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FOR: HUSKY ENERGY INC.

TSX SYMBOL:
 HSE

Husky Energy Announces 2005 Second Quarter Results

Jul 19, 2005 - 11:59 ET

CALGARY--(CCNMatthews - July 19) - Husky Energy Inc. reported net earnings of $394 million or $0.93 per share (diluted) in the second quarter of 2005, a 72 percent increase over net earnings of $229 million or $0.54 per share (diluted) in the second quarter of 2004. Included in net earnings for the second quarter of 2005 are net charges of $54 million related to stock-based compensation and $14 million related to U.S. dollar denominated debt translation. Cash flow from operations was $828 million or $1.95 per share (diluted) in the second quarter of 2005, a 43 percent increase compared with $581 million or $1.37 per share (diluted) in the second quarter of 2004. Sales and operating revenues, net of royalties, were $2.5 billion in the second quarter of 2005, a 13 percent increase compared with $2.2 billion in the second quarter of 2004.

"We are pleased with Husky's second quarter record solid cash flow from operations," said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. "In this strong commodity price environment, Husky's financial and operational strength continues to benefit from our integration, quality asset base and strong financial discipline."

Production in the second quarter of 2005 was 308,900 barrels of oil equivalent per day, compared with 326,400 barrels of oil equivalent per day in the second quarter of 2004. Total crude oil and natural gas liquids production was 194,000 barrels per day, compared with 212,200 barrels per day in the second quarter of 2004. Natural gas production was 689.3 million cubic feet per day, compared with 685.4 million cubic feet per day in the second quarter of 2004.

"In Western Canada, production was affected by unseasonably wet weather," said Mr. Lau. "An extended spring break-up followed by heavy rainfall throughout Alberta caused delays in the tie-in of our natural gas program and in the development of Husky's heavy oil reserves."

Operational issues continued to affect production at Terra Nova during the quarter. Our share of production for the quarter was 13,500 barrels per day compared to 15,700 barrels per day in the second quarter of 2004.

Husky made progress on several initiatives. A sailaway ceremony for the SeaRose FPSO was held in early July in Marystown, Newfoundland and Labrador. The vessel will depart Marystown in early August and, after a series of tests in Mortier Bay, sail to the White Rose oil field.

During the third quarter, the SeaRose FPSO will be connected to the subsea production system. The White Rose project is expected to be on schedule to achieve first oil before year-end and add approximately 67,500 barrels per day of light oil production net to Husky when it attains full productive capacity.

Drilling at the Lewis Hill prospect in the South Whale Basin offshore Newfoundland commenced on July 11, 2005. Husky has a 100 percent working interest in this location. After completion of drilling at Lewis Hill, two wells will be drilled at the White Rose oil field with the objective of delineating reserves beyond those currently under development.

In the South China Sea, the Wushi 17-1-1 well was drilled in Block 23/15 during the second quarter in the Beibu Gulf and encountered hydrocarbons. The well data are currently being evaluated. Husky plans to immediately drill a second exploration well on the adjacent Block 23/20. A rig has been secured for the deep water location in Block 29/26 and drilling is expected to commence by the end of 2005 or in early 2006.

At Husky's Tucker thermal oil sands project, facility construction continues on schedule. During the second quarter, work progressed well on the drilling program for 30 horizontal well pairs. At the end of the second quarter, overall facility construction was 25 percent complete. The Sunrise thermal oil sands project conceptual studies for marketing options are underway and regulatory project approval is expected by the end of 2005 or early 2006.

Husky's net earnings for the first six months of 2005 were $778 million or $1.84 per share (diluted), compared with $484 million or $1.14 per share (diluted) for the same period in 2004. Cash flow from operations for the first six months of 2005 was $1,644 million or $3.88 per share (diluted), compared with $1,157 million or $2.72 per share (diluted) for the same period of 2004.

Production in the first six months of 2005 was 314,200 barrels of oil equivalent per day, compared with 325,400 barrels of oil equivalent per day in the same period in 2004. Total crude oil and natural gas liquids production was 200,400 barrels per day, compared with 212,100 barrels per day in the first six months of 2004. Natural gas production was 682.8 million cubic feet per day, compared with 679.5 million cubic feet per day in the first six months of 2004. Production levels in Western Canada for the first six months of 2005 were affected by a lengthy spring break-up and unseasonably wet weather.



MANAGEMENT'S DISCUSSION AND ANALYSIS July 19, 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 June 30 March 31 Dec. 31 Sept. 30
per share amounts and ratios) 2005 2005 2004 2004
-------------------------------------------------------------------------
Sales and operating revenues,
net of royalties $ 2,493 $ 2,201 $ 2,018 $ 2,191
Segmented earnings
Upstream $ 307 $ 239 $ 112 $ 161
Midstream 130 169 77 50
Refined Products 20 18 (3) 18
Corporate and eliminations (63) (42) 39 68
-------------------------------------------------------------------------
Net earnings $ 394 $ 384 $ 225 $ 297
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Per share
- Basic $ 0.93 $ 0.91 $ 0.53 $ 0.70
- Diluted 0.93 0.91 0.53 0.70
Cash flow from operations 828 816 469 571
Per share
- Basic 1.95 1.93 1.11 1.34
- Diluted 1.95 1.93 1.11 1.34
Dividends declared per
common share 0.14 0.12 0.12 0.12
Special dividend per
common share - - 0.54 -
Total assets 14,058 13,690 13,240 12,901
Total long-term debt including
current portion 2,192 2,290 2,103 2,096
Return on equity(2)
(percent) 20.2 18.3 17.0 17.7
Return on average capital
employed(2) (percent) 15.3 13.9 13.0 13.4
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-------------------------------------------------------------------------
Financial Summary(1) Three months ended
(millions of dollars, except June 30 March 31 Dec. 31 Sept. 30
per share amounts and ratios) 2004 2004 2003 2003
-------------------------------------------------------------------------
Sales and operating revenues,
net of royalties $ 2,210 $ 2,021 $ 1,800 $ 1,871
Segmented earnings
Upstream $ 204 $ 236 $ 169 $ 215
Midstream 53 60 46 41
Refined Products 21 5 6 22
Corporate and eliminations (49) (46) 31 (42)
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Net earnings $ 229 $ 255 $ 252 $ 236
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Per share
- Basic $ 0.54 $ 0.60 $ 0.60 $ 0.56
- Diluted 0.54 0.60 0.59 0.56
Cash flow from operations 581 576 561 597
Per share
- Basic 1.37 1.36 1.33 1.42
- Diluted 1.37 1.36 1.32 1.42
Dividends declared per
common share 0.12 0.10 0.10 0.10
Special dividend per
common share - - - 1.00
Total assets 12,542 12,317 11,949 11,771
Total long-term debt including
current portion 2,229 1,993 1,989 2,279
Return on equity(2)
(percent) 16.8 21.8 26.4 27.2
Return on average capital
employed(2) (percent) 12.7 16.2 18.9 19.0
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(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, Three months ended
before Royalties June 30 March 31 Dec. 31 Sept. 30 June 30
2005 2005 2004 2004 2004
-------------------------------------------------------------------------
Crude oil and NGL
(mbbls/day)
Western Canada
Light crude oil
& NGL 31.7 31.9 32.9 33.1 32.9
Medium crude oil 30.6 32.4 33.7 34.5 35.6
Heavy crude oil 100.9 110.4 113.8 108.8 107.4
-------------------------------------------------------------------------
163.2 174.7 180.4 176.4 175.9
East Coast Canada
Terra Nova -
light crude oil 13.5 13.7 10.1 11.5 15.7
China
Wenchang - light
crude oil 17.3 18.5 17.9 20.2 20.6
-------------------------------------------------------------------------
194.0 206.9 208.4 208.1 212.2
-------------------------------------------------------------------------
Natural gas
(mmcf/day) 689.3 676.2 697.4 700.4 685.4
-------------------------------------------------------------------------
Total
(mboe/day) 308.9 319.6 324.6 324.8 326.4
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Crude oil and natural gas production in the second quarter of 2005 was 308.9 mboe/day compared with 319.6 mboe/day in the previous quarter and 326.4 mboe/day in the second quarter of 2004.

Production in the second quarter of 2005 compared with the first quarter of 2005 decreased primarily as a result of 9.5 mbbls/day lower heavy oil production from the Lloydminster region resulting primarily from exceptionally wet weather and 1.2 mbbls/day lower production from the Wenchang, China oil field from natural reservoir declines. Lower crude oil production in the second quarter of 2005 compared with the first quarter of 2005 was partially offset by higher production of natural gas and NGL.

Natural gas production volume averaged 13.1 mmcf/day higher in the second quarter of 2005 compared with the first quarter of 2005. Natural gas production was affected by a major turnaround at the Ram River gas plant and wet weather during the quarter that restricted our access to drilling operations in the foothills and deep basin area of Alberta and British Columbia. At the end of the quarter a number of wells in these areas were temporarily suspended from drilling and completion activities.

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 Six months Six months Year ended
ended ended December
June 30 Forecast June 30 31
2005 2005 2004 2004
-------------------------------------------------------------------------
Crude oil & NGL (mbbls/day)
Light crude oil &
NGL 63.3 64 - 71 69.8 66.2
Medium crude oil 31.5 32 - 36 35.8 35.0
Heavy crude oil 105.6 112 - 120 106.5 108.9
-------------------------------------------------------------------------
200.4 208 - 227 212.1 210.1
Natural gas (mmcf/day) 682.8 700 - 740 679.5 689.2
Total barrels of oil
equivalent (mboe/day) 314.2 325 - 350 325.4 325.0
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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 in non-conventional production from oil sands in Western Canada, offshore Canada's East Coast and international properties in China and Indonesia. 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 June 30, 2005, we have invested in the following major development projects offshore Canada's East Coast and in the Alberta oil sands:




-------------------------------------------------------------------------
Productive Working
Project 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 50 mbbls/day(2) 100% 2009 - 2010
-------------------------------------------------------------------------
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(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

At Marystown, Newfoundland and Labrador, construction of the SeaRose FPSO is complete and 24 of the 42 topside modules have been turned over to us as complete and ready for testing and commissioning. The crew of the SeaRose FPSO is nearing the end of training at the Marine Institute in St. John's and is on site. Sailaway is expected to occur in early August.

At the White Rose oil field, drilling and completion of the 10 wells that will be operating at first oil is progressing. Three water injection wells, one gas injection well and one production well have been completed and completion of three water injection wells and two production wells is currently underway. The flexible production and gas injection flow lines are being installed during the third quarter.

Tucker

During the second quarter of 2005, drilling operations commenced from two drilling pads. At pad "A" the intermediate casing strings have been set on all eight SAGD well pairs. Drilling of the horizontal section for these wells commenced in early July. At pad "B" the surface casing has been set for all 12 SAGD well pairs and currently the intermediate casing strings are being drilled. Construction of pad "C" is underway where 10 SAGD well pairs will be drilled. Facility construction is progressing with equipment and modules being delivered to the field. Construction on the control complex building has commenced. Overall facility construction is 25 percent complete. The project remains on schedule for commissioning work to commence in the second half of 2006.

Sunrise

At Sunrise, the regulatory approval process is continuing; regulatory approval for the project is expected in late 2005 or early 2006. Project work continued on the conceptual design and the marketing options for the project.

Exploration

- Western Canada

During the second quarter of 2005, we drilled 51 exploratory wells (36 net) resulting in 36 (21 net) natural gas completions and 10 (10 net) oil completions.

Exploration activity in our key areas in the foothills, deep basin and northwestern plains of Alberta and British Columbia was restricted due to spring break-up and exceptionally wet weather.

- Northwest Territories

During the second quarter of 2005, we became the operator of Exploration License 387 on which the 2004 Summit Creek B-44 discovery well was drilled and in which we have a 29.5 percent working interest. We are planning to shoot a 200 kilometre seismic program in this area in July and further delineation drilling in the winter.

- East Coast

The Rowan Gorilla VI jack-up rig has been contracted to drill the Lewis Hill prospect in the South Whale Basin (100 percent working interest). The well spudded in early July.

In the northern Jeanne d'Arc Basin, Husky will be shooting a 700 square kilometre seismic program over our exploration blocks north of the White Rose oil field. This program is expected to commence in the third quarter.

- China

In the Beibu Gulf, the COSL 931 shallow-water jack-up rig drilled the Wushi 17-1-1 prospect on Block 23/15. The rig will move south to the 32-1-1 prospect on Block 23/20 contiguous to the 23/15 block.

A deep-water drill ship has been contracted to drill a prospect on Block 29/26 in the Pearl River Mouth Basin. The site survey for the location is currently being conducted and the well is expected to spud in the fourth quarter of 2005 or early 2006.

- Indonesia

In Indonesia, work is progressing toward establishing a natural gas contract for two natural gas fields yet to be developed in the Madura Strait, offshore Java. In addition, seismic studies on the Madura exploration prospects are underway.

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 for mid 2006 with connections to be made in September 2005 during the 30 day scheduled plant turnaround. The projects are expected to cost approximately $60 million.

REFINED PRODUCTS

Prince George Refinery

The refinery is currently being modified to produce low sulphur fuels. The project is in the construction phase. Production of desulphurized gasoline and diesel is expected to commence in July 2005 and March 2006, respectively. The project is expected to cost approximately $93 million.

Lloydminster Ethanol Plant

At Lloydminster, Saskatchewan we are constructing a 130 million litre per year ethanol plant. The project is in the construction phase and is scheduled for completion in early 2006. The project is expected to cost approximately $120 million.

Minnedosa Ethanol Plant

At Minnedosa, Manitoba we are currently considering plans to increase the capacity of the existing plant from 10 million litres to 130 million litres per year.

Husky established an endowment of $1 million at the University of Manitoba for the creation of two research chairs in biofuels with a focus on ethanol. We will also provide an additional $1.625 million over 5 years which the university will seek to augment through government support programs.

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 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 Three months ended
Prices and U.S. June 30 March 31 Dec. 31 Sept. 30 June 30
Exchange Rate 2005 2005 2004 2004 2004
-------------------------------------------------------------------------
WTI crude oil(1)
(U.S. $/bbl) $ 53.17 $ 49.84 $ 48.28 $ 43.88 $ 38.32
Canadian par light
crude 0.3% sulphur
($/bbl) 66.43 62.02 58.01 56.61 50.99
Lloyd @
Lloydminster heavy
crude oil ($/bbl) 27.95 22.62 25.31 35.47 28.09
NYMEX natural gas(1)
(U.S. $/mmbtu) 6.73 6.27 7.11 5.76 5.97
NIT natural gas
($/GJ) 6.99 6.34 6.72 6.32 6.45
WTI/Lloyd crude
blend differential
(U.S. $/bbl) 21.27 19.57 19.82 12.86 11.82
U.S./Canadian dollar
exchange rate
(U.S. $) 0.804 0.815 0.819 0.765 0.736
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 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)
-------------------------------------------------------------------------
Q2-03 Q3-03 Q4-03 Q1-04 Q2-04
-------------------------------------------------------------------------
West Texas
Intermediate ("WTI")
(U.S. $) $28.91 $30.20 $31.18 $35.15 $38.32
-------------------------------------------------------------------------
Husky average light
crude oil price
(C $) $36.45 $38.49 $38.55 $42.50 $47.99
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Husky average medium
crude oil price
(C $) $30.48 $29.68 $27.25 $32.97 $35.98
-------------------------------------------------------------------------
Husky average heavy
crude oil price
(C $) $25.13 $25.13 $20.84 $26.38 $27.54
-------------------------------------------------------------------------


--------------------------------------------------------------
Q3-04 Q4-04 Q1-05 Q2-05
--------------------------------------------------------------
West Texas
Intermediate ("WTI")
(U.S. $) $43.88 $48.28 $49.84 $53.17
--------------------------------------------------------------
Husky average light
crude oil price
(C $) $53.94 $50.29 $58.94 $62.49
--------------------------------------------------------------
Husky average medium
crude oil price
(C $) $40.59 $35.06 $36.50 $40.45
--------------------------------------------------------------
Husky average heavy
crude oil price
(C $) $34.92 $25.81 $22.53 $27.95
--------------------------------------------------------------

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.

Natural Gas

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

-------------------------------------------------------------------------
Q2-03 Q3-03 Q4-03 Q1-04 Q2-04
-------------------------------------------------------------------------
NYMEX natural gas
(U.S. $/mmbtu) $5.39 $4.97 $4.58 $5.69 $5.97
-------------------------------------------------------------------------
NIT natural gas
(C $/GJ) $6.63 $5.97 $5.30 $6.26 $6.45
-------------------------------------------------------------------------
Husky average natural
gas price (C $/mcf) $5.50 $5.40 $4.87 $6.05 $6.38
-------------------------------------------------------------------------


--------------------------------------------------------------
Q3-04 Q4-04 Q1-05 Q2-05
--------------------------------------------------------------
NYMEX natural gas
(U.S. $/mmbtu) $5.76 $7.11 $6.27 $6.73
--------------------------------------------------------------
NIT natural gas
(C $/GJ) $6.32 $6.72 $6.34 $6.99
--------------------------------------------------------------
Husky average natural
gas price (C $/mcf) $5.92 $6.64 $6.07 $6.76
--------------------------------------------------------------

 


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. 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 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 June 30, 2005, 78 percent or $1.7 billion of our long-term debt was denominated in U.S. dollars. The Cdn/U.S. exchange rate at the end of the second quarter of 2005 was $1.2256. The percentage of our long-term debt exposed to the Cdn/U.S. exchange rate decreases to 59 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. 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 second 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 76 0.18 50 0.12
NYMEX benchmark
natural gas
price(1) U.S. $0.20/mmbtu 38 0.09 24 0.06
Light/heavy
crude oil
differential(2) Cdn $1.00/bbl (23) (0.05) (14) (0.03)
Light oil
margins Cdn $0.005/litre 16 0.04 10 0.02
Asphalt
margins Cdn $1.00/bbl 7 0.02 5 0.01
Exchange rate
(U.S. $/Cdn $)
(3) U.S. $0.01 (53) (0.13) (36) (0.08)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes decrease in earnings related to natural gas consumption.
(2) Includes impact of upstream and upgrading operations only.
(3) Assumes no foreign exchange gains or losses on U.S. dollar
denominated long-term debt and other monetary items. The impact of
the Canadian dollar strengthening by U.S. $0.01 would be an increase
of $13 million in net earnings based on June 30, 2005 U.S. dollar
denominated debt levels.
(4) Based on June 30, 2005 common shares outstanding of 424.0 million.


RESULTS OF OPERATIONS

UPSTREAM
-------------------------------------------------------------------------
Upstream Earnings Summary Three months Six months
ended June 30 ended June 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross revenues $ 1,154 $ 1,097 $ 2,194 $ 2,110
Royalties 178 182 330 340
Hedging - 115 - 189
-------------------------------------------------------------------------
Net revenues 976 800 1,864 1,581
Operating and administration
expenses 249 240 489 465
Depletion, depreciation and
amortization 278 262 551 516
Income taxes 142 94 278 160
-------------------------------------------------------------------------
Earnings $ 307 $ 204 $ 546 $ 440
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Net Revenue Variance Analysis
(millions of dollars) Crude oil Natural
& NGL gas Other Total
-------------------------------------------------------------------------
Three months ended June 30,
2004 $ 480 $ 299 $ 21 $ 800
Price changes 96 23 - 119
Volume changes (63) 2 - (61)
Royalties (3) 7 - 4
Hedging 114 1 - 115
Processing and sulphur - - (1) (1)
-------------------------------------------------------------------------
Three months ended June 30,
2005 $ 624 $ 332 $ 20 $ 976
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Six months ended June 30, 2004 $ 948 $ 596 $ 37 $ 1,581
Price changes 156 22 - 178
Volume changes (92) (1) - (93)
Royalties (8) 18 - 10
Hedging 193 (4) - 189
Processing and sulphur - - (1) (1)
-------------------------------------------------------------------------
Six months ended June 30, 2005 $ 1,197 $ 631 $ 36 $ 1,864
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Second Quarter

Upstream earnings were $103 million higher in the second quarter of 2005 than in the second quarter of 2004 as a result of the following factors:

- Higher crude oil and natural gas prices

- Hedging diverted $115 million in the second quarter of 2004; second

quarter of 2005 commodity prices were not hedged

- Higher production of natural gas and NGL

Partially offset by:

- Lower sales volume of crude oil

- Higher unit operating costs

- Higher unit depletion, depreciation and amortization

- Higher income taxes

Six Months

With the exception of income taxes, the factors that affected upstream performance in the first six months of 2005 compared with the first six months of 2004 were essentially the same as those during the second quarter of 2005 and 2004. The effective income tax rate was lower in the first six months of 2004 as a result of a cumulative benefit from a rate reduction enacted during the first quarter of 2004.

Unit Operating Costs

Unit operating costs were eight percent higher in the second quarter of 2005 compared with the same period in 2004 due to increased natural gas compression costs, higher natural gas well count, turnaround and production declines.

Unit Depletion, Depreciation and Amortization

Unit depletion, depreciation and amortization expense increased 12 percent in the second quarter of 2005 compared with the same period in 2004. The increase resulted from a higher capital base in 2005 as a result of the increased requirement for production maintenance capital for our properties in the Western Canada Sedimentary Basin, offshore operations requiring a higher proportion of capital and higher capital costs associated with purchase of reserves in place. In addition, the exceptionally wet weather restricted well completions, particularly in the Rocky Mountain foothills and deep basin area of Alberta and as a result reserves bookings were delayed.




-------------------------------------------------------------------------
Average Sales Prices Three months Six months
ended June 30 ended June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Crude Oil ($/bbl)
Light crude oil & NGL $ 59.51 $ 47.41 $ 57.95 $ 44.60
Medium crude oil 40.45 35.98 38.42 34.46
Heavy crude oil 27.95 27.54 25.13 26.96
Total average 40.09 35.12 37.59 33.77
Natural Gas ($/mcf)
Average 6.76 6.38 6.42 6.22
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Effective Royalty Rates(1)
Three months Six months
Percentage of upstream ended June 30 ended June 30
sales revenues 2005 2004 2005 2004
-------------------------------------------------------------------------
Crude oil & NGL 13% 13% 13% 13%
Natural gas 20% 23% 20% 22%
Total 16% 17% 15% 16%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Before commodity hedging.


-------------------------------------------------------------------------
Upstream Revenue Mix(1)
Three months Six months
Percentage of upstream ended June 30 ended June 30
sales revenues, after royalties 2005 2004 2005 2004
-------------------------------------------------------------------------
Light crude oil & NGL 31% 28% 31% 28%
Medium crude oil 10% 11% 10% 11%
Heavy crude oil 23% 26% 23% 26%
Natural gas 36% 35% 36% 35%
-------------------------------------------------------------------------
100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Before commodity hedging.


OPERATING NETBACKS

Western Canada
-------------------------------------------------------------------------
Light Crude Oil Netbacks(1) Three months Six months
ended June 30 ended June 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 57.50 $ 45.82 $ 53.92 $ 43.11
Royalties 7.64 8.83 6.23 7.99
Operating costs 11.26 9.30 10.53 9.07
-------------------------------------------------------------------------
Netback $ 38.60 $ 27.69 $ 37.16 $ 26.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Medium Crude Oil Netbacks(1) Three months Six months
ended June 30 ended June 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 40.61 $ 35.98 $ 38.49 $ 34.51
Royalties 6.98 6.29 6.69 5.95
Operating costs 10.05 9.66 10.30 9.65
-------------------------------------------------------------------------
Netback $ 23.58 $ 20.03 $ 21.50 $ 18.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Heavy Crude Oil Netbacks(1) Three months Six months
ended June 30 ended June 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 28.09 $ 27.65 $ 25.28 $ 27.09
Royalties 3.09 3.13 2.62 2.96
Operating costs 9.48 9.24 9.35 9.31
-------------------------------------------------------------------------
Netback $ 15.52 $ 15.28 $ 13.31 $ 14.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Natural Gas Netbacks(2) Three months Six months
ended June 30 ended June 30
Per mcfge 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 6.81 $ 6.36 $ 6.50 $ 6.19
Royalties 1.51 1.51 1.45 1.43
Operating costs 1.00 0.87 0.97 0.83
-------------------------------------------------------------------------
Netback $ 4.30 $ 3.98 $ 4.08 $ 3.93
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Total Western Canada
Upstream Netbacks(1) Three months Six months
ended June 30 ended June 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 37.81 $ 34.84 $ 35.36 $ 33.75
Royalties 6.49 6.45 5.91 6.06
Operating costs 8.26 7.77 8.19 7.69
-------------------------------------------------------------------------
Netback $ 23.06 $ 20.62 $ 21.26 $ 20.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.
(2) Includes associated co-products converted to mcfge.


-------------------------------------------------------------------------
Terra Nova Crude Oil Netbacks
Three months Six months
ended June 30 ended June 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 58.11 $ 47.69 $ 59.42 $ 45.37
Royalties 2.86 1.16 2.94 1.12
Operating costs 3.29 2.86 3.61 2.82
-------------------------------------------------------------------------
Netback $ 51.96 $ 43.67 $ 52.87 $ 41.43
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Wenchang Crude Oil Netbacks Three months Six months
ended June 30 ended June 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 66.11 $ 48.24 $ 62.42 $ 44.77
Royalties 6.16 4.81 5.78 4.51
Operating costs 2.39 2.02 2.38 2.10
-------------------------------------------------------------------------
Netback $ 57.56 $ 41.41 $ 54.26 $ 38.16
-------------------------------------------------------------------------
-------------------------------------------------------------------------


-------------------------------------------------------------------------
Total Upstream Segment
Netbacks(1) Three months Six months
ended June 30 ended June 30
Per boe 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales revenues $ 40.29 $ 36.31 $ 37.94 $ 35.04
Royalties 6.31 6.09 5.77 5.71
Operating costs 7.74 7.17 7.67 7.10
-------------------------------------------------------------------------
Netback $ 26.24 $ 23.05 $ 24.50 $ 22.23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.


MIDSTREAM

-------------------------------------------------------------------------
Upgrading Earnings Summary
Three months Six months
(millions of dollars, except ended June 30 ended June 30
where indicated) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross margin $ 195 $ 83 $ 402 $ 168
Operating costs 53 53 103 105
Other recoveries (2) (1) (3) (2)
Depreciation and amortization 4 4 9 9
Income taxes 43 8 89 14
-------------------------------------------------------------------------
Earnings $ 97 $ 19 $ 204 $ 42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Upgrader throughput(1)
(mbbls/day) 71.3 56.6 71.7 63.4
Synthetic crude oil sales
(mbbls/day) 60.1 44.1 62.0 51.1
Upgrading differential
($/bbl) $ 31.05 $ 17.10 $ 31.51 $ 15.25
Unit margin ($/bbl) $ 35.64 $ 20.76 $ 35.80 $ 18.02
Unit operating cost(2)
($/bbl) $ 8.12 $ 10.31 $ 7.91 $ 9.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Throughput includes diluent returned to the field.
(2) Based on throughput.


-------------------------------------------------------------------------
Upgrading Earnings Variance Analysis
(millions of dollars)
-------------------------------------------------------------------------
Three months ended June 30, 2004 $ 19
Volume 30
Margin 82
Operating costs - energy related (6)
Operating costs - non-energy related 6
Other 1
Income taxes (35)
-------------------------------------------------------------------------
Three months ended June 30, 2005 $ 97
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30, 2004 $ 42
Volume 35
Margin 199
Operating costs - energy related (5)
Operating costs - non-energy related 7
Other 1
Income taxes (75)
-------------------------------------------------------------------------
Six months ended June 30, 2005 $ 204
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Second Quarter

Upgrading earnings increased in the second quarter of 2005 by $78 million compared with the second quarter of 2004 due to:

- Wider upgrading differential

- Higher sales volume of synthetic crude oil

- Lower non-energy related unit operating costs

Partially offset by:

- Higher energy related operating costs

- Higher income taxes due to higher earnings

Six Months

With the exception of income taxes, the factors that affected upgrading performance in the first six months of 2005 compared with the first six months of 2004 were essentially the same as those during the second quarter of 2005 and 2004. The income tax rate was lower in the first six months of 2004 as a result of a cumulative benefit from a rate reduction enacted during the first quarter of 2004.




-------------------------------------------------------------------------
Infrastructure and Marketing
Earnings Summary Three months Six months
(millions of dollars, except ended June 30 ended June 30
where indicated) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross margin
- pipeline $ 22 $ 23 $ 47 $ 42
- other infrastructure and
marketing 39 34 116 77
-------------------------------------------------------------------------
61 57 163 119
Other expenses 2 2 5 4
Depreciation and amortization 6 5 11 10
Income taxes 20 16 52 34
-------------------------------------------------------------------------
Earnings $ 33 $ 34 $ 95 $ 71
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Aggregate pipeline throughput
(mbbls/day) 488 520 499 515
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Second Quarter

Infrastructure and marketing earnings decreased slightly in the second quarter of 2005 compared with the second quarter of 2004 due to:

- Higher income taxes due to higher earnings

Partially offset by:

- Higher marketing margins for crude oil and natural gas

Six Months

The factors that affected infrastructure and marketing earnings in the first six months of 2005 compared with the first six months of 2004 were essentially the same as those during the second quarter of 2005 and 2004. In addition, pipeline margins were higher during the first six months of 2005 compared with 2004.



REFINED PRODUCTS

-------------------------------------------------------------------------
Refined Products Earnings Summary Three months Six months
(millions of dollars, except ended June 30 ended June 30
where indicated) 2005 2004 2005 2004
-------------------------------------------------------------------------
Gross margin
- fuel sales $ 24 $ 37 $ 53 $ 60
- ancillary sales 9 7 16 14
- asphalt sales 28 17 47 21
-------------------------------------------------------------------------
61 61 116 95
Operating and other expenses 19 18 36 35
Depreciation and amortization 11 9 20 18
Income taxes 11 13 22 16
-------------------------------------------------------------------------
Earnings $ 20 $ 21 $ 38 $ 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Number of fuel outlets 521 536
Light oil sales
(million litres/day) 8.8 8.5 8.6 8.4
Light oil sales per outlet
(thousand litres/day) 12.2 11.2 12.3 11.3
Prince George refinery
throughput (mbbls/day) 9.5 10.4 9.8 10.7
Asphalt sales (mbbls/day) 19.7 24.2 18.7 21.3
Lloydminster refinery
throughput (mbbls/day) 21.6 26.7 24.3 25.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Second Quarter

Refined products earnings decreased slightly in the second quarter of 2005 compared with the second quarter of 2004 due to:

- Lower marketing margins for gasoline and distillates

- Lower sales volume of asphalt products

Offset by:

- Higher sales volume of motor fuels

- Higher margins for asphalt products

- Lower income taxes

Six Months

With the exception of income taxes, the factors that affected refined products earnings in the first six months of 2005 compared with the first six months of 2004 were essentially the same as those during the second quarter of 2005 and 2004. Income taxes were lower in the first six months of 2004 as a result of a cumulative benefit from a rate reduction enacted during the first quarter of 2004.



CORPORATE

-------------------------------------------------------------------------
Corporate Summary(1) Three months Six months
ended June 30 ended June 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Intersegment eliminations -
net $ (14) $ 13 $ 9 $ 30
Administration expenses 5 5 11 10
Stock-based compensation 77 22 98 23
Accretion 1 1 1 1
Other - net 3 2 6 4
Depreciation and amortization 5 8 11 18
Interest on debt 37 36 72 70
Interest capitalized (31) (18) (55) (35)
Interest income - (1) (1) (1)
Foreign exchange 20 12 27 24
Income taxes (40) (31) (74) (49)
-------------------------------------------------------------------------
Loss $ (63) $ (49) $ (105) $ (95)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2004 amounts as restated. Refer to Note 3 to the Consolidated
Financial Statements.


-------------------------------------------------------------------------
Foreign Exchange Summary
Three months Six months
ended June 30 ended June 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
(Gain) loss on translation of
U.S. dollar denominated
long-term debt
Realized $ - $ - $ (4) $ (2)
Unrealized 22 25 35 48
-------------------------------------------------------------------------
22 25 31 46
Cross currency swaps (4) (9) (6) (14)
Other (gains) losses 2 (4) 2 (8)
-------------------------------------------------------------------------
$ 20 $ 12 $ 27 $ 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
U.S./Canadian dollar
exchange rates:
At beginning of period U.S. U.S. U.S. U.S.
$0.827 $0.763 $0.831 $0.774
At end of period U.S. U.S. U.S. U.S.
$0.816 $0.746 $0.816 $0.746
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Second Quarter

The corporate loss of $63 million in the second quarter of 2005 compared with $49 million in the second quarter of 2004 was due to:

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

2005

- Higher foreign exchange costs on U.S. dollar denominated debt

Partially offset by:

- Lower depreciation and amortization

- Higher capitalized interest resulting from the higher White Rose

project capital base

- Higher income tax recovery

- Higher inclusion of intersegment profit previously eliminated

Six Months

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




CONSOLIDATED INCOME TAXES

-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Income taxes before tax
amendments $ 195 $ 113 $ 386 $ 228
Bill 27 - Alberta Corporate
Tax Amendment Act, 2004 - - - 40
Other items 19 13 19 13
-------------------------------------------------------------------------
Income taxes as reported $ 176 $ 100 $ 367 $ 175
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 




LIQUIDITY AND CAPITAL RESOURCES

OPERATING ACTIVITIES

In the second quarter of 2005, cash generated from operating activities amounted to $771 million compared with $464 million in the second quarter of 2004. Higher cash flow from operating activities was due to higher earnings.

FINANCING ACTIVITIES

In the second quarter of 2005, cash used in financing activities amounted to $192 million compared with cash generated from financing activities of $129 million in the second quarter of 2004. During the second quarter of 2005, higher debt repayments and dividends net of borrowings and monetization resulted in higher use of cash compared with the second quarter of 2004.

INVESTING ACTIVITIES

In the second quarter of 2005, cash used in investing activities amounted to $585 million compared with $550 million in the second 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 Six months
ended June 30 ended June 30
(millions of dollars) 2005 2004 2005 2004
-------------------------------------------------------------------------
Upstream
Exploration
Western Canada $ 153 $ 56 $ 314 $ 204
East Coast Canada and
Frontier 14 8 18 14
International 19 9 23 11
-------------------------------------------------------------------------
186 73 355 229
-------------------------------------------------------------------------
Development
Western Canada 223 214 594 545
East Coast Canada 126 130 246 206
International 1 4 3 4
-------------------------------------------------------------------------
350 348 843 755
-------------------------------------------------------------------------
536 421 1,198 984
-------------------------------------------------------------------------
Midstream
Upgrader 30 18 47 26
Infrastructure and Marketing 7 4 13 7
-------------------------------------------------------------------------
37 22 60 33
-------------------------------------------------------------------------
Refined Products 43 14 48 24
Corporate 4 6 8 11
-------------------------------------------------------------------------
Capital expenditures 620 463 1,314 1,052
Settlement of asset retirement
obligations (7) (5) (10) (11)
-------------------------------------------------------------------------
Capital expenditures per
Consolidated Statements
of Cash Flows $ 613 $ 458 $ 1,304 $ 1,041
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period and corporate acquisitions.

 


Upstream capital expenditures totaled $1,198 million, 91 percent of total consolidated capital expenditures during the first six months of 2005 compared with $984 million or 94 percent of the total, during the first six months of 2004.





-------------------------------------------------------------------------
Upstream Capital Expenditures Six months
ended June 30
(millions of dollars) 2005
-------------------------------------------------------------------------
Western Canada Sedimentary Basin sustaining exploitation $ 644
Western Canada foothills and deep basin exploration 131
Western Canada oil sands 133
Eastern Canada offshore and Northwest Territories 264
International exploration and development 26
-------------------------------------------------------------------------
$ 1,198
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The remaining capital expenditures during the first six months of 2005
amounting to $116 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 Three months Six months
Drilled (1)(2) ended June 30 ended June 30
2005 2004 2005 2004
Gross Net Gross Net Gross Net Gross Net
-------------------------------------------------------------------------
Exploration Oil 10 10 5 5 35 32 13 12
Gas 36 21 16 11 132 93 124 111
Dry 5 5 1 1 19 19 29 29
-------------------------------------------------------------------------
51 36 22 17 186 144 166 152
-------------------------------------------------------------------------

Development Oil 65 58 88 85 131 119 196 180
Gas 47 44 121 113 278 265 411 388
Dry 5 5 10 10 15 15 37 34
-------------------------------------------------------------------------
117 107 219 208 424 399 644 602
-------------------------------------------------------------------------
Total 168 143 241 225 610 543 810 754
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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
Six
months Year
ended ended
June December
(millions of dollars) 30 2005 31 2004
-------------------------------------------------------------------------
Cash sourced
Cash flow from operations(1) $ 1,644 $ 2,197
Debt issue 2,451 2,200
Asset sales 57 36
Proceeds from exercise of stock options 4 18
Proceeds from monetization of financial
instruments 30 8
-------------------------------------------------------------------------
4,186 4,459
-------------------------------------------------------------------------
Cash used
Capital expenditures 1,304 2,349
Corporate acquisitions - 102
Debt repayment 2,408 1,959
Special dividend on common shares - 229
Ordinary dividends on common shares 110 195
Settlement of asset retirement obligations 14 40
Other 2 24
-------------------------------------------------------------------------
3,838 4,898
-------------------------------------------------------------------------
Net cash (deficiency) 348 (439)
Increase (decrease) in non-cash working capital (352) 443
-------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (4) 4
Cash and cash equivalents - beginning of period 7 3
-------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 3 $ 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Increase (decrease) in non-cash working capital
Cash positive working capital change
Accounts receivable decrease $ - $ 209
Accounts payable and accrued liabilities
increase - 323
-------------------------------------------------------------------------
- 532
Cash negative working capital change
Accounts receivable increase 20 -
Inventory increase 140 77
Prepaid expense increase 18 12
Accounts payable and accrued liabilities decrease 174 -
-------------------------------------------------------------------------
352 89
-------------------------------------------------------------------------
Increase (decrease) in non-cash working capital $ (352) $ 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 June 30, 2005, our working capital deficiency was $445 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
June 30, 2005
Outstanding Available
(millions of dollars) (U.S. $) (Cdn $) (Cdn $)
-------------------------------------------------------------------------
Short-term bank debt $ 3 $ 34 $ 147
Long-term bank debt
Syndicated credit facility - 100 900
Bilateral credit facilities - 90 60
Medium-term notes - 300
Capital securities 225 276
U.S. public notes 1,050 1,287
U.S. senior secured bonds 99 121
U.S. private placement notes 15 18
-------------------------------------------------------------------------
Total short-term and long-term debt $ 1,392 $ 2,226 $ 1,107
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares and retained earnings $ 6,877
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Financial Ratios

Three months Six months
(millions of dollars, ended June 30 ended June 30
except ratios) 2005 2004 2005 2004
-------------------------------------------------------------------------
Cash flow
- operating activities $ 771 $ 464 $ 1,500 $ 1,165
- financing activities $ (192) $ 129 $ (253) $ 51
- investing activities $ (585) $ (550) $ (1,251) $ (1,144)
Debt to capital employed
(percent) 24.5 27.1
Corporate reinvestment
ratio (1) (2) 1.0 1.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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
July-
Payments due by period December 2006- 2008- There-
(millions of dollars) Total 2005 2007 2009 after
-------------------------------------------------------------------------
Long-term debt $ 2,192 $ 36 $ 378 $ 660 $ 1,118
Operating leases 528 34 158 153 183
Firm transportation
agreements 772 93 308 188 183
Unconditional purchase
obligations 942 283 592 52 15
Lease rentals 330 22 88 88 132
Exploration work agreements 51 27 15 - 9
Engineering and construction
commitments 908 516 380 12 -
-------------------------------------------------------------------------
$ 5,723 $ 1,011 $ 1,919 $ 1,153 $ 1,640
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


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. In June 2005, our receivable securitization program was 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. During the first six months of 2004, we paid approximately $9 million for office space in Western Canadian Place.

SIGNIFICANT CUSTOMERS

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

FINANCIAL AND DERIVATIVE INSTRUMENTS




POWER CONSUMPTION

At June 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 July to Dec. 2005 $ 49.25/MWh $ 0.4
12.5 July to Dec. 2005 $ 50.50/MWh 0.5
-------------------------------------------------------------------------
$ 0.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


FOREIGN CURRENCY RISK MANAGEMENT

At June 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

At June 30, 2005 the cost of a U.S. dollar in Canadian currency was $1.2256.

In the first six months of 2005, the cross currency swaps resulted in an offset to foreign exchange losses on translation of U.S. dollar denominated debt amounting to $6 million.

In addition, we entered into U.S. dollar forward contracts, which resulted in realized gains totalling less than $1 million in the first six 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 six months of 2005, we recognized a gain of $8 million.

INTEREST RATE RISK MANAGEMENT

In the first six months of 2005, the interest rate risk management activities resulted in a decrease to interest expense of $9 million.

The cross currency swaps resulted in an addition to interest expense of $5 million in the first six 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 six months of 2005, these swaps resulted in an offset to interest expense amounting to $3 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 six months of 2005, these swaps resulted in an offset to interest expense amounting to $4 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 six 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 $4 million offset to interest expense in the first six 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
-------------------------------------------------------------------------
Six months Year ended
ended June 30 December 31

(in thousands, except per share amounts) 2005 2004
-------------------------------------------------------------------------
Share price(1) High $ 50.75 $ 35.65
Low $ 32.30 $ 22.73
Close at end of period $ 48.73 $ 34.25
Average daily trading volume 741 482
Weighted average number of common shares
outstanding
Basic 423,841 423,362
Diluted 423,841 424,303
Issued and outstanding at end of period(2)
Number of common shares 423,983 423,736
Number of stock options 7,995 9,964
Number of stock options exercisable 2,281 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 June 30, 2005
to July 15, 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 six months ended June 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 second quarter of 2005 compared with the second quarter of 2004 and the first six months of 2005 compared with the first six 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:




-------------------------------------------------------------------------
Six months Year ended
ended June 30 December 31

(millions of dollars) 2005 2004
-------------------------------------------------------------------------
Non-GAAP Cash flow from operations $ 1,644 $ 2,197
Settlement of asset retirement
obligations (14) (40)
Change in non-cash working capital (130) 169
-------------------------------------------------------------------------
GAAP Cash flow - operating activities $ 1,500 $ 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
-------------------------------------------------------------------------
June 30 December 31
(millions of dollars) 2005 2004
-------------------------------------------------------------------------
(unaudited) (audited)

Assets
Current assets
Cash and cash equivalents $ 3 $ 7
Accounts receivable 466 446
Inventories 414 274
Prepaid expenses 69 52
-------------------------------------------------------------------------
952 779

Property, plant and equipment -
(full cost accounting) 20,631 19,451
Less accumulated depletion, depreciation
and amortization 7,801 7,258
-------------------------------------------------------------------------
12,830 12,193
Goodwill 160 160
Other assets 116 108
-------------------------------------------------------------------------
$ 14,058 $ 13,240
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Bank operating loans $ 34 $ 49
Accounts payable and accrued liabilities 1,310 1,498
Long-term debt due within one year (note 5) 53 56
-------------------------------------------------------------------------
1,397 1,603
Long-term debt (notes 3, 5) 2,139 2,047
Other long-term liabilities (note 4) 662 632
Future income taxes 2,983 2,758
Commitments and contingencies (note 6)
Shareholders' equity
Common shares (note 7) 3,515 3,506
Retained earnings 3,362 2,694
-------------------------------------------------------------------------
6,877 6,200
-------------------------------------------------------------------------
$ 14,058 $ 13,240
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares outstanding (millions) (note 7) 424.0 423.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 Six months
ended June 30 ended June 30

(millions of dollars, except
per share amounts) (unaudited) 2005 2004 2005 2004
-------------------------------------------------------------------------
Sales and operating revenues, net of
royalties $2,493 $2,210 $4,694 $4,231
Costs and expenses
Cost of sales and operating expenses 1,474 1,503 2,732 2,854
Selling and administration expenses 40 37 69 62
Stock-based compensation 77 22 98 23
Depletion, depreciation and
amortization 304 288 602 571
Interest - net (notes 3, 5) 6 17 16 34
Foreign exchange (notes 3, 5) 20 12 27 24
Other - net 2 2 5 4
-------------------------------------------------------------------------
1,923 1,881 3,549 3,572
-------------------------------------------------------------------------
Earnings before income taxes 570 329 1,145 659
-------------------------------------------------------------------------
Income taxes
Current 75 59 142 119
Future 101 41 225 56
-------------------------------------------------------------------------
176 100 367 175
-------------------------------------------------------------------------
Net earnings $ 394 $ 229 $ 778 $ 484
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per share (note 8)
Basic $ 0.93 $ 0.54 $ 1.84 $ 1.14
Diluted $ 0.93 $ 0.54 $ 1.84 $ 1.14
Weighted average number of common shares
outstanding (millions) (note 8)
Basic 423.9 423.4 423.8 423.1
Diluted 423.9 425.2 423.8 424.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated Statements of Retained Earnings
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

(millions of dollars) (unaudited) 2005 2004 2005 2004
-------------------------------------------------------------------------
Beginning of period $3,027 $2,325 $2,694 $2,156
Net earnings 394 229 778 484
Dividends on common shares (59) (51) (110) (93)
Stock-based compensation - retroactive
adoption - - - (44)
-------------------------------------------------------------------------
End of period $3,362 $2,503 $3,362 $2,503
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 Six months
ended June 30 ended June 30

(millions of dollars) (unaudited) 2005 2004 2005 2004
-------------------------------------------------------------------------
Operating activities
Net earnings $ 394 $ 229 $ 778 $ 484
Items not affecting cash
Accretion (note 4) 9 8 17 14
Depletion, depreciation and
amortization 304 288 602 571
Future income taxes 101 41 225 56
Foreign exchange 17 16 24 32
Other 3 (1) (2) -
Settlement of asset retirement
obligations (9) (7) (14) (13)
Change in non-cash working
capital (note 9) (48) (110) (130) 21
-------------------------------------------------------------------------
Cash flow - operating activities 771 464 1,500 1,165
-------------------------------------------------------------------------
Financing activities
Bank operating loans financing - net (48) (33) (15) (71)
Long-term debt issue 1,029 1,405 2,451 1,461
Long-term debt repayment (1,150) (1,194) (2,393) (1,267)
Debt issue costs - (5) - (5)
Proceeds from exercise of stock options 3 3 4 16
Proceeds from monetization of financial
instruments 30 - 30 -
Dividends on common shares (59) (51) (110) (93)
Change in non-cash working capital
(note 9) 3 4 (220) 10
-------------------------------------------------------------------------
Cash flow - financing activities (192) 129 (253) 51
-------------------------------------------------------------------------
Available for investing 579 593 1,247 1,216
-------------------------------------------------------------------------
Investing activities
Capital expenditures (613) (458) (1,304) (1,041)
Asset sales 14 14 57 14
Other (2) (14) (2) (12)
Change in non-cash working capital
(note 9) 16 (92) (2) (105)
-------------------------------------------------------------------------
Cash flow - investing activities (585) (550) (1,251) (1,144)
-------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents (6) 43 (4) 72
Cash and cash equivalents at beginning
of period 9 32 7 3
-------------------------------------------------------------------------
Cash and cash equivalents at end
of period $ 3 $ 75 $ 3 $ 75
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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

Six months ended June 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
June 30(1)
Sales and operating
revenues, net of
royalties $ 976 $ 800 $ 393 $ 213 $ 1,566 $ 1,669
Costs and expenses
Operating, cost of
sales, selling
and general 249 240 249 182 1,507 1,614
Depletion,
depreciation and
amortization 278 262 4 4 6 5
Interest - net - - - - - -
Foreign exchange - - - - - -
-------------------------------------------------------------------------
527 502 253 186 1,513 1,619
-------------------------------------------------------------------------
Earnings (loss)
before income taxes 449 298 140 27 53 50
Current income taxes 69 29 (2) - (4) 14
Future income taxes 73 65 45 8 24 2
-------------------------------------------------------------------------
Net earnings (loss) $ 307 $ 204 $ 97 $ 19 $ 33 $ 34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital expenditures -
Three months ended
June 30 $ 536 $ 421 $ 30 $ 18 $ 7 $ 4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended
June 30(1)
Sales and operating
revenues, net of
royalties $ 1,864 $ 1,581 $ 746 $ 459 $ 2,952 $ 3,107
Costs and expenses
Operating, cost of
sales, selling
and general 489 465 444 394 2,794 2,992
Depletion,
depreciation and
amortization 551 516 9 9 11 10
Interest - net - - - - - -
Foreign exchange - - - - - -
-------------------------------------------------------------------------
1,040 981 453 403 2,805 3,002
-------------------------------------------------------------------------
Earnings (loss)
before income taxes 824 600 293 56 147 105
Current income taxes 122 63 9 - (11) 26
Future income taxes 156 97 80 14 63 8
-------------------------------------------------------------------------
Net earnings (loss) $ 546 $ 440 $ 204 $ 42 $ 95 $ 71
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital employed -
As at June 30 $ 7,878 $ 7,056 $ 490 $ 484 $ 570 $ 415
Capital expenditures -
Six months ended
June 30 $ 1,198 $ 984 $ 47 $ 26 $ 13 $ 7
Total assets -
As at June 30 $11,575 $10,305 $ 751 $ 688 $ 871 $ 737
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

2005 2004 2005 2004 2005 2004
-------------------------------------------------------------------------
Three months ended
June 30(1)
Sales and operating
revenues, net of
royalties $ 560 $ 457 $(1,002) $ (929) $ 2,493 $ 2,210
Costs and expenses
Operating, cost of
sales, selling
and general 518 414 (930) (886) 1,593 1,564
Depletion,
depreciation and
amortization 11 9 5 8 304 288
Interest - net - - 6 17 6 17
Foreign exchange - - 20 12 20 12
-------------------------------------------------------------------------
529 423 (899) (849) 1,923 1,881
-------------------------------------------------------------------------
Earnings (loss)
before income taxes 31 34 (103) (80) 570 329
Current income taxes (1) 5 13 11 75 59
Future income taxes 12 8 (53) (42) 101 41
-------------------------------------------------------------------------
Net earnings (loss) $ 20 $ 21 $ (63) $ (49) $ 394 $ 229
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital expenditures
Three months ended
June 30 $ 43 $ 14 $ 4 $ 6 $ 620 $ 463
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended
June 30(1)
Sales and operating
revenues, net of
royalties $ 997 $ 817 $(1,865) $(1,733) $ 4,694 $ 4,231
Costs and expenses
Operating, cost of
sales, selling
and general 917 757 (1,740) (1,665) 2,904 2,943
Depletion,
depreciation and
amortization 20 18 11 18 602 571
Interest - net - - 16 34 16 34
Foreign exchange - - 27 24 27 24
-------------------------------------------------------------------------
937 775 (1,686) (1,589) 3,549 3,572
-------------------------------------------------------------------------
Earnings (loss)
before income taxes 60 42 (179) (144) 1,145 659
Current income taxes (2) 7 24 23 142 119
Future income taxes 24 9 (98) (72) 225 56
-------------------------------------------------------------------------
Net earnings (loss) $ 38 $ 26 $ (105) $ (95) $ 778 $ 484
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital employed -
As at June 30 $ 399 $ 356 $ (234) $ (77) $ 9,103 $ 8,234
Capital expenditures -
Six months ended
June 30 $ 48 $ 24 $ 8 $ 11 $ 1,314 $ 1,052
Total assets -
As at June 30 $ 727 $ 617 $ 134 $ 195 $14,058 $12,542
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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:

-------------------------------------------------------------------------
Six months ended
June 30
2005 2004
-------------------------------------------------------------------------
Asset retirement obligations at beginning of
period $ 509 $ 432
Liabilities incurred 8 11
Liabilities disposed (7) -
Liabilities settled (14) (13)
Accretion 17 14
-------------------------------------------------------------------------
Asset retirement obligations at end of period $ 513 $ 444
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At June 30, 2005, the estimated total undiscounted inflation adjusted
amount required to settle the asset retirement obligations was
$2.9 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

-------------------------------------------------------------------------
June 30 Dec. 31 June 30 Dec. 31
Maturity 2005 2004 2005 2004
-------------------------------------------------------------------------
Cdn $ Amount U.S. $ Amount
Long-term debt
Syndicated credit facility 2008 $ 100 $ 70 $ - $ -
Bilateral credit
facilities 2006-8 90 40 - -
7.125% notes 2006 184 181 150 150
8.90% capital securities 2008 276 271 225 225
6.25% notes 2012 490 481 400 400
7.55% debentures 2016 245 241 200 200
6.15% notes 2019 368 361 300 300
Private placement notes 2005 18 18 15 15
8.45% senior secured
bonds 2005-12 121 140 99 117
Medium-term notes 2007-9 300 300 - -
-------------------------------------------------------------------------
Total long-term debt 2,192 2,103 $ 1,389 $ 1,407
------------------
------------------
Amount due within one year (53) (56)
-------------------------------------------------------
$ 2,139 $ 2,047
-------------------------------------------------------
-------------------------------------------------------

Interest - net consisted of:
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Long-term debt $ 36 $ 35 $ 70 $ 68
Short-term debt 1 1 2 2
-------------------------------------------------------------------------
37 36 72 70
Amount capitalized (31) (18) (55) (35)
-------------------------------------------------------------------------
6 18 17 35
Interest income - (1) (1) (1)
-------------------------------------------------------------------------
$ 6 $ 17 $ 16 $ 34
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Foreign exchange consisted of:
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Loss on translation of U.S. dollar
denominated long-term debt $ 22 $ 25 $ 31 $ 46
Cross currency swaps (4) (9) (6) (14)
Other (gains) losses 2 (4) 2 (8)
-------------------------------------------------------------------------
$ 20 $ 12 $ 27 $ 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 - Six months ended June 30, 2004

As As
Reported Change Restated
-------------------------------------------------------------------------
Interest - net $ 20 $ 14 $ 34
Foreign exchange 13 11 24
Future income taxes 63 (7) 56
Net earnings 502 (18) 484
-------------------------------------------------------------------------
-------------------------------------------------------------------------


 


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.

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:
-------------------------------------------------------------------------
Six months ended June 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 246,341 9 1,399,967 22
-------------------------------------------------------------------------
Balance at June 30 423,982,755 $ 3,515 423,575,709 $ 3,502
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Stock Options

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

-------------------------------------------------------------------------
Six months ended June 30
2005 2004
-------------------------------------------------------------------------
Number Weighted Number Weighted
of Average of Average
Options Exercise Options Exercise
(thousands) Prices (thousands) Prices
-------------------------------------------------------------------------
Outstanding, beginning of period 9,964 $ 22.61 4,597 $ 13.88
Granted 175 $ 35.29 7,988 $ 24.90
Exercised for common shares (217) $ 16.27 (1,189) $ 13.11
Surrendered for cash (1,646) $ 18.10 (167) $ 13.21
Forfeited (281) $ 24.46 (59) $ 20.46
-------------------------------------------------------------------------
Outstanding, June 30 7,995 $ 23.92 11,170 $ 21.82
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable at June 30 2,281 $ 21.98 2,497 $ 13.10
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
June 30, 2005
Outstanding Options Options Exercisable
-------------------------------------------------------------------------
Weighted
Number Weighted Average Number Weighted
of Average Contractual of Average
Range of Options Exercise Life Options Exercise
Exercise Price (thousands) Prices (years) (thousands) Prices
-------------------------------------------------------------------------
$12.31 - $14.99 485 $ 13.27 1 414 $ 13.05
$15.00 - $23.99 361 $ 18.74 3 111 $ 17.16
$24.00 - $24.99 6,692 $ 24.38 4 1,748 $ 24.38
$25.00 - $36.10 457 $ 32.58 4 8 $ 27.21
-------------------------------------------------------------------------
7,995 $ 23.92 4 2,281 $ 21.98
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Note 8 Earnings per Common Share
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Net earnings and net earnings
available to common shareholders $ 394 $ 229 $ 778 $ 484
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average number of
common shares outstanding
Basic (millions) 423.9 423.4 423.8 423.1
Effect of dilutive stock options and
warrants - 1.8 - 1.8
-------------------------------------------------------------------------
Weighted average number of
common shares outstanding
Diluted (millions) 423.9 425.2 423.8 424.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per share
Basic $ 0.93 $ 0.54 $ 1.84 $ 1.14
Diluted $ 0.93 $ 0.54 $ 1.84 $ 1.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2005 2004 2005 2004
-------------------------------------------------------------------------
a) Change in non-cash working capital
was as follows:
Decrease (increase) in non-cash
working capital
Accounts receivable $ 25 $ 74 $ (20) $ 49
Inventories (86) (54) (140) (72)
Prepaid expenses (7) (22) (18) (16)
Accounts payable and accrued
liabilities 39 (196) (174) (35)
-------------------------------------------------------------------------
Change in non-cash working capital (29) (198) (352) (74)
Relating to:
Financing activities 3 4 (220) 10
Investing activities 16 (92) (2) (105)
-------------------------------------------------------------------------
Operating activities $ (48) $ (110) $ (130) $ 21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
b) Other cash flow information:
Cash taxes paid $ 76 $ 101 $ 159 $ 152
Cash interest paid $ 43 $ 43 $ 73 $ 73
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Note 10 Employee Future Benefits

Total benefit costs recognized were as follows:
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2005 2004 2005 2004
-------------------------------------------------------------------------
Employer current service cost $ 1 $ 5 $ 2 $ 8
Interest cost 3 2 5 4
Expected return on plan assets (2) (2) (4) (4)
Amortization of net actuarial losses - - 1 1
-------------------------------------------------------------------------
$ 2 $ 5 $ 4 $ 9
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Note 11 Financial Instruments and Risk Management

Unrecognized gains (losses) on derivative instruments were as follows:
-------------------------------------------------------------------------
June 30 Dec. 31
2005 2004
-------------------------------------------------------------------------
Commodity price risk management
Natural gas $ (7) $ (9)
Power consumption 1 (1)
Interest rate risk management
Interest rate swaps 33 52
Foreign currency risk management
Foreign exchange contracts (33) (30)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Commodity Price Risk Management

- Natural Gas Production

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

day at NYMEX for July to December 2005 at an average price of

U.S. $1.92 per mcf. During the first six months of 2005, the impact

was a loss of $5 million.

- Power Consumption

At June 30, 2005, the Company had hedged power consumption of 99,360

MWh from July to December 2005 at an average fixed price of $49.94 per

MWh. The impact of the hedge program during the first six months of

2005 was a loss of less than $1 million.

- Natural Gas Contracts

At June 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 19,204 $ 12
Physical sale contracts (19,204) $ (10)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 six months of 2005, the Company realized a gain of

$9 million from interest rate risk management activities.

Foreign Currency Risk Management

During the first six months of 2005, the Company realized a $7 million

gain from all foreign currency risk management activities.

During the first six 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 June 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 from

Operations Earnings from operations plus non-cash charges 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, July 20, 2005 at 4:15 p.m. Eastern time to discuss Husky's second quarter results which will be released after market close on July 19, 2005. To participate, please dial 1-800-404-8949 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 21246538. The PostView will be available until Saturday, August 20, 2005.

Media are invited to participate in the call on a listen-only basis by dialing 1-800-291-5032 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