NEWS RELEASE TRANSMITTED BY Marketwire



FOR: HUSKY ENERGY INC.

TSX SYMBOL:
 HSE

Husky Energy Announces 2005 Third Quarter Results

Oct 18, 2005 - 11:59 ET

CALGARY--(CCNMatthews - Oct. 18) - Husky Energy Inc. reported net earnings of $556 million or $1.31 per share (diluted) in the third quarter of 2005, an 87 percent increase over net earnings of $297 million or $0.70 per share (diluted) in the third quarter of 2004. Included in net earnings for the third quarter of 2005 is a net charge of $54 million related to stock-based compensation and a net gain of $54 million related to U.S. dollar denominated debt translation. Cash flow from operations was $944 million or $2.23 per share (diluted) in the third quarter of 2005, a 65 percent increase compared with $571 million or $1.34 per share (diluted) in the third quarter of 2004. Sales and operating revenues net of royalties were $2.8 billion in the third quarter of 2005, a 26 percent increase compared with $2.2 billion in the third quarter of 2004.

"Our strong operating results in the third quarter of 2005, bolstered by continuing high commodity prices, should lead to a record year for the Company," said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc.

Production in the third quarter of 2005 was 303,200 barrels of oil equivalent per day, compared with 324,800 barrels of oil equivalent per day in the third quarter of 2004. Total crude oil and natural gas liquids production was 190,000 barrels per day, compared with 208,100 barrels per day in the third quarter of 2004. Natural gas production was 679.2 million cubic feet per day, compared with 700.4 million cubic feet per day in the third quarter of 2004.

"Production in crude oil and natural gas was slightly below our expectations due to continued wet weather in Western Canada and lengthy operational issues and a maintenance turnaround at Terra Nova," said Mr. Lau. "Overall, we expect our 2005 annual production to be below the range of our guidance by approximately four percent."

During the third quarter of 2005, Husky made good progress on its White Rose project. The SeaRose FPSO is currently undergoing offshore hook-up and commissioning at the White Rose oil field. First oil is anticipated before year-end and will add approximately 67,500 barrels per day of light oil production net to Husky when it attains full productive capacity.

At the White Rose oil field, Husky began drilling two delineation wells to further define reserves in the South and West Avalon Pools. In September, Husky commenced a 750-square-kilometre 3-D seismic program to assist in defining other potential prospects on several blocks in the Jeanne d'Arc Basin. During the quarter, an exploratory well was drilled at the Lewis Hill prospect in the South Whale Basin. The well was plugged and abandoned without testing.

In the Northwest Territories, Husky completed a 2-D seismic program on Block EL 397 containing the Summit Creek B-44 discovery and announced plans to drill two wells in the Summit Creek area in January 2006. One of the wells will assess the size of the pool discovered by Summit Creek B-44. The other exploration well will test a separate undrilled prospect.

In Central Alberta, Husky is continuing its expansion program to develop coal bed methane or natural gas from coal in the Horseshoe Canyon Formation. Husky and its joint venture partner plan to drill approximately 400 wells in the Fenn Rumsey area near Drumheller in 2006.

At Husky's Tucker oil sands project near Cold Lake, Alberta facility construction continues on schedule and is now 43 percent complete. Drilling of the 30 horizontal well pairs is on target. For Husky's Sunrise 200,000 barrels per day oil sands project near Fort McMurray, Alberta, Husky expects to receive regulatory approval by the end of 2005 or early 2006.

In the South China Sea, Husky drilled Wushi 17-1-1, an exploration well on Block 23/15 in the Beibu Gulf. Hydrocarbons were encountered in the Weizhou Formation at a depth of 2,397 metres. The well was sidetracked to determine the extent of the hydrocarbon zone and the results of the well are still being evaluated. Husky has identified several prospects in the Beibu Gulf and is currently drilling an exploration well on the adjacent Block 23/20.

At Husky's heavy oil Upgrader in Lloydminster, Saskatchewan, a major turnaround was completed. The Upgrader achieved a record of 4.3 million working hours without a lost time accident, which is approximately 9.5 years of operation. The turnaround resulted in the completion of major maintenance as well as the first half of the debottlenecking work that will increase capacity in 2006 to 82,000 barrels per day from 77,000 barrels per day.

Following the successful completion of the first phase of the Clean Fuels Project, Husky is now producing low sulphur gasoline at its Prince George Refinery. The second phase of the project will enable the Refinery to produce low sulphur diesel and increase overall capacity to 12,000 barrels per day from 10,000 barrels per day by mid 2006.

Husky's net earnings for the first nine months of 2005 were $1,334 million or $3.15 per share (diluted), a 71 percent increase over net earnings of $781 million or $1.84 per share (diluted) for the same period in 2004. Cash flow from operations in the first nine months of 2005 was $2,588 million or $6.11 per share (diluted), a 50 percent increase from $1,728 million or $4.07 per share (diluted) for the same period in 2004. Sales and operating revenues net of royalties in the first nine months of 2005 were $7.5 billion, compared with $6.4 billion in the same period of 2004.

Production in the first nine months of 2005 was 310,500 barrels of oil equivalent per day, compared with 325,200 barrels of oil equivalent per day for the same period in 2004. Total crude oil and natural gas liquids production was 196,900 barrels per day, compared with 210,800 barrels per day in the first nine months of 2004. Natural gas production was 681.6 million cubic feet per day, compared with 686.5 million cubic feet per day for the same period in 2004.

MANAGEMENT'S DISCUSSION AND ANALYSIS October 18, 2005

All expectations, forecasts, assumptions and beliefs about our future production, financial results, financial condition and development of our business are forward-looking statements, as described in more detail under the caption "Forward-looking Statements." Our actual financial results and condition may differ materially due to a number of risks and uncertainties. A number of those risks and uncertainties are described under the caption "Business Environment." In particular the reader is cautioned about statements we have made concerning future production and strategic plans contained under the caption "Business Development."



SUMMARY OF QUARTERLY RESULTS

-------------------------------------------------------------------------
Financial Summary(1)

Three months ended
(millions of dollars,
except per share Sept. 30 June 30 March 31 Dec. 31
amounts and ratios) 2005 2005 2005 2004
-------------------------------------------------------------------------
Sales and operating revenues,
net of royalties $ 2,763 $ 2,493 $ 2,201 $ 2,018
Segmented earnings
Upstream $ 445 $ 307 $ 239 $ 112
Midstream 61 130 169 77
Refined Products 27 20 18 (3)
Corporate and eliminations 23 (63) (42) 39
-------------------------------------------------------------------------
Net earnings $ 556 $ 394 $ 384 $ 225
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Per share
- Basic $ 1.31 $ 0.93 $ 0.91 $ 0.53
- Diluted 1.31 0.93 0.91 0.53
Cash flow from operations 944 828 816 469
Per share
- Basic 2.23 1.95 1.93 1.11
- Diluted 2.23 1.95 1.93 1.11
Dividends per common share 0.14 0.14 0.12 0.12
Special dividend per
common share - - - 0.54
Total assets 14,712 14,058 13,690 13,240
Total long-term debt including
current portion 1,896 2,192 2,290 2,103
Return on equity(2) (percent) 22.9 20.2 18.3 17.0
Return on average capital
employed(2) (percent) 17.9 15.3 13.9 13.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Financial Summary(1)

Three months ended
(millions of dollars,
except per share Sept. 30 June 30 March 31 Dec. 31
amounts and ratios) 2004 2004 2004 2003
-------------------------------------------------------------------------
Sales and operating revenues,
net of royalties $ 2,191 $ 2,210 $ 2,021 $ 1,800
Segmented earnings
Upstream $ 161 $ 204 $ 236 $ 169
Midstream 50 53 60 46
Refined Products 18 21 5 6
Corporate and eliminations 68 (49) (46) 31
-------------------------------------------------------------------------
Net earnings $ 297 $ 229 $ 255 $ 252
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Per share
- Basic $ 0.70 $ 0.54 $ 0.60 $ 0.60
- Diluted 0.70 0.54 0.60 0.59
Cash flow from operations 571 581 576 561
Per share
- Basic 1.34 1.37 1.36 1.33
- Diluted 1.34 1.37 1.36 1.32
Dividends per common share 0.12 0.12 0.10 0.10
Special dividend per
common share - - - -
Total assets 12,901 12,542 12,317 11,949
Total long-term debt including
current portion 2,096 2,229 1,993 1,989
Return on equity(2) (percent) 17.7 16.8 21.8 26.4
Return on average capital
employed(2) (percent) 13.4 12.7 16.2 18.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2004 and 2003 amounts as restated. Refer to Note 3 to the
Consolidated Financial Statements.
(2) Calculated for the twelve months ended for the periods shown.



-------------------------------------------------------------------------
Daily Production, before Royalties

Three months ended

Sept. 30 June 30 March 31 Dec. 31 Sept. 30
2005 2005 2005 2004 2004
-------------------------------------------------------------------------
Crude oil and NGL
(mbbls/day)
Western Canada
Light crude
oil & NGL 31.8 31.7 31.9 32.9 33.1
Medium crude oil 30.3 30.6 32.4 33.7 34.5
Heavy crude oil 103.3 100.9 110.4 113.8 108.8
-------------------------------------------------------------------------
165.4 163.2 174.7 180.4 176.4
East Coast Canada
Terra Nova -
light crude oil 10.2 13.5 13.7 10.1 11.5
China
Wenchang -
light crude oil 14.4 17.3 18.5 17.9 20.2
-------------------------------------------------------------------------
190.0 194.0 206.9 208.4 208.1
-------------------------------------------------------------------------
Natural gas
(mmcf/day) 679.2 689.3 676.2 697.4 700.4
-------------------------------------------------------------------------
Total (mboe/day) 303.2 308.9 319.6 324.6 324.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Total crude oil and natural gas production declined by two percent to average 303.2 mboe/day in the third quarter of 2005 from 308.9 mboe/day in the second quarter of 2005. Third quarter production declines resulted from lower production from Terra Nova, which was shut down during the month of September to perform a scheduled turnaround that has been extended to deal with gas compression reliability issues. The decline in production at Wenchang in the third quarter of 2005 compared with the second quarter of 2005 was primarily due to typhoon related downtime. Production from our properties in Western Canada was marginally up during the third quarter of 2005 compared with the second quarter of 2005. Heavy crude oil production increased by two percent, the effect of which was partially offset by a one percent decline in natural gas production. Western Canada third quarter production was maintained compared with the second quarter of 2005 in spite of wet weather issues and a tight market for materials and services, all of which have caused delays in drilling, completion and tie-in programs.

BUSINESS DEVELOPMENT

In each business segment we are executing our strategic plan both in respect of existing operations and for our transition into new areas of sustainable growth.




UPSTREAM
-------------------------------------------------------------------------
Gross Production Nine Nine Year
months months ended
ended ended December
Sept. 30 Forecast(1) Sept. 30 31
2005 2005 2004 2004
-------------------------------------------------------------------------
Crude oil & NGL (mbbls/day)
Light crude oil & NGL 61.0 64 - 71 68.1 66.2
Medium crude oil 31.1 32 - 36 35.4 35.0
Heavy crude oil 104.8 112 - 120 107.3 108.9
-------------------------------------------------------------------------
196.9 208 - 227 210.8 210.1
Natural gas (mmcf/day) 681.6 700 - 740 686.5 689.2
Total barrels of oil equivalent
(mboe/day) 310.5 325 - 350 325.2 325.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) We expect our 2005 annual production to be below the range of our
guidance by approximately four percent.

 


Our conventional oil and gas properties throughout the Western Canada Sedimentary Basin ("WCSB") form the foundation of our upstream business and provide the majority of our cash flow. Although the WCSB is considered to be mature, with production declines typically over 20 percent per annum, this resource base will continue to provide cash flow necessary to fund our emerging growth opportunities offshore Canada's East Coast, in international properties in China and Indonesia and in non-conventional production from oil sands in Western Canada. In addition, we expect to continue to realize additional value by managing our operating costs in the WCSB through consolidation via strategic acquisitions and divestitures and improvements in production technology and practice.

At September 30, 2005, we have invested in the following major development projects offshore Canada's East Coast and in the Alberta oil sands:




-------------------------------------------------------------------------
Project Productive Working
Capacity(1) Interest Schedule
-------------------------------------------------------------------------

White Rose Offshore East Coast 68 mbbls/day 72.5% Late 2005

Tucker Oil sands 30 mbbls/day 100% 2006 - 2007

Sunrise Oil sands 200 mbbls/day(2) 100% 2009 - 2012
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Husky interest.
(2) Sunrise will be developed in phases; ultimate planned rate is
200 mbbls/day.

 


In addition to these major projects currently under development, exploration and development programs in the WCSB are expected to increase production of natural gas from both shallow gas step-out drilling and drilling in the deep basin of Alberta and in the foothills region of Alberta and northeastern British Columbia for high potential natural gas targets. Our exploration program will also target prospects offshore Newfoundland and Labrador, in the Central Mackenzie Valley area of the Northwest Territories, offshore China and in the Madura Strait in Indonesia.

White Rose

The SeaRose FPSO arrived at the White Rose oil field on August 22 and was connected to the subsea production system on August 25. Drilling and completion of the 10 wells required at first oil are progressing with two wells still to be completed. The project is expected to be on schedule to achieve first oil before year-end.

Tucker

At Tucker, a steam-assisted gravity drainage Alberta oil sands project, drilling operations are on schedule at approximately 60 percent completion. The central plant construction is on schedule at approximately 43 percent completion.

Sunrise

At Sunrise, discussions continue to address project related questions of the key stakeholders. Project development activity is progressing with evaluation of marketing and downstream solution options for the project.

Exploration

- Western Canada

In Western Canada during the third quarter of 2005, we drilled a total of 142 gross exploratory wells (78 net) that resulted in 28 gross oil completions (28 net) and 107 gross natural gas completions (43 net).

During the third quarter of 2005, our primary exploration activities were conducted in the foothills, deep basin and northern plains areas of Alberta and British Columbia where we drilled 13 gross exploration wells (7 net) resulting in 13 gross natural gas wells (7 net). Activity in these areas is restricted to less environmentally sensitive areas until the ground is frozen during the winter months.

- Northwest Territories

During the third quarter we conducted a seismic program in the Central Mackenzie Valley in preparation for further testing of the area around the Summit Creek B-44 oil and gas discovery. Several additional structures have been identified and we are currently planning a two well drilling program for this winter.

- East Coast

During the third quarter of 2005, we drilled an exploratory well, the Lewis Hill G-85 in the South Whale Basin, which lies approximately 350 kilometres south of St. John's, Newfoundland and Labrador. The well was plugged and abandoned without testing.

The Lewis Hill rig was subsequently moved to the White Rose oil field where it successfully drilled one pilot hole and a side-track to delineate a northern extension of the White Rose South Avalon reservoir, which is currently under development. The rig is being moved to drill a delineation well into the West Avalon reservoir.

We are currently conducting a 3-D seismic program in the northern Jeanne d'Arc Basin offshore the East Coast of Canada. This survey will provide further information about several identified prospects north of the White Rose oil field.

- China

During the third quarter of 2005, the Wushi 17-1-1 exploration well was drilled on Block 23/15 in the Beibu Gulf. The well was subsequently side- tracked to a new bottom hole location to evaluate the extent of the oil accumulation encountered by the original well bore. The original well bore penetrated an oil column approximately 75 metres thick. The side-tracked well bore encountered a thinner oil column with low flow rates after testing. The size and extent of the discovery is being evaluated based on the well results and seismic data.

The Wushi 32-1-1 well is currently being drilled on the adjacent Block 23/20 in the Beibu Gulf.

- Indonesia

During the third quarter of 2005, development engineering re-validation work commenced for the production facilities at the Madura natural gas development project and negotiations continued toward establishing natural gas sales agreements.

MIDSTREAM

Husky Lloydminster Upgrader

The debottleneck projects are scheduled to increase the plant's throughput capacity from 77 mbbls/day to 82 mbbls/day of synthetic crude oil and diluent. Completion is expected in the third quarter of 2006 with connections made in September 2005 during the scheduled plant turnaround. The projects are expected to cost approximately $60 million.

REFINED PRODUCTS

Prince George Refinery

During the third quarter of 2005, the first phase of the Prince George Refinery Clean Fuels Project was completed. On August 15, gasoline was produced that meets the new Government of Canada specifications for sulphur content. The second phase of the project will modify the refinery to produce low sulphur diesel fuel and increase the plant capacity from 10 mbbls/day to 12 mbbls/day. The second phase is expected to be on stream by the second quarter of 2006.

Lloydminster Ethanol Plant

At September 30, 2005, the ethanol plant currently being constructed at Lloydminster, Saskatchewan, adjacent to the Husky Lloydminster Upgrader, was 55 percent complete and overall construction was 30 percent complete. The plant is scheduled to be completed in the second quarter of 2006.

Minnedosa Ethanol Plant

At Minnedosa, Manitoba the plant expansion project progressed in the early stages of approvals and design engineering. The project would expand the existing ethanol plant from 10 million litres per year to 130 million litres per year. The project is contingent on receiving government approvals, which are expected in October 2005 and having acceptable economics.

BUSINESS ENVIRONMENT

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

- Volatility in crude oil and natural gas prices

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

- Demand for heavier grades of crude oil

- Demand for and ability to deliver natural gas

- The exchange rate between the Canadian and U.S. dollar

- Refined petroleum products margins

- Demand for Husky's pipeline capacity

- Demand for refined petroleum products

- Government regulation

- Cost of capital





-------------------------------------------------------------------------
Average Benchmark Prices and U.S. Exchange Rate

Three months ended

Sept. 30 June 30 March 31 Dec. 31 Sept. 30
2005 2005 2005 2004 2004
-------------------------------------------------------------------------
WTI crude oil(1)
(U.S. $/bbl) $ 63.10 $ 53.17 $ 49.84 $ 48.28 $ 43.88
Canadian par light
crude 0.3%
sulphur ($/bbl) 77.04 66.43 62.02 58.01 56.61
Lloyd @
Lloydminster
heavy crude oil
($/bbl) 44.13 27.95 22.62 25.31 35.47
NYMEX natural gas(1)
(U.S. $/mmbtu) 8.49 6.73 6.27 7.11 5.76
NIT natural gas
($/GJ) 7.75 6.99 6.34 6.72 6.32
WTI/Lloyd crude
blend differential
(U.S. $/bbl) 18.90 21.27 19.57 19.82 12.86
U.S./Canadian
dollar exchange rate
(U.S. $) 0.833 0.804 0.815 0.819 0.765
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Prices quoted are near-month contract prices for settlement during
the next month.

 


COMMODITY PRICE RISK

Our earnings depend largely on the profitability of our upstream business segment which is most 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 our control.




Crude Oil

WTI and Husky Average Crude Oil Prices

($/bbl)

-------------------------------------------------------------------------
Q3-03 Q4-03 Q1-04 Q2-04 Q3-04
-------------------------------------------------------------------------
West Texas
Intermediate
("WTI") (U.S. $) $30.20 $31.18 $35.15 $38.32 $43.88
-------------------------------------------------------------------------
Husky average
light crude oil
price (C $) $38.49 $38.55 $42.50 $47.99 $53.94
-------------------------------------------------------------------------
Husky average
medium crude oil
price (C $) $29.68 $27.25 $32.97 $35.98 $40.59
-------------------------------------------------------------------------
Husky average
heavy crude oil
price (C $) $25.13 $20.84 $26.38 $27.54 $34.92
-------------------------------------------------------------------------


--------------------------------------------------------------
Q4-04 Q1-05 Q2-05 Q3-05
--------------------------------------------------------------
West Texas
Intermediate
("WTI") (U.S. $) $48.28 $49.84 $53.17 $63.10
--------------------------------------------------------------
Husky average
light crude oil
price (C $) $50.29 $58.94 $62.49 $70.59
--------------------------------------------------------------
Husky average
medium crude oil
price (C $) $35.06 $36.50 $40.45 $53.41
--------------------------------------------------------------
Husky average
heavy crude oil
price (C $) $25.81 $22.53 $27.95 $44.17
--------------------------------------------------------------

The prices received for our crude oil and NGL 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 due to
the additional processing costs.

Natural Gas

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

-------------------------------------------------------------------------
Q3-03 Q4-03 Q1-04 Q2-04 Q3-04
-------------------------------------------------------------------------
NYMEX natural gas
(U.S. $/mmbtu) $4.97 $4.58 $5.69 $5.97 $5.76
-------------------------------------------------------------------------
NIT natural gas
(C $/GJ) $5.97 $5.30 $6.26 $6.45 $6.32
-------------------------------------------------------------------------
Husky average
natural gas price
(C $/mcf) $5.40 $4.87 $6.05 $6.38 $5.92
-------------------------------------------------------------------------


--------------------------------------------------------------
Q4-04 Q1-05 Q2-05 Q3-05
--------------------------------------------------------------
NYMEX natural gas
(U.S. $/mmbtu) $7.11 $6.27 $6.73 $8.49
--------------------------------------------------------------
NIT natural gas
(C $/GJ) $6.72 $6.34 $6.99 $7.75
--------------------------------------------------------------
Husky average
natural gas price
(C $/mcf) $6.64 $6.07 $6.76 $7.86
--------------------------------------------------------------

 


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, production disruptions, 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.

Upgrading Differential

The profitability of our heavy oil upgrading operations is dependent upon the amount by which revenues from the synthetic crude oil and related products exceed the costs of the heavy oil feedstock plus the related operating costs, a significant portion of which is energy related. An increase in the price of blended heavy crude oil feedstock that is not accompanied by an equivalent increase in the sales price of synthetic crude oil would reduce the profitability of our upgrading operations. We have significant crude oil production that trades at a discount to light crude oil, and any negative effect of a narrower heavy/light crude oil differential on upgrading operations would be more than offset by a positive effect on revenues in the upstream segment from heavy crude 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. Our ability to maintain refined products margins in an environment of higher feedstock costs is contingent upon our ability to pass on our higher costs to our customers.

Integration

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

FOREIGN EXCHANGE RISK

Our results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities and correspondingly a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky's U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At September 30, 2005, 84 percent or $1.6 billion of our long-term debt was denominated in U.S. dollars. The Cdn/U.S. exchange rate at the end of the third quarter of 2005 was $1.1611. The percentage of our long-term debt exposed to the Cdn/U.S. exchange rate decreases to 56 percent when the cross currency swaps are included. Refer to the section "Financial and Derivative Instruments."

INTEREST RATES

We maintain a portion of our debt in floating rate facilities which are exposed to interest rate fluctuations. We will occasionally fix our floating rate debt or create a variable rate for our fixed rate debt using derivative financial instruments. Refer to the section "Financial and Derivative Instruments."

ENVIRONMENTAL REGULATIONS

Most aspects of Husky's business are subject to environmental laws and regulations. Similar to other companies in the oil and gas industry, we incur costs for preventive and corrective actions in addition to costs incurred for asset retirement obligations. Changes to regulations could have an adverse effect on our results of operations and financial condition.

INTERNATIONAL OPERATIONS

In addition to commodity price risk, Husky's international upstream 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 indicates the relative effect of changes in certain key variables on our pre-tax cash flow and net earnings. The analysis is based on business conditions and production volumes during the third quarter of 2005. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.




-------------------------------------------------------------------------
Sensitivity Analysis

Effect on Pre-tax Effect on
Item Increase Cash Flow Net Earnings
-------------------------------------------------------------------------
($ ($/share) ($ ($/share)
millions) (4) millions) (4)

WTI benchmark
crude oil
price U.S. $1.00/bbl 71 0.17 46 0.11
NYMEX
benchmark
natural gas
price(1) U.S. $0.20/mmbtu 35 0.08 22 0.05
Light/heavy
crude oil
differential
(2) Cdn $1.00/bbl (32) (0.07) (20) (0.05)
Light oil
margins Cdn $0.005/litre 17 0.04 11 0.03
Asphalt
margins Cdn $1.00/bbl 11 0.03 7 0.02
Exchange rate
(U.S. $/Cdn $)
(3) U.S. $0.01 (59) (0.14) (39) (0.09)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $11 million in net earnings based on September 30, 2005 U.S.
dollar denominated debt levels.
(4) Based on September 30, 2005 common shares outstanding of
424.1 million


RESULTS OF OPERATIONS

UPSTREAM
-------------------------------------------------------------------------
Upstream Earnings Summary Three months Nine months
ended Sept. 30 ended Sept. 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross revenues $ 1,422 $ 1,183 $ 3,616 $ 3,293
Royalties 246 197 576 537
Hedging - 169 - 358
-------------------------------------------------------------------------
Net revenues 1,176 817 3,040 2,398
Operating and administration
expenses 262 255 751 720
Depletion, depreciation and
amortization 280 278 831 794
Income taxes 189 123 467 283
-------------------------------------------------------------------------
Earnings $ 445 $ 161 $ 991 $ 601
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Net Revenue Variance Analysis

Crude oil Natural
(millions of dollars) & NGL gas Other Total
-------------------------------------------------------------------------
Three months ended
September 30, 2004 $ 509 $ 291 $ 17 $ 817
Price changes 205 116 - 321
Volume changes (75) (11) - (86)
Royalties (34) (15) - (49)
Hedging 166 3 - 169
Processing and sulphur - - 4 4
-------------------------------------------------------------------------
Three months ended
September 30, 2005 $ 771 $ 384 $ 21 $ 1,176
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended
September 30, 2004 $ 1,457 $ 887 $ 54 $ 2,398
Price changes 357 139 - 496
Volume changes (165) (12) - (177)
Royalties (42) 3 - (39)
Hedging 359 (1) - 358
Processing and sulphur - - 4 4
-------------------------------------------------------------------------
Nine months ended
September 30, 2005 $ 1,966 $ 1,016 $ 58 $ 3,040
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Third Quarter

Upstream earnings were $284 million higher in the third quarter of 2005 than in the third quarter of 2004 as a result of the following factors:

- Higher crude oil, natural gas and sulphur prices

- Hedging diverted $169 million in the third quarter of 2004; third

quarter of 2005 commodity prices were not hedged

- Higher sales volume of sulphur and NGL

Partially offset by:

- Lower sales volume of crude oil and natural gas

- Higher unit operating costs

- Higher unit depletion, depreciation and amortization

- Higher income taxes

Nine Months

The factors that affected upstream performance in the first nine months of 2005 compared with the first nine months of 2004 were essentially the same as those during the third quarter of 2005 and 2004.

Unit Operating Costs

Unit operating costs were eight percent higher in the third quarter of 2005 compared with the same period in 2004 due to higher energy costs, increased natural gas compression costs, higher natural gas well count and production declines. In addition, high commodity prices are affecting rates charged by our service providers with the high level of industry activity creating tight service markets.

Unit Depletion, Depreciation and Amortization

Unit depletion, depreciation and amortization expense increased nine percent in the third quarter of 2005 compared with the same period in 2004. The increase was primarily due to a higher capital base in 2005 as a result of increased requirement for production maintenance capital for our properties in the Western Canada Sedimentary Basin, higher capital expenditures for offshore operations and higher capital costs associated with the purchase of reserves in place. In addition, the higher commodity prices, as with operating costs, increased the cost of materials and services in our capital costs.




-------------------------------------------------------------------------
Average Sales Prices Three months Nine months
ended Sept. 30 ended Sept. 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Crude Oil ($/bbl)
Light crude oil & NGL $ 67.21 $ 53.54 $ 60.85 $ 47.44
Medium crude oil 53.41 40.59 43.34 36.47
Heavy crude oil 44.17 34.92 31.46 29.68
Total average 62.42 41.60 42.43 36.53
Natural Gas ($/mcf)
Average 7.86 5.92 6.90 6.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Effective Royalty Rates(1)
Three months Nine months
Percentage of upstream sales ended Sept. 30 ended Sept. 30
revenues 2005 2004 2005 2004
-------------------------------------------------------------------------
Crude oil & NGL 16% 14% 14% 13%
Natural gas 21% 23% 20% 23%
Total 17% 17% 16% 16%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Before commodity hedging.


-------------------------------------------------------------------------
Upstream Revenue Mix(1)
Three months Nine months
Percentage of upstream sales ended Sept. 30 ended Sept. 30
revenues, after royalties 2005 2004 2005 2004
-------------------------------------------------------------------------
Light crude oil & NGL 26% 27% 29% 27%
Medium crude oil 10% 11% 10% 11%
Heavy crude oil 30% 31% 26% 28%
Natural gas 34% 31% 35% 34%
-------------------------------------------------------------------------
100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Before commodity hedging


OPERATING NETBACKS

Western Canada
-------------------------------------------------------------------------
Light Crude Oil Netbacks(1) Three months Nine months
ended Sept. 30 ended Sept. 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 65.25 $ 47.60 $ 57.85 $ 44.51
Royalties 10.02 7.25 7.54 7.72
Operating costs 6.62 7.57 9.16 8.56
-------------------------------------------------------------------------
Netback $ 48.61 $ 32.78 $ 41.15 $ 28.23
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Medium Crude Oil Netbacks(1) Three months Nine months
ended Sept. 30 ended Sept. 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 53.13 $ 40.38 $ 43.32 $ 36.45
Royalties 9.69 7.21 7.68 6.37
Operating costs 11.44 10.85 10.68 10.05
-------------------------------------------------------------------------
Netback $ 32.00 $ 22.32 $ 24.96 $ 20.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Heavy Crude Oil Netbacks(1) Three months Nine months
ended Sept. 30 ended Sept. 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 44.19 $ 34.91 $ 31.57 $ 29.75
Royalties 6.25 4.25 3.83 3.40
Operating costs 9.88 9.90 9.53 9.51
-------------------------------------------------------------------------
Netback $ 28.06 $ 20.76 $ 18.21 $ 16.84
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Natural Gas Netbacks(2) Three months Nine months
ended Sept. 30 ended Sept. 30
Per mcfge 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 7.90 $ 6.00 $ 6.97 $ 6.12
Royalties 1.78 1.49 1.56 1.45
Operating costs 1.17 0.93 1.04 0.87
-------------------------------------------------------------------------
Netback $ 4.95 $ 3.58 $ 4.37 $ 3.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Total Western Canada Upstream Netbacks(1)

Three months Nine months
ended Sept. 30 ended Sept. 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 48.86 $ 37.42 $ 39.86 $ 35.00
Royalties 8.82 6.77 6.88 6.31
Operating costs 8.56 8.08 8.31 7.83
-------------------------------------------------------------------------
Netback $ 31.48 $ 22.57 $ 24.67 $ 20.86
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.
(2) Includes associated co-products converted to mcfge.


-------------------------------------------------------------------------
Terra Nova Crude Oil Netbacks
Three months Nine months
ended Sept. 30 ended Sept. 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 69.62 $ 51.49 $ 62.23 $ 46.96
Royalties 12.64 3.13 5.61 1.64
Operating costs 5.61 3.91 4.16 3.11
-------------------------------------------------------------------------
Netback $ 51.37 $ 44.45 $ 52.46 $ 42.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Wenchang Crude Oil Netbacks
Three months Nine months
ended Sept. 30 ended Sept. 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 67.98 $ 55.86 $ 64.04 $ 48.48
Royalties 6.53 5.84 6.00 4.95
Operating costs 2.56 2.00 2.43 2.06
-------------------------------------------------------------------------
Netback $ 58.89 $ 48.02 $ 55.61 $ 41.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Total Upstream Segment Netbacks(1)
Three months Nine months
ended Sept. 30 ended Sept. 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 50.49 $ 39.08 $ 42.07 $ 36.39
Royalties 8.83 6.59 6.78 6.01
Operating costs 8.18 7.57 7.84 7.26
-------------------------------------------------------------------------
Netback $ 33.48 $ 24.92 $ 27.45 $ 23.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.


MIDSTREAM

-------------------------------------------------------------------------
Upgrading Earnings Summary
Three months Nine months
(millions of dollars, except ended Sept. 30 ended Sept. 30
where indicated) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross margin $ 92 $ 93 $ 494 $ 261
Operating costs 48 55 151 160
Other recoveries (1) (2) (4) (4)
Depreciation and amortization 6 5 15 14
Income taxes 12 11 101 25
-------------------------------------------------------------------------
Earnings $ 27 $ 24 $ 231 $ 66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Upgrader throughput(1)
(mbbls/day) 48.3 71.6 63.8 66.2
Synthetic crude oil sales
(mbbls/day) 43.9 60.1 55.9 54.1
Upgrading differential
($/bbl) $ 23.53 $ 15.26 $ 29.73 $ 15.31
Unit margin ($/bbl) $ 23.01 $ 16.88 $ 32.41 $ 17.60
Unit operating cost(2)
($/bbl) $ 11.04 $ 8.30 $ 8.71 $ 8.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Throughput includes diluent returned to the field.
(2) Based on throughput.


-------------------------------------------------------------------------
Upgrading Earnings Variance Analysis

(millions of dollars)
-------------------------------------------------------------------------
Three months ended September 30, 2004 $ 24
Volume (25)
Margin 25
Operating costs - energy related 5
Operating costs - non-energy related 1
Other (1)
Depreciation and amortization (1)
Income taxes (1)
-------------------------------------------------------------------------
Three months ended September 30, 2005 $ 27
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended September 30, 2004 $ 66
Volume 7
Margin 226
Operating costs - non-energy related 9
Depreciation and amortization (1)
Income taxes (76)
-------------------------------------------------------------------------
Nine months ended September 30, 2005 $ 231
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Third Quarter

Upgrading earnings increased in the third quarter of 2005 by $3 million compared with the third quarter of 2004 due to:

- Wider upgrading differential

- Lower energy and non-energy related unit operating costs

Partially offset by:

- Lower sales volume of synthetic crude oil as a result of a scheduled

turnaround

Nine Months

With the exception of sales volume, slightly higher energy related operating costs and income taxes, the factors that affected upgrading performance in the first nine months of 2005 compared with the first nine months of 2004 were essentially the same as those during the third quarter of 2005 and 2004. Income taxes in the first nine months of 2005 compared with the same period in 2004 were higher due to higher income.




-------------------------------------------------------------------------
Infrastructure and Marketing Earnings Summary

Three months Nine months
(millions of dollars, except ended Sept. 30 ended Sept. 30
where indicated) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross margin
- pipeline $ 21 $ 23 $ 68 $ 65
- other infrastructure
and marketing 38 26 154 103
-------------------------------------------------------------------------
59 49 222 168
Other expenses 3 3 8 7
Depreciation and amortization 5 6 16 16
Income taxes 17 14 69 48
-------------------------------------------------------------------------
Earnings $ 34 $ 26 $ 129 $ 97
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Aggregate pipeline throughput
(mbbls/day) 418 461 472 496
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 




Third Quarter

Infrastructure and marketing earnings increased by $8 million in the third quarter of 2005 compared with the third quarter of 2004 due to:

- Higher income from oil and gas commodity marketing

Partially offset by:

- Lower pipeline throughput and margins

- Higher income taxes due to higher income

Nine Months

The factors that affected infrastructure and marketing earnings in the first nine months of 2005 compared with the first nine months of 2004 were essentially the same as those during the third quarter of 2005 and 2004.




REFINED PRODUCTS

-------------------------------------------------------------------------
Refined Products Earnings Summary
Three months Nine months
(millions of dollars, except ended Sept. 30 ended Sept. 30
where indicated) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross margin
- fuel sales $ 41 $ 26 $ 94 $ 86
- ancillary sales 10 8 26 22
- asphalt sales 24 20 71 41
-------------------------------------------------------------------------
75 54 191 149
Operating and other expenses 19 18 55 53
Depreciation and amortization 14 9 34 27
Income taxes 15 9 37 25
-------------------------------------------------------------------------
Earnings $ 27 $ 18 $ 65 $ 44
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Number of fuel outlets 519 533
Light oil sales
(million litres/day) 9.3 8.8 8.8 8.5
Light oil sales per outlet
(thousand litres/day) 13.3 11.9 12.7 11.5
Prince George refinery
throughput (mbbls/day) 9.6 9.2 9.7 10.2
Asphalt sales (mbbls/day) 29.9 27.6 22.5 23.4
Lloydminster refinery
throughput (mbbls/day) 25.9 23.8 24.9 25.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Third Quarter

Refined products earnings increased by $9 million in the third quarter of 2005 compared with the third quarter of 2004 due to:

- Higher marketing margins and sales volume for gasoline and distillates

- Higher marketing margins and sales volume of asphalt products

- Higher income from restaurant, convenience store and facilities rent

Partially offset by:

- Higher depreciation expense

- Higher income taxes

Nine Months

The factors that affected refined products earnings in the first nine months of 2005 compared with the first nine months of 2004 were essentially the same as those during the third quarter of 2005 and 2004.



CORPORATE

-------------------------------------------------------------------------
Corporate Summary(1)
Three months Nine months
ended Sept. 30 ended Sept. 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Intersegment eliminations -
net $ 44 $ (5) $ 53 $ 25
Administration expenses 4 6 15 16
Stock-based compensation 79 22 177 45
Accretion 1 1 2 2
Other - net (57) 1 (51) 5
Depreciation and amortization 6 8 17 26
Interest on debt 36 32 107 101
Interest capitalized (36) (19) (91) (54)
Foreign exchange (63) (84) (36) (60)
Income taxes (37) (30) (111) (79)
-------------------------------------------------------------------------
Earnings (loss) $ 23 $ 68 $ (82) $ (27)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2004 amounts as restated. Refer to Note 3 to the Consolidated
Financial Statements.


-------------------------------------------------------------------------
Foreign Exchange Summary
Three months Nine months
ended Sept. 30 ended Sept. 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gain on translation of
U.S. dollar denominated
long-term debt
Realized $ (5) $ (3) $ (9) $ (5)
Unrealized (84) (106) (49) (58)
-------------------------------------------------------------------------
(89) (109) (58) (63)
Cross currency swaps 22 22 16 8
Other (gains) losses 4 3 6 (5)
-------------------------------------------------------------------------
$ (63) $ (84) $ (36) $ (60)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
U.S./Canadian dollar
exchange rates:
At beginning of period U.S. U.S. U.S. U.S.
$ 0.816 $ 0.746 $ 0.831 $ 0.774
U.S. U.S. U.S. U.S.
At end of period $ 0.861 $ 0.791 $ 0.861 $ 0.791
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 




Third Quarter

Corporate earnings decreased by $45 million in the third quarter of 2005 compared with the third quarter of 2004 due to:

- Higher stock-based compensation expense during the third quarter of

2005

- Higher interest costs

- Higher intersegment profit elimination

- Lower gains on translation of U.S. denominated debt

Partially offset by:

- Gain on settlement of litigation

- Lower depreciation and amortization

- Higher capitalized interest resulting from the higher White Rose and

Tucker project capital base

- Higher income tax recovery

Nine Months

The factors that affected corporate expense in the first nine months of 2005 compared with the first nine months of 2004 were essentially the same as those during the third quarter of 2005 and 2004.

LIQUIDITY AND CAPITAL RESOURCES

OPERATING ACTIVITIES

In the third quarter of 2005, cash generated from operating activities amounted to $1.1 billion compared with $577 million in the third quarter of 2004. Higher cash flow from operating activities was primarily due to higher commodity prices and higher change in non-cash working capital.

FINANCING ACTIVITIES

In the third quarter of 2005, cash used in financing activities amounted to $290 million compared with $25 million in the third quarter of 2004. During the third quarter of 2005, higher short and long-term debt repayments and dividends net of long-term debt issue resulted in higher use of cash compared with the third quarter of 2004.

INVESTING ACTIVITIES

In the third quarter of 2005, cash used in investing activities amounted to $776 million compared with $625 million in the third quarter of 2004. Cash was used primarily for capital expenditures partially offset by proceeds from asset sales.




Capital Expenditures

-------------------------------------------------------------------------
Capital Expenditures Summary(1)
Three months Nine months
ended Sept. 30 ended Sept. 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Upstream
Exploration
Western Canada $ 189 $ 41 $ 503 $ 245
East Coast Canada and
Frontier 28 3 46 17
International 16 5 39 16
-------------------------------------------------------------------------
233 49 588 278
-------------------------------------------------------------------------
Development
Western Canada 262 310 856 855
East Coast Canada 202 149 448 355
International 4 1 7 5
-------------------------------------------------------------------------
468 460 1,311 1,215
-------------------------------------------------------------------------
701 509 1,899 1,493
-------------------------------------------------------------------------
Midstream
Upgrader 38 12 85 38
Infrastructure and Marketing 11 5 24 12
-------------------------------------------------------------------------
49 17 109 50
-------------------------------------------------------------------------
Refined Products 57 29 105 53
Corporate 6 8 14 19
-------------------------------------------------------------------------
Capital expenditures 813 563 2,127 1,615
Settlement of asset
retirement obligations (8) (7) (18) (18)
-------------------------------------------------------------------------
Capital expenditures per
Consolidated Statements
of Cash Flows $ 805 $ 556 $ 2,109 $ 1,597
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period and corporate acquisitions.

Upstream capital expenditures totaled $1,899 million, 89 percent of total
consolidated capital expenditures during the first nine months of 2005
compared with $1,493 million or 92 percent of the total, during the first nine
months of 2004.

-------------------------------------------------------------------------
Upstream Capital Expenditures Nine months ended
Sept. 30
(millions of dollars) 2005
-------------------------------------------------------------------------
Western Canada Sedimentary Basin sustaining exploitation $ 940
Western Canada foothills and deep basin exploration 160
Western Canada oil sands 259
Eastern Canada offshore and Northwest Territories 494
International exploration and development 46
-------------------------------------------------------------------------
$ 1,899
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The remaining capital expenditures during the first nine months of 2005
amounting to $228 million were related primarily to the Lloydminster upgrader
debottlenecking project, the Prince George refinery clean fuels project and
the Lloydminster ethanol plant project.

-------------------------------------------------------------------------
Western Canada Wells Drilled(1)(2)

Three months Nine months
ended Sept. 30 ended Sept. 30
2005 2004 2005 2004
Gross Net Gross Net Gross Net Gross Net
-------------------------------------------------------------------------
Exploration Oil 28 28 6 4 63 60 19 16
Gas 107 43 29 23 239 136 153 134
Dry 7 7 1 1 26 26 30 30
-------------------------------------------------------------------------
142 78 36 28 328 222 202 180
-------------------------------------------------------------------------
Development Oil 154 147 200 188 285 266 396 368
Gas 164 136 221 204 442 401 632 592
Dry 10 8 14 14 25 23 51 48
-------------------------------------------------------------------------
328 291 435 406 752 690 1,079 1,008
-------------------------------------------------------------------------
Total 470 369 471 434 1,080 912 1,281 1,188
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes stratigraphic test wells.
(2) Includes non-operated wells.

 




SOURCES OF CAPITAL

Liquidity describes a company's ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and proved developed reserves, to acquire strategic oil and gas assets, repay maturing debt and pay dividends. Husky's upstream capital programs are funded principally by cash provided from operating activities. During times of low oil and gas prices part of a capital program can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining our production, it may be necessary to utilize alternative sources of capital to continue our strategic investment plan during periods of low commodity prices. As a result we continually examine our options with respect to sources of long and short-term capital resources. In addition, from time to time we engage in hedging a portion of our production to protect cash flow.




-------------------------------------------------------------------------
Sources and Uses of Cash
Nine months Year ended
ended Sept. 30 December 31
(millions of dollars) 2005 2004
-------------------------------------------------------------------------
Cash sourced
Cash flow from operations(1) $ 2,588 $ 2,197
Debt issue 3,027 2,200
Asset sales 70 36
Proceeds from exercise of stock options 5 18
Proceeds from monetization of financial
instruments 30 8
-------------------------------------------------------------------------
5,720 4,459
-------------------------------------------------------------------------
Cash used
Capital expenditures 2,109 2,349
Corporate acquisitions - 102
Debt repayment 3,224 1,959
Special dividend on common shares - 229
Ordinary dividends on common shares 170 195
Settlement of asset retirement obligations 24 40
Other 23 24
-------------------------------------------------------------------------
5,550 4,898
-------------------------------------------------------------------------
Net cash (deficiency) 170 (439)
Increase (decrease) in non-cash working capital (135) 443
-------------------------------------------------------------------------
Increase in cash and cash equivalents 35 4
Cash and cash equivalents - beginning of period 7 3
-------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 42 $ 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Increase (decrease) in non-cash working capital
Cash positive working capital change
Accounts receivable decrease $ - $ 209
Accounts payable and accrued liabilities
increase 157 323
-------------------------------------------------------------------------
157 532
Cash negative working capital change
Accounts receivable increase 113 -
Inventory increase 176 77
Prepaid expense increase 3 12
-------------------------------------------------------------------------
292 89
-------------------------------------------------------------------------
Increase (decrease) in non-cash working capital $ (135) $ 443
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash flow from operations represents net earnings plus items not
affecting cash, which include accretion, depletion, depreciation
and amortization, future income taxes and foreign exchange.

 


Working capital is the amount by which current assets exceed current liabilities. At September 30, 2005, our working capital deficiency was $539 million compared with $824 million at December 31, 2004. These working capital deficits are primarily the result of accounts payable related to capital expenditures for exploration and development. Settlement of these current liabilities is funded by cash provided by operating activities and to the extent necessary by bank borrowings. This position is a common characteristic of the oil and gas industry which, by the nature of its business, spends large amounts of capital.




-------------------------------------------------------------------------
Capital Structure
September 30, 2005
Outstanding Available
(millions of dollars) (U.S. $) (Cdn $) (Cdn $)
-------------------------------------------------------------------------
Short-term bank debt $ - $ - $ 177
Long-term bank debt
Syndicated credit facility - - 1,000
Bilateral credit facilities - - 150
Medium-term notes - 300
Capital securities 225 261
U.S. public notes 1,050 1,219
U.S. senior secured bonds 85 99
U.S. private placement notes 15 17
-------------------------------------------------------------------------
Total short-term and long-term debt $ 1,375 $ 1,896 $ 1,327
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares and retained earnings $ 7,380
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Financial Ratios
Three months Nine months
(millions of dollars, ended Sept. 30 ended Sept. 30
except ratios) 2005 2004 2005 2004
-------------------------------------------------------------------------
Cash flow
- operating activities $ 1,105 $ 577 $ 2,605 $ 1,742
- financing activities $ (290) $ (25) $ (543) $ 26
- investing activities $ (776) $ (625) $ (2,027) $ (1,769)
Debt to capital employed
(percent) 20.4 25.5
Corporate reinvestment
ratio(1)(2) 0.9 1.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Calculated for the twelve months ended for the periods shown.
(2) Reinvestment ratio is based on net capital expenditures including
corporate acquisitions.


CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

-------------------------------------------------------------------------
Contractual Obligations
October-
Payments due by period December 2006- 2008- There-
(millions of dollars) Total 2005 2007 2009 after
-------------------------------------------------------------------------
Long-term debt $ 1,896 $ 17 $ 326 $ 494 $ 1,059
Operating leases 537 15 176 161 185
Firm transportation
agreements 901 53 375 262 211
Unconditional purchase
obligations 1,502 150 1,186 151 15
Lease rentals 330 11 88 88 143
Exploration work agreements 42 18 15 - 9
Engineering and construction
commitments 705 311 382 12 -
-------------------------------------------------------------------------
$ 5,913 $ 575 $ 2,548 $ 1,168 $ 1,622
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


OFF BALANCE SHEET ARRANGEMENTS

We do not utilize off balance sheet arrangements with unconsolidated entities to enhance perceived liquidity.

We engage in the ordinary course of business in the securitization of accounts receivable. Our receivable securitization program is fully utilized at $350 million. The securitization agreement terminates on January 31, 2009. The accounts receivable are sold to an unrelated third party on a revolving basis. In accordance with the agreement we must provide a loss reserve to replace defaulted receivables.

The securitization program provides us with cost effective short-term funding for general corporate use. We account for these securitizations as asset sales. In the event the program is terminated our liquidity would not be materially reduced.

TRANSACTIONS WITH RELATED PARTIES

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

SIGNIFICANT CUSTOMERS

We did not have any customers that constituted more than 10 percent of total sales and operating revenues during the first nine months of 2005.

FINANCIAL AND DERIVATIVE INSTRUMENTS




POWER CONSUMPTION

At September 30, 2005, we had hedged power consumption as follows:

-------------------------------------------------------------------------
(millions of Notional
dollars, except Volumes Unrecognized
where indicated) (MW) Term Price Gain (Loss)
-------------------------------------------------------------------------
Fixed price purchase 10.0 Oct. to Dec. 2005 $ 49.25/MWh $ 1
12.5 Oct. to Dec. 2005 $ 50.50/MWh 1
-------------------------------------------------------------------------
$ 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


FOREIGN CURRENCY RISK MANAGEMENT

At September 30, 2005, we had the following cross currency debt swaps in place:

- U.S. $150 million at 7.125 percent swapped at $1.45 to $218 million at

8.74 percent until November 15, 2006

- U.S. $150 million at 6.250 percent swapped at $1.41 to $212 million at

7.41 percent until June 15, 2012

- U.S. $75 million at 6.250 percent swapped at $1.19 to $90 million at

5.65 percent until June 15, 2012

- U.S. $50 million at 6.250 percent swapped at $1.17 to $59 million at

5.67 percent until June 15, 2012

At September 30, 2005 the cost of a U.S. dollar in Canadian currency was $1.1611.

In the first nine months of 2005, the cross currency swaps resulted in an offset to foreign exchange gains on translation of U.S. dollar denominated debt amounting to $16 million.

In addition, we entered into U.S. dollar forward contracts, which resulted in realized gains of $12 million in the first nine months of 2005.

Husky entered into long-dated forwards that fixed the exchange rate on U.S. dollar sales. These contracts were unwound in 2004 and during the first nine months of 2005, we recognized a gain of $8 million.

INTEREST RATE RISK MANAGEMENT

In the first nine months of 2005, the interest rate risk management activities resulted in a decrease to interest expense of $11 million.

The cross currency swaps resulted in an addition to interest expense of $7 million in the first nine months of 2005.

Husky has interest rate swaps on $200 million of long-term debt effective February 8, 2002 whereby 6.95 percent was swapped for CDOR + 175 bps until July 14, 2009. During the first nine months of 2005, these swaps resulted in an offset to interest expense amounting to $4 million.

Husky has interest rate swaps 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 the first nine months of 2005, these swaps resulted in an offset to interest expense amounting to $5 million.

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

The amortization of previous interest rate swap terminations resulted in an additional $6 million offset to interest expense in the first nine months of 2005.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain of our accounting policies require that we make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. For a discussion about those accounting policies, please refer to our Management's Discussion and Analysis for the year ended December 31, 2004 available at www.sedar.com.

NEW ACCOUNTING STANDARDS

Effective January 1, 2005, we retroactively reclassified the capital securities from equity to long-term debt in accordance with the Canadian Institute of Chartered Accountants handbook section 3860, "Financial Instruments - Disclosure and Presentation." As a result the return on capital securities is included in interest expense rather than as a charge to retained earnings.




OUTSTANDING SHARE DATA

-------------------------------------------------------------------------
Nine months Year ended
ended Sept. 30 December 31
(in thousands, except per share amounts) 2005 2004
-------------------------------------------------------------------------
Share price(1) High $ 69.95 $ 35.65
Low $ 32.30 $ 22.73
Close at end of period $ 64.57 $ 34.25
Average daily trading volume 677 482
Weighted average number of common shares
outstanding
Basic 423,912 423,362
Diluted 423,912 424,303
Issued and outstanding at end of period(2)
Number of common shares 424,112 423,736
Number of stock options 7,341 9,964
Number of stock options exercisable 1,557 1,417
Number of warrants - 25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Trading in the common shares of Husky Energy Inc. ("HSE") commenced
on the Toronto Stock Exchange on August 28, 2000. The Company is
represented in the S&P/TSX Composite, S&P/TSX Canadian Energy Sector
and in the S&P/TSX 60 indices.
(2) There were no significant issuances of common shares, stock options
or any other securities convertible into, or exercisable or
exchangeable for common shares during the period from September 30,
2005 to October 14, 2005.


 


ADDITIONAL INFORMATION

Management's Discussion and Analysis is our explanation of our financial performance for the period covered by the unaudited financial statements along with an analysis of our financial position and prospects. It should be read in conjunction with the unaudited Consolidated Financial Statements for the nine months ended September 30, 2005 in this Quarterly Report and the audited Consolidated Financial Statements, Management's Discussion and Analysis and Annual Information Form for the year ended December 31, 2004 filed March 18, 2005 on SEDAR at www.sedar.com. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada. All comparisons refer to the third quarter of 2005 compared with the third quarter of 2004 and the first nine months of 2005 compared with the first nine months of 2004, unless otherwise indicated. All dollar amounts are in millions of Canadian dollars, unless otherwise indicated. Unless otherwise indicated, all production volumes quoted are gross, which represent our working interest share before royalties. Prices quoted include or exclude the effect of hedging as indicated. Crude oil has been classified as the following: light crude oil has an API gravity of 30 degrees or more; medium crude oil has an API gravity of 21 degrees or more and less than 30 degrees; heavy crude oil has an API gravity of less than 21 degrees.

NON-GAAP MEASURES

Disclosure of Cash Flow from Operations

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 our financial performance. Our 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 items reported under the caption, "Corporate and eliminations", are required to reconcile to the consolidated total and are not considered to be attributable to a business segment.



The following table shows the reconciliation of cash flow from operations
to cash flow - operating activities for the periods noted:

-------------------------------------------------------------------------
Nine months Year ended
ended Sept. 30 December 31
(millions of dollars) 2005 2004
-------------------------------------------------------------------------
Non-GAAP Cash flow from operations $ 2,588 $ 2,197
Settlement of asset retirement
obligations (24) (40)
Change in non-cash working capital 41 169
-------------------------------------------------------------------------
GAAP Cash flow - operating activities $ 2,605 $ 2,326
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Our disclosure of reserves data and other oil and gas information has been made in reliance on an exemption to us by the Canadian Securities Administrators. The exemption permits us to make our disclosures in accordance with U.S. disclosure requirements and practices in order to provide comparability with U.S. and other international issuers. These requirements may differ from Canadian requirements under National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities." Our proved reserves disclosure has been evaluated in accordance with the standards contained in Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934.

We use the terms barrels of oil equivalent ("boe") and thousand cubic feet of gas equivalent ("mcfge"), which are calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the terms boe and mcfge may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the well head.

FORWARD-LOOKING STATEMENTS

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

- Fluctuations in commodity prices

- The accuracy of our oil and gas reserve estimates and estimated

production levels as they are affected by our success at exploration

and development drilling and related activities and estimated decline

rates

- The uncertainties resulting from potential delays or changes in plans

with respect to exploration or development projects or capital

expenditures

- Changes in general economic, market and business conditions

- Fluctuations in supply and demand for our products

- Fluctuations in the cost of borrowing

- Our use of derivative financial instruments to hedge exposure to

changes in commodity prices and fluctuations in interest rates and

foreign currency exchange rates

- Political and economic developments, expropriations, royalty and tax

increases, retroactive tax claims and changes to import and export

regulations and other foreign laws and policies in the countries in

which we operate

- Our ability to receive timely regulatory approvals

- The integrity and reliability of our capital assets

- The cumulative impact of other resource development projects

- The maintenance of satisfactory relationships with unions, employee

associations and joint venturers

- Competitive actions of other companies, including increased

competition from other oil and gas companies or from companies that

provide alternate sources of energy

- Actions by governmental authorities, including changes in

environmental and other regulations that may impose restriction in

areas where we operate

- The ability and willingness of parties with whom we have material

relationships to fulfill their obligations

- The occurrence of unexpected events such as fires, blowouts,

freeze-ups, equipment failures and other similar events affecting us

or other parties, whose operations or assets directly or indirectly

affect us





CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets
-------------------------------------------------------------------------
September 30 December 31
(millions of dollars) 2005 2004
-------------------------------------------------------------------------
(unaudited) (audited)
Assets
Current assets
Cash and cash equivalents $ 42 $ 7
Accounts receivable 559 446
Inventories 450 274
Prepaid expenses 61 52
-------------------------------------------------------------------------
1,112 779

Property, plant and equipment
- (full cost accounting) 21,414 19,451
Less accumulated depletion, depreciation
and amortization 8,114 7,258
-------------------------------------------------------------------------
13,300 12,193
Goodwill 160 160
Other assets 140 108
-------------------------------------------------------------------------
$ 14,712 $ 13,240
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Bank operating loans $ - $ 49
Accounts payable and accrued liabilities 1,605 1,498
Long-term debt due within one year (note 5) 46 56
-------------------------------------------------------------------------
1,651 1,603
Long-term debt (notes 3, 5) 1,850 2,047
Other long-term liabilities (note 4) 730 632
Future income taxes 3,101 2,758
Commitments and contingencies (note 6)
Shareholders' equity
Common shares (note 7) 3,522 3,506
Retained earnings 3,858 2,694
-------------------------------------------------------------------------
7,380 6,200
-------------------------------------------------------------------------
$ 14,712 $ 13,240
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares outstanding (millions) (note 7) 424.1 423.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements. 2004 amounts as restated.



Consolidated Statements of Earnings
-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30
(millions of dollars, except
per share amounts) (unaudited) 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales and operating revenues,
net of royalties $ 2,763 $ 2,191 $ 7,457 $ 6,422
Costs and expenses
Cost of sales and operating
expenses 1,701 1,472 4,433 4,326
Selling and administration
expenses 40 37 109 99
Stock-based compensation 79 22 177 45
Depletion, depreciation and
amortization 311 306 913 877
Interest - net (notes 3, 5) - 13 16 47
Foreign exchange (notes 3, 5) (63) (84) (36) (60)
Other - net (57) 1 (52) 5
-------------------------------------------------------------------------
2,011 1,767 5,560 5,339
-------------------------------------------------------------------------
Earnings before income taxes 752 424 1,897 1,083
-------------------------------------------------------------------------
Income taxes
Current 78 81 220 200
Future 118 46 343 102
-------------------------------------------------------------------------
196 127 563 302
-------------------------------------------------------------------------
Net earnings $ 556 $ 297 $ 1,334 $ 781
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per share (note 8)
Basic $ 1.31 $ 0.70 $ 3.15 $ 1.84
Diluted $ 1.31 $ 0.70 $ 3.15 $ 1.84
Weighted average number of
common shares outstanding
(millions) (note 8)
Basic 424.0 423.6 423.9 423.2
Diluted 424.0 423.6 423.9 424.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Consolidated Statements of Retained Earnings
-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30

(millions of dollars) (unaudited) 2005 2004 2005 2004
-------------------------------------------------------------------------
Beginning of period $ 3,362 $ 2,503 $ 2,694 $ 2,156
Net earnings 556 297 1,334 781
Dividends on common shares (60) (51) (170) (144)
Stock-based compensation
- retroactive adoption - - - (44)
-------------------------------------------------------------------------
End of period $ 3,858 $ 2,749 $ 3,858 $ 2,749
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements. 2004 amounts as restated.



Consolidated Statements of Cash Flows
-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30

(millions of dollars) (unaudited) 2005 2004 2005 2004
-------------------------------------------------------------------------
Operating activities
Net earnings $ 556 $ 297 $ 1,334 $ 781
Items not affecting cash
Accretion (note 4) 8 7 25 21
Depletion, depreciation
and amortization 311 306 913 877
Future income taxes 118 46 343 102
Foreign exchange (66) (87) (42) (55)
Other 17 2 15 2
Settlement of asset retirement
obligations (10) (11) (24) (24)
Change in non-cash working
capital (note 9) 171 17 41 38
-------------------------------------------------------------------------
Cash flow - operating
activities 1,105 577 2,605 1,742
-------------------------------------------------------------------------
Financing activities
Bank operating loans
financing - net (34) 47 (49) (24)
Long-term debt issue 576 205 3,027 1,666
Long-term debt repayment (782) (228) (3,175) (1,495)
Debt issue costs - - - (5)
Proceeds from exercise of
stock options 1 1 5 17
Proceeds from monetization of
financial instruments - - 30 -
Dividends on common shares (60) (51) (170) (144)
Change in non-cash working
capital (note 9) 9 1 (211) 11
-------------------------------------------------------------------------
Cash flow - financing
activities (290) (25) (543) 26
-------------------------------------------------------------------------
Available for investing 815 552 2,062 1,768
-------------------------------------------------------------------------
Investing activities
Capital expenditures (805) (556) (2,109) (1,597)
Corporate acquisitions - (102) - (102)
Asset sales 13 20 70 34
Other (21) 2 (23) (10)
Change in non-cash working
capital (note 9) 37 11 35 (94)
-------------------------------------------------------------------------
Cash flow - investing
activities (776) (625) (2,027) (1,769)
-------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 39 (73) 35 (1)
Cash and cash equivalents at
beginning of period 3 75 7 3
-------------------------------------------------------------------------
Cash and cash equivalents at
end of period $ 42 $ 2 $ 42 $ 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements. 2004 amounts as restated.



Notes to the Consolidated Financial Statements

Nine months ended September 30, 2005 (unaudited)
Except where indicated and per share amounts,
all dollar amounts are in millions.

Note 1 Segmented Financial Information

-------------------------------------------------------------------------

Upstream Midstream
Infrastructure
Upgrading and Marketing
2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------
Three months ended
September 30(1)
Sales and operating
revenues, net of
royalties $ 1,176 $ 817 $ 328 $ 308 $ 1,721 $ 1,564
Costs and expenses
Operating, cost
of sales, selling
and general 262 255 283 268 1,665 1,518
Depletion,
depreciation and
amortization 280 278 6 5 5 6
Interest - net - - - - - -
Foreign exchange - - - - - -
-------------------------------------------------------------------------
542 533 289 273 1,670 1,524
-------------------------------------------------------------------------

Earnings (loss)
before income
taxes 634 284 39 35 51 40
Current income
taxes 47 59 4 - (3) 5
Future income
taxes 142 64 8 11 20 9
-------------------------------------------------------------------------
Net earnings $ 445 $ 161 $ 27 $ 24 $ 34 $ 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital expenditures -
Three months ended
September 30 $ 701 $ 509 $ 38 $ 12 $ 11 $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended
September 30(1)
Sales and operating
revenues, net of
royalties $ 3,040 $ 2,398 $ 1,074 $ 767 $ 4,673 $ 4,671
Costs and expenses
Operating, cost of
sales, selling and
general 751 720 727 662 4,459 4,510
Depletion,
depreciation and
amortization 831 794 15 14 16 16
Interest - net - - - - - -
Foreign exchange - - - - - -
-------------------------------------------------------------------------
1,582 1,514 742 676 4,475 4,526
-------------------------------------------------------------------------

Earnings (loss) before
income taxes 1,458 884 332 91 198 145
Current income
taxes 169 122 13 - (14) 31
Future income
taxes 298 161 88 25 83 17
-------------------------------------------------------------------------
Net earnings (loss) $ 991 $ 601 $ 231 $ 66 $ 129 $ 97
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital employed -
As at
September 30 $ 8,005 $ 7,409 $ 489 $ 487 $ 670 $ 390
Capital
expenditures -
Nine months ended
September 30 $ 1,899 $ 1,493 $ 85 $ 38 $ 24 $ 12
Total assets - As
at September 30 $11,920 $10,718 $ 806 $ 698 $ 1,042 $ 718
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Corporate and
Refined Products Eliminations(2) Total

2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------
Three months ended
September 30(1)
Sales and operating
revenues, net of
royalties $ 716 $ 515 $(1,178) $(1,013) $ 2,763 $ 2,191
Costs and expenses
Operating, cost
of sales, selling
and general 660 479 (1,107) (988) 1,763 1,532
Depletion,
depreciation and
amortization 14 9 6 8 311 306
Interest - net - - - 13 - 13
Foreign exchange - - (63) (84) (63) (84)
-------------------------------------------------------------------------
674 488 (1,164) (1,051) 2,011 1,767
-------------------------------------------------------------------------

Earnings (loss)
before income taxes 42 27 (14) 38 752 424
Current income taxes (1) 4 31 13 78 81
Future income taxes 16 5 (68) (43) 118 46
-------------------------------------------------------------------------
Net earnings $ 27 $ 18 $ 23 $ 68 $ 556 $ 297
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital expenditures -
Three months ended
September 30 $ 57 $ 29 $ 6 $ 8 $ 813 $ 563
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended
September 30(1)
Sales and operating
revenues, net of
royalties $ 1,713 $ 1,332 $(3,043) $(2,746) $ 7,457 $ 6,422
Costs and expenses
Operating, cost of
sales, selling and
general 1,577 1,236 (2,847) (2,653) 4,667 4,475
Depletion,
depreciation and
amortization 34 27 17 26 913 877
Interest - net - - 16 47 16 47
Foreign exchange - - (36) (60) (36) (60)
-------------------------------------------------------------------------
1,611 1,263 (2,850) (2,640) 5,560 5,339
-------------------------------------------------------------------------

Earnings (loss) before
income taxes 102 69 (193) (106) 1,897 1,083
Current income taxes (3) 11 55 36 220 200
Future income taxes 40 14 (166) (115) 343 102
-------------------------------------------------------------------------
Net earnings (loss) $ 65 $ 44 $ (82) $ (27) $ 1,334 $ 781
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Capital employed -
As at
September 30 $ 402 $ 372 $ (290) $ (262) $ 9,276 $ 8,396
Capital
expenditures -
Nine months ended
September 30 $ 105 $ 53 $ 14 $ 19 $ 2,127 $ 1,615
Total assets - As
at September 30 $ 783 $ 647 $ 161 $ 120 $14,712 $12,901
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2004 amounts as restated. Refer to Note 5.
(2) Eliminations relate to sales and operating revenues between segments
recorded at transfer prices based on current market prices, and to
unrealized intersegment profits in inventories.


 


Note 2 Significant Accounting Policies

The interim consolidated financial statements of Husky Energy Inc.

("Husky" or "the Company") have been prepared by management in accordance

with accounting principles generally accepted in Canada. The interim

consolidated financial statements have been prepared following the same

accounting policies and methods of computation as the consolidated

financial statements for the fiscal year ended December 31, 2004, except

as noted below. The interim consolidated financial statements should be

read in conjunction with the consolidated financial statements and the

notes thereto in the Company's annual report for the year ended

December 31, 2004. Certain prior years' amounts have been reclassified to

conform with current presentation.

Note 3 Change in Accounting Policies

Financial Instruments

Effective January 1, 2005, the Company retroactively adopted the revised

recommendations of the Canadian Institute of Chartered Accountants

("CICA") section 3860, "Financial Instruments - Disclosure and

Presentation", on the classification of obligations that must or could be

settled with an entity's own equity instruments. The new recommendations

resulted in the Company's capital securities being classified as

liabilities instead of equity. The accrued return on the capital

securities and the issue costs are classified outside of shareholders'

equity. The return on the capital securities is a charge to earnings.

Note 5 discloses the impact of the adoption of the revised

recommendations of CICA section 3860 on the consolidated financial

statements.

Note 4 Other Long-term Liabilities

Asset Retirement Obligations




Changes to asset retirement obligations were as follows:

-------------------------------------------------------------------------
Nine months
ended Sept. 30
2005 2004
-------------------------------------------------------------------------
Asset retirement obligations at beginning of
period $ 509 $ 432
Liabilities incurred 13 16
Liabilities disposed (7) -
Liabilities settled (24) (24)
Accretion 25 21
-------------------------------------------------------------------------
Asset retirement obligations at end of
period $ 516 $ 445
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


At September 30, 2005, the estimated total undiscounted inflation

adjusted amount required to settle the asset retirement obligations was

$3.0 billion. These obligations will be settled based on the useful

lives of the underlying assets, which currently extend up to 50 years

into the future. This amount has been discounted using credit adjusted

risk free rates ranging from 6.2 to 6.4 percent.




Note 5 Long-term Debt

-------------------------------------------------------------------------
Sept. 30 Dec. 31 Sept. 30 Dec. 31
Maturity 2005 2004 2005 2004
-------------------------------------------------------------------------
Cdn $ Amount U.S. $ Amount
Long-term debt
Syndicated credit
facility $ - $ 70 $ - $ -
Bilateral credit
facilities - 40 - -
7.125% notes 2006 174 181 150 150
8.90% capital
securities 2008 261 271 225 225
6.25% notes 2012 465 481 400 400
7.55% debentures 2016 232 241 200 200
6.15% notes 2019 348 361 300 300
Private placement notes 2005 17 18 15 15
8.45% senior secured
bonds 2006-12 99 140 85 117
Medium-term notes 2007-9 300 300 - -
-------------------------------------------------------------------------
Total long-term debt 1,896 2,103 $1,375 $1,407
--------------------
--------------------
Amount due within one year (46) (56)
-----------------------------------------------------
$1,850 $2,047
-----------------------------------------------------
-----------------------------------------------------

Interest - net consisted of:

-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Long-term debt $ 35 $ 32 $ 105 $ 100
Short-term debt 1 - 3 2
-------------------------------------------------------------------------
36 32 108 102
Amount capitalized (36) (19) (91) (54)
-------------------------------------------------------------------------
- 13 17 48
Interest income - - (1) (1)
-------------------------------------------------------------------------
$ - $ 13 $ 16 $ 47
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Foreign exchange consisted of:

-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Gain on translation of U.S. dollar
denominated long-term debt $ (89) $ (109) $ (58) $ (63)
Cross currency swaps 22 22 16 8
Other (gains) losses 4 3 6 (5)
-------------------------------------------------------------------------
$ (63) $ (84) $ (36) $ (60)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Credit Facilities

In March 2005, Husky increased its revolving syndicated credit facility

from $950 million to $1 billion.

Capital Securities

The Company retroactively adopted CICA recommendations resulting in the

Company's capital securities being classified as liabilities instead of

equity. The revision was effective January 1, 2005 and resulted in the

following changes to the Company's consolidated financial statements:




-------------------------------------------------------------------------
Consolidated Balance Sheet
- As at December 31, 2004
As As
Reported Change Restated
-------------------------------------------------------------------------
Assets
Other assets $ 106 $ 2 $ 108
Liabilities and Shareholders' Equity
Accounts payable and accrued
liabilities 1,489 9 1,498
Long-term debt 1,776 271 2,047
Capital securities and accrued return 278 (278) -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Consolidated Statement of Earnings
- Nine months ended September 30, 2004

As As
Reported Change Restated
-------------------------------------------------------------------------
Interest - net $ 27 $ 20 $ 47
Foreign exchange (53) (7) (60)
Future income taxes 108 (6) 102
Net earnings 788 (7) 781
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 




Note 6 Commitments and Contingencies

The Company is involved in various claims and litigation arising in the

normal course of business. While the outcome of these matters is

uncertain and there can be no assurance that such matters will be

resolved in the Company's favour, the Company does not currently believe

that the outcome of adverse decisions in any pending or threatened

proceedings related to these and other matters or any amount which it may

be required to pay by reason thereof would have a material adverse impact

on its financial position, results of operations or liquidity. In the

third quarter of 2005, a lawsuit was settled with proceeds received and

the resulting gain was recognized in earnings and recorded in other -

net.

Note 7 Share Capital

The Company's authorized share capital consists of an unlimited number of

no par value common and preferred shares.

Common Shares



Changes to issued common shares were as follows:

-------------------------------------------------------------------------
Nine months ended September 30
2005 2004
-------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
-------------------------------------------------------------------------
Balance at beginning of
period 423,736,414 $ 3,506 422,175,742 $ 3,457
Stock-based compensation -
adoption - - - 23
Exercised - options and
warrants 375,136 16 1,497,522 24
-------------------------------------------------------------------------
Balance at September 30 424,111,550 $ 3,522 423,673,264 $ 3,504
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Stock Options

A summary of the status of the Company's stock option plan is presented
below:

-------------------------------------------------------------------------
Nine months ended September 30
2005 2004
-------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
(thousands) Prices (thousands) Prices
-------------------------------------------------------------------------
Outstanding, beginning
of period 9,964 $ 22.61 4,597 $ 13.88
Granted 405 $ 43.19 7,988 $ 24.90
Exercised for common shares (346) $ 15.62 (1,287) $ 13.09
Surrendered for cash (2,241) $ 18.53 (880) $ 13.24
Forfeited (441) $ 24.01 (167) $ 22.16
-------------------------------------------------------------------------
Outstanding, September 30 7,341 $ 25.23 10,251 $ 22.48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable at
September 30 1,557 $ 23.47 1,712 $ 13.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
September 30, 2005
Outstanding Options Options Exercisable
-------------------------------------------------------------------------
Weighted
Weighted Average Number Weighted
Number of Average Contractual of Average
Range of Options Exercise Life Options Exercise
Exercise Price (thousands) Prices (years) (thousands) Prices
-------------------------------------------------------------------------
$14.22 - $14.99 132 $ 14.50 2 79 $ 14.49
$15.00 - $23.99 326 $ 18.75 3 89 $ 17.05
$24.00 - $24.99 6,202 $ 24.38 4 1,383 $ 24.38
$25.00 - $39.99 451 $ 32.57 4 6 $ 27.21
$40.00 - $49.18 230 $ 49.18 5 - $ -
-------------------------------------------------------------------------
7,341 $ 25.23 4 1,557 $ 23.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Note 8 Earnings per Common Share

-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Net earnings and net earnings
available to common shareholders $ 556 $ 297 $ 1,334 $ 781
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average number of common
shares outstanding
Basic (millions) 424.0 423.6 423.9 423.2
Effect of dilutive stock options
and warrants - - - 1.3
-------------------------------------------------------------------------
Weighted average number of
common shares outstanding
Diluted (millions) 424.0 423.6 423.9 424.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per share
Basic $ 1.31 $ 0.70 $ 3.15 $ 1.84
Diluted $ 1.31 $ 0.70 $ 3.15 $ 1.84
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Note 9 Cash Flows - Change in Non-cash Working Capital

-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30

2005 2004 2005 2004
-------------------------------------------------------------------------
a) Change in non-cash working
capital was as follows:
Decrease (increase) in non-cash
working capital
Accounts receivable $ (93) $ (16) $ (113) $ 33
Inventories (36) (17) (176) (89)
Prepaid expenses 15 4 (3) (12)
Accounts payable and
accrued liabilities 331 58 157 23
-------------------------------------------------------------------------
Change in non-cash working capital 217 29 (135) (45)
Relating to:
Financing activities 9 1 (211) 11
Investing activities 37 11 35 (94)
-------------------------------------------------------------------------
Operating activities $ 171 $ 17 $ 41 $ 38
-------------------------------------------------------------------------
-------------------------------------------------------------------------
b) Other cash flow information:
Cash taxes paid (received) $ (14) $ 35 $ 145 $ 187
Cash interest paid $ 30 $ 31 $ 103 $ 104
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Note 10 Employee Future Benefits

Total benefit costs recognized were as follows:

-------------------------------------------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Employer current service cost $ 4 $ 4 $ 13 $ 12
Interest cost 2 2 7 6
Expected return on plan assets (2) (2) (6) (6)
Amortization of net actuarial
losses 1 - 2 1
-------------------------------------------------------------------------
$ 5 $ 4 $ 16 $ 13
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Note 11 Financial Instruments and Risk Management

Unrecognized gains (losses) on derivative instruments were as follows:

-------------------------------------------------------------------------
Sept. 30 Dec. 31
2005 2004
-------------------------------------------------------------------------
Commodity price risk management
Natural gas $ (8) $ (9)
Power consumption 2 (1)
Interest rate risk management
Interest rate swaps 22 52
Foreign currency risk management
Foreign exchange contracts (38) (30)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 




Commodity Price Risk Management

- Natural Gas Production

At September 30, 2005, the Company had hedged 7.5 mmcf of natural gas per

day at NYMEX for October to December 2005 at an average price of U.S.

$1.92 per mcf. During the first nine months of 2005, the impact was a

loss of $9 million.

- Power Consumption

At September 30, 2005, the Company had hedged power consumption of

49,680 MWh from October to December 2005 at an average fixed price of

$49.94 per MWh. The impact of the hedge program during the first nine

months of 2005 was a gain of $1 million.

- Natural Gas Contracts

At September 30, 2005, the unrecognized gains (losses) on external

offsetting physical purchase and sale natural gas contracts were as

follows:




-------------------------------------------------------------------------
Volumes Unrecognized
(mmcf) Gain (Loss)
-------------------------------------------------------------------------
Physical purchase contracts 30,741 $ 29
Physical sale contracts (30,741) $ (28)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Interest Rate Risk Management

In May 2005, the Company unwound the following interest rate swaps:

-------------------------------------------------------------------------
Debt Swap Amount Swap Maturity Swap Rate (percent)
-------------------------------------------------------------------------
6.15% notes U.S. $300 June 15, 2019 U.S. LIBOR + 63 bps
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


The proceeds of $30 million have been deferred and are being amortized to

income over the remaining term of the underlying debt.

During the first nine months of 2005, the Company realized a gain of

$11 million from interest rate risk management activities.

Foreign Currency Risk Management

During the third quarter of 2005, the Company entered into the following

cross currency debt swaps:




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

 


During the first nine months of 2005, the Company realized a $4 million

loss from all foreign currency risk management activities.

During the first nine months of 2005, Husky recognized a gain of

$8 million from its long-dated forwards, which fixed the exchange rate on

U.S. dollar sales and were unwound in November 2004.

Sale of Accounts Receivable

The Company has a securitization program to sell, on a revolving basis,

accounts receivable to a third party up to $350 million. As at

September 30, 2005, $350 million in outstanding accounts receivable had

been sold under the program.



Terms and Abbreviations

bbls barrels

bps basis points

mbbls thousand barrels

mbbls/day thousand barrels per day

mmbbls million barrels

mcf thousand cubic feet

mmcf million cubic feet

mmcf/day million cubic feet per day

bcf billion cubic feet

tcf trillion cubic feet

boe barrels of oil equivalent

mboe thousand barrels of oil equivalent

mboe/day thousand barrels of oil equivalent per day

mmboe million barrels of oil equivalent

mcfge thousand cubic feet of gas equivalent

GJ gigajoule

mmbtu million British Thermal Units

mmlt million long tons

MW megawatt

MWh megawatt hour

NGL natural gas liquids

WTI West Texas Intermediate

NYMEX New York Mercantile Exchange

NIT NOVA Inventory Transfer(1)

LIBOR London Interbank Offered Rate

CDOR Certificate of Deposit Offered Rate

SEDAR System for Electronic Document Analysis and

Retrieval

FPSO Floating production, storage and offloading vessel

OPEC Organization of Petroleum Exporting Countries

WCSB Western Canada Sedimentary Basin

SAGD Steam-assisted gravity drainage

Capital Employed Short- and long-term debt and shareholders' equity

Capital Expenditures Includes capitalized administrative expenses and

capitalized interest but does not include proceeds

or other assets

Cash Flow Earnings from operations plus non-cash charges

from Operations before settlement of asset retirement obligations

and change in non-cash working capital

Equity Shares and retained earnings

Total Debt Long-term debt including current portion and bank

operating loans

hectare 1 hectare is equal to 2.47 acres

wildcat well Exploratory well drilled in an area where no

production exists

feedstock Raw materials which are processed into petroleum

products

(1) NOVA Inventory Transfer is an exchange or transfer of title of gas

that has been received into the NOVA pipeline system but not yet

delivered to a connecting pipeline.

Natural gas converted on the basis that six mcf equals one barrel of oil.

In this report, the terms "Husky Energy Inc.", "Husky", "we", "our" or

"the Company" mean Husky Energy Inc. and its subsidiaries and partnership

interests on a consolidated basis.

Husky Energy Inc. will host a conference call for analysts and investors on Wednesday, October 19, 2005 at 4:15 p.m. Eastern time to discuss Husky's third quarter results which will be released after market close on October 18, 2005. To participate, please dial 1-800-818-6210 beginning at 4:05 p.m. Eastern time. Mr. John C.S. Lau, President & Chief Executive Officer, Donald R. Ingram, Senior Vice President, Midstream & Refined Products and Neil D. McGee, Vice President & Chief Financial Officer will be participating in the call.

We appreciate your interest in Husky Energy and look forward to your participation in our conference call.

Those who are unable to listen to the call live may listen to a recording by dialing 1-800-558-5253 one hour after the completion of the call, approximately 6:15 p.m. Eastern time, then dialing reservation number 21259641. The PostView will be available until Saturday, November 19, 2005.

Media are invited to participate in the call on a listen-only basis by dialing 1-800-806-5839 beginning at 4:05 p.m. Eastern time.



FOR FURTHER INFORMATION PLEASE CONTACT:

Husky Energy Inc.
Mr. Colin Luciuk
Manager, Investor Relations
(403) 750-4938



or



Husky Energy Inc.
707-8th Avenue S.W.
Box 6525, Station D
Calgary, Alberta, Canada, T2P 3G7
(403) 298-6111
FAX(403) 298-6515
Website: www.huskyenergy.ca
Email: Investor.Relations@huskyenergy.ca