective January 1, 2004 with the adoption of the Canadian Institute of Chartered Accountants (“CICA”) section 3110, “Asset Retirement Obligations”, the Company will record a separate liability for the fair value of its asset retirement obligations. See note 20 to the Consolidated Financial Statements.

Post-retirement Benefit Obligations

      The above table does not include post-retirement obligations. Husky has a defined contribution pension plan and a post-retirement health and dental care plan for its employees. In addition Husky has a defined benefit pension plan for approximately 230 employees. In 1991 admittance to the defined benefit pension plan ended after the majority of members transferred to the newly created defined contribution pension plan.

Other Obligations

      Husky is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing and financial impact of these events or rulings prevents any meaningful measurement, which is necessary to assess impact on future liquidity. Such obligations include environmental contingencies, contingent consideration and potential settlements resulting from litigation.

Off Balance Sheet Arrangements

      Husky does not currently utilize any off balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions or for any other purpose.

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TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS

      Husky, in the ordinary course of business, entered into a lease for an eight-year term effective September 1, 2000 with Western Canadian Place Ltd. The terms of the lease provide for the lease of office space, management services and operating costs at commercial rates. Western Canadian Place Ltd. is indirectly controlled by Husky’s principal shareholders. During 2003 Husky paid approximately $17 million for office space in Western Canadian Place.

      Husky did not have any customers that constituted more than five percent of total sales and operating revenues during 2003.

FINANCIAL AND DERIVATIVE INSTRUMENTS

      Husky is exposed to market risks related to the volatility of commodity prices, foreign exchange rates and interest rates. Refer to the section “Business Environment”. Husky, from time to time, uses derivative instruments to manage its exposure to these risks.

Commodity Price Risk Management

      Husky uses derivative commodity instruments to manage exposure to price volatility on a portion of its oil and gas production and firm commitments for the purchase or sale of crude oil and natural gas.

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

Natural Gas

      The 2003 natural gas hedging program was in effect from April 2003 to December 2003. During that period Husky received net payments totalling $24 million on these contracts.

      At December 31, 2003 Husky had natural gas swap agreements in place to hedge 2004 production. The contracts were as follows:

Natural Gas Hedges

							Unrecognized
	Notional Volumes		Term		Price		Gain/(Loss)
	(mmcf/day)						($ millions)
NYMEX fixed price		70		February 2004		U.S.  $6.69/mmbtu	$	1
		70		March 2004		U.S.  $6.69/mmbtu		2
		20		April 2004		U.S.  $6.38/mmbtu		1
							$	4

Crude Oil

      Crude oil hedges on 27.6 mmbbls were in effect from January to December 2003. During that period Husky recorded net payments totalling $36 million on these contracts.

      Husky had a put option contract in effect from July to December 2003 on 3.7 mmbbls of crude oil with a strike price of U.S. $27/bbl. The contract was a full-term settlement contract. Husky paid $8 million for the contract which was charged to earnings over the contract period.

      At December 31, 2003 Husky had crude oil swap agreements in place to hedge 2004 production. The contracts were as follows:

Crude Oil Hedges

							Unrecognized
	Notional Volumes		Term		Price		Gain/(Loss)
	(mbbls/day)						($ millions)
NYMEX fixed price		85		Jan. to Dec. 2004	U.S.  $	27.46/bbl	$	(109	)

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Power Consumption

      At December 31, 2003 Husky had hedged power consumption as follows:

Power Consumption Hedges

							Unrecognized
	Notional Volumes		Term		Price		Gain/(Loss)
	(MW)						($ millions)
Fixed price purchase		20.0		Jan. to Dec. 2004	$	46.25/MWh	$	1
		17.5		Jan. to Dec. 2004	$	47.25/MWh		1
							$	2

Foreign Currency Risk Management

      At December 31, 2003, the Company had the following cross currency debt swaps in place:

• U.S. $150 million at 7.125 percent swapped at $1.4500 to $218 million at 8.74 percent until November 15, 2006.

• U.S. $150 million at 6.250 percent swapped at $1.4100 to $212 million at 7.41 percent until June 15, 2012.

      At December 31, 2003 the cost of a U.S. dollar in Canadian currency was $1.2924.

      In 2003 the cross currency swaps resulted in an offset to foreign exchange gains on translation of U.S. dollar denominated debt amounting to $73 million.

Interest Rate Risk Management

      In 2003 the interest rate risk management activities resulted in a decrease to interest expense of $17 million.

      The cross currency swaps resulted in an addition to interest expense of $13 million in 2003.

      Husky has an interest rate swap on $200 million of long-term debt effective February 8, 2002 whereby 6.95 percent was swapped for CDOR + 175 bps until July 14, 2009. During 2003 this swap resulted in an offset to interest expense amounting to $4 million.

      Husky has an interest rate swap on U.S. $200 million of long-term debt effective February 12, 2002 whereby 7.55 percent was swapped for an average U.S. LIBOR + 194 bps until November 15, 2011. During 2003 this swap resulted in an offset to interest expense amounting to $12 million.

      Husky had three interest rate swaps that were unwound in 2003. During 2003, the impact of these three swaps before they were unwound was an offset to interest expense of $6 million. The amortization of the swap terminations resulted in an additional $8 million offset to interest expense.

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APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

      Husky’s financial statements have been prepared in accordance with generally accepted accounting principles. The significant accounting policies used by Husky are disclosed in note 3 to the Consolidated Financial Statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following discusses such accounting policies and is included in Management’s Discussion and Analysis to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results being reported. Husky’s management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

      The following assessment of significant accounting policies is not meant to be exhaustive. The Company might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

Proved Oil and Gas Reserves

      Proved oil and gas reserves, as defined by the U.S. Securities and Exchange Commission Regulation S-X Rule 4-10, are the estimated quantities of crude oil, natural gas liquids including condensate and natural gas that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

      Reserves are considered proved if they can be produced economically as demonstrated by either actual production or conclusive formation tests. Reserves which must be produced through the application of enhanced recovery techniques are included in the proved category only after successful testing by a pilot project or operation of an installed program in the same reservoir that provides support for the engineering analysis on which the project was based. Proved developed reserves are expected to be produced through existing wells and with existing facilities and operating methods.

      The oil and gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the Company’s plans. The effect of changes in proved oil and gas reserves on the financial results and position of the Company is described under the heading “Full Cost Accounting for Oil and Gas Activities”.

Full Cost Accounting for Oil and Gas Activities

Depletion Expense

      The Company uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development are capitalized whether successful or not. The aggregate of net capitalized costs and estimated future development costs less estimated salvage values is amortized using the unit of production method based on estimated proved oil and gas reserves.

      An increase in estimated proved oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense.

Withheld Costs

      Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.

Impairment of Long-lived Assets

      The Company is required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived asset or oil and gas cost centre is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings.

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Fair Value of Derivative Instruments

      Periodically Husky utilizes financial derivatives to manage market risk. The purpose of the hedge is to provide an element of stability to Husky’s cash flow in a volatile environment. Husky discloses the estimated fair value of open hedging contracts as at the end of a reporting period. Effective January 1, 2004 Husky will adopt CICA Accounting Guideline 13, “Hedging Relationships” (“AcG-13”). AcG-13 has essentially the same criteria to be satisfied before the application of hedge accounting is permitted as the corresponding requirements of the Financial Accounting Standards Board (“FASB”) Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). Refer to the description of FAS 133 in note 20 to the Consolidated Financial Statements.

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

      Accounting rules for transactions involving derivative instruments are complex and subject to a range of interpretation. The FASB has established the Derivative Implementation Group task force, which, on an ongoing basis, considers issues arising from interpretation of these accounting rules. The potential exists that the task force may promulgate interpretations that differ from those of the Company. In this event the Company’s policy would be modified.

Asset Retirement Obligations

      Effective January 1, 2004 the Company will change its accounting policy with respect to accounting for asset retirement obligations. CICA section 3110, essentially the same as FASB’s Statement No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”), requires the fair value of asset retirement obligations to be recorded when they are incurred rather than merely accumulated or accrued over the useful life of the respective asset.

      The Company, under the current policy, is required to provide for future removal and site restoration costs. The Company must estimate these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to earnings and the appropriate liability account over the expected service life of the asset. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are charged to earnings when management is able to determine the amount and the likelihood of the future obligation.

Legal, Environmental Remediation and Other Contingent Matters

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

Income Tax Accounting

      The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

Business Combinations

      Over recent years Husky has grown considerably through combining with other businesses. Husky acquired Marathon Canada in 2003. This transaction was accounted for using what is now the only accounting method available, the purchase method. Under the purchase method, the acquiring company includes the fair value of the assets of the acquired entity on its balance sheet. The determination of fair value necessarily involves many assumptions. The valuation of oil and gas properties primarily relies on placing a value on the oil and gas reserves. The valuation of oil and gas reserves entails the process described above under the caption “Proved Oil and Gas Reserves” but in contrast incorporates the use of economic forecasts that estimate future changes in prices and costs. In addition this

28

methodology is used to value unproved oil and gas reserves. The valuation of these reserves, by their nature, is less certain than the valuation of proved reserves.

Goodwill

      The process of accounting for the purchase of a company, described above, results in recognizing the fair value of the acquired company’s assets on the balance sheet of the acquiring company. Any excess of the purchase price over fair value is recorded as goodwill. Since goodwill results from the culmination of a process that is inherently imprecise the determination of goodwill is also imprecise. In accordance with the recent issuance of FASB Statement No. 142 and CICA section 3062, “Goodwill and Other Intangible Assets”, goodwill is no longer amortized but assessed periodically for impairment. The process of assessing goodwill for impairment necessarily requires Husky to determine the fair value of its assets and liabilities. Such a process involves considerable judgement.

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NEW ACCOUNTING STANDARDS

Asset Retirement Obligations

      In June 2001 the FASB issued FAS 143, “Accounting for Asset Retirement Obligations”. FAS 143 was effective January 1, 2003 for U.S. reporting purposes. The Canadian version of FAS 143, CICA section 3110, which is essentially the same, is effective January 1, 2004. These new methods for accounting for asset retirement obligations require an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When initially recorded, the liability is added to the related property, plant and equipment, subsequently increasing depletion, depreciation and amortization expense. In addition, the liability is accreted for the change in present value in each period. Upon adoption of CICA section 3110, the Company will adjust its existing future removal and site restoration liability retroactively with restatement.

      The Company has estimated that the cumulative effect will be an increase of the future removal and site restoration liability of $129 million, an increase of related net property, plant and equipment of $164 million, an increase to the future income tax liability of $13 million and an increase in retained earnings of $22 million.

Accounting for Derivative Instruments and Hedging Activities

      In June 1998 the FASB issued FAS 133, “Accounting for Derivative Instruments and Hedging Activities”. This was followed in June 2000 when the FASB promulgated FAS 138, which amended FAS 133 and FAS 149, a further modification that was effective for contracts entered into or modified after June 30, 2003. In Canada the Accounting Standards Board (“AcSB”) intends to bring Canadian accounting standards into line with those in the U.S. by a two-stage approach. The first stage is an amendment to AcG-13, “Hedging Relationships”, which is effective January 1, 2004 and establishes criteria to be satisfied before hedge accounting may be applied. The second stage comprises three exposure drafts that were issued on March 31, 2003. The culmination of stage two is expected to complete the harmonization of the Canadian accounting for derivatives, for all intents and purposes, with U.S. GAAP.

      These accounting standards require that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded on the balance sheet as either an asset or liability measured at fair value. These standards further establish that changes in the fair value be recognized currently in earnings unless the arrangement can meet the “effective hedge” criteria.

Stock-based Compensation Plans

      In October 1995 the FASB issued Statement No. 123, “Accounting for Stock-based Compensation Plans” (“FAS 123”), which established a fair value method of accounting for stock-based compensation and required companies that continued to account for stock-based compensation in accordance with the “intrinsic method” to provide a pro forma disclosure that reflects the difference between the two methods. In January 2003 the FASB issued FAS 148, an amendment to FAS 123, which provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. The FASB plans to issue another exposure draft in the first quarter of 2004 and issue the final statement in the second quarter of 2004. Effective January 1, 2004 CICA section 3870, “Stock-based Compensation and Other Stock-based Payments”, will require all public companies to expense all stock-based compensation. This standard provides for the retroactive adoption of fair value accounting effective January 1, 2004. After January 1, 2004 the fair value of stock-based compensation will be recognized as an expense in the financial statements.

Oil and Gas Full Cost Accounting

      In July 2003 the AcSB issued Accounting Guideline 16, “Oil and Gas Accounting — Full Cost” (“AcG-16”), replacing AcG-5. AcG-16 provides for methodology consistent with CICA section 3063, “Impairment of Long-lived Assets”, CICA section 3475, “Disposal of Long-lived Assets and Discontinued Operations” and FASB Statement No. 144, “Accounting for the Impairment and Disposal of Long-lived Assets”.

      The new standards prescribe the recognition of impairment only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and measure the impairment amount as the difference between the carrying amount and the fair value. In addition, discontinued operations disclosure will be required upon the disposition of a component or cost centre of the entity rather than an entire business segment.

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Quarterly Financial Summary

		2003								2002
		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
		($ millions, except where indicated)
Sales and operating revenues, net of royalties		$	1,800	$	1,871	$	1,769	$	2,218	$	1,697	$	1,669	$	1,659	$	1,359
Net earnings		$	245	$	243	$	427	$	406	$	242	$	173	$	263	$	126
Earnings per share
	Basic	$	0.62	$	0.55	$	1.06	$	1.01	$	0.57	$	0.38	$	0.64	$	0.29
	Diluted	$	0.62	$	0.54	$	1.05	$	1.00	$	0.57	$	0.38	$	0.64	$	0.29
Cash flow from operations		$	568	$	604	$	540	$	747	$	635	$	590	$	498	$	373
Share price
	High	$	23.95	$	20.95	$	18.14	$	17.49	$	17.20	$	17.00	$	17.98	$	17.80
	Low	$	20.40	$	17.35	$	16.15	$	16.03	$	15.43	$	14.00	$	15.85	$	14.20
	Close (end of period)	$	23.47	$	20.50	$	17.50	$	16.93	$	16.47	$	16.70	$	16.66	$	17.10
Shares traded (thousands)			22,171		35,453		24,858		18,371		20,478		30,620		31,159		34,383
Dividends declared per share		$	0.10	$	1.10	$	0.09	$	0.09	$	0.09	$	0.09	$	0.09	$	0.09
Number of weighted average common shares outstanding (thousands)
	Basic		421,702		419,729		418,539		418,163		417,748		417,497		417,393		416,939
	Diluted		423,830		422,010		420,331		419,985		419,567		419,136		419,558		418,951

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RESULTS OF OPERATIONS FOR 2002 COMPARED WITH 2001

      The consolidated revenue during 2002 was three percent lower than in 2001 primarily as a result of lower natural gas prices. The effect of lower natural gas prices was most evident in the infrastructure and marketing segment with respect to natural gas marketing revenues.

      Net earnings in 2002 were $804 million compared with $654 million in 2001. The increase of $150 million was attributable to the following:

      Upstream — increase of $206 million

• higher realized crude oil prices and production

• lower natural gas royalties

      partially offset by:

• lower prices for natural gas

• higher operating costs and DD&A

• higher income taxes

      Midstream — decrease of $95 million

• narrower upgrading differential

• lower pipeline throughput

      partially offset by:

• higher oil and gas commodity marketing income

• higher cogeneration income

• lower energy related upgrading operating costs

• lower income taxes

      Refined Products — decrease of $31 million

• lower asphalt product margins

      partially offset by:

• improved gasoline and distillate margins

• lower income taxes

      Corporate — increase of $70 million

• lower foreign exchange losses on translation of U.S. dollar denominated long-term debt

      partially offset by:

• higher intersegment profit eliminations

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FORWARD-LOOKING STATEMENTS

Cautionary Statement for the Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995

      This document contains certain forward-looking statements relating, but not limited, to Husky’s operations, anticipated financial performance, business prospects and strategies and which are based on Husky’s current expectations, estimates, projections and assumptions and were made by Husky in light of experience and perception of historical trends. All statements that address expectations or projections about the future, including statements about strategy for growth, expected expenditures, commodity prices, costs, schedules and production volumes, operating or financial results, are forward-looking statements. Some of Husky’s forward-looking statements may be identified by words like “expects”, “anticipates”, “plans”, “intends”, “believes”, “projects”, “could”, “vision”, “goal”, “objective” and similar expressions. Husky’s business is subject to risks and uncertainties, some of which are similar to other energy companies and some of which are unique to Husky. Husky’s actual results may differ materially from those expressed or implied by Husky’s forward-looking statements as a result of known and unknown risks, uncertainties and other factors.

      The reader is cautioned not to place undue reliance on Husky’s forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, that contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond Husky’s control, that could influence actual results include, but are not limited to:

• fluctuations in commodity prices

• changes in general economic, market and business conditions

• fluctuations in supply and demand for Husky’s products

• fluctuations in the cost of borrowing

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

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

• Husky’s ability to receive timely regulatory approvals

• the integrity and reliability of Husky’s capital assets

• the cumulative impact of other resource development projects

• the accuracy of Husky’s oil and gas reserve estimates, estimated production levels and Husky’s success at exploration and development drilling and related activities

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

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

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

• actions by governmental authorities, including changes in environmental and other regulations

• the ability and willingness of parties with whom Husky has material relationships to fulfil their obligations

• the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Husky or other parties whose operations or assets directly or indirectly affect Husky

      The reader is cautioned that the foregoing list of important factors is not exhaustive. Events or circumstances could cause Husky’s actual results to differ materially from those estimated or projected and expressed in, or implied by, these forward-looking statements.

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EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

      The Company’s chief executive officer and chief financial officer (its principal executive officer and principal financial officer, respectively) have concluded, based on their evaluation as of a date within 90 days prior to the filing of this Annual Report (the “evaluation date”), that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by it in reports filed or submitted by it under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by it in such reports is accumulated and communicated to the Company’s management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

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

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