NEWS RELEASE TRANSMITTED BY Marketwire



FOR: HUSKY ENERGY INC.

TSX SYMBOL:
 HSE

Husky Energy announces 2006 second quarter results

Jul 19, 2006 - 11:59 ET

CALGARY--(CCNMatthews - July 19) - Husky Energy Inc. reported net earnings of $978 million or $2.31 per share (diluted) in the second quarter of 2006, up 148 percent from $394 million or $0.93 per share (diluted) in the second quarter of 2005. Net earnings for the second quarter of 2006 included tax benefits due to tax rate reductions of $328 million or $0.77 per share (diluted). Cash flow from operations in the second quarter was $1.1 billion or $2.60 per share (diluted), a 33 percent increase compared with $828 million or $1.95 per share (diluted) for the same period in 2005. Sales and operating revenues, net of royalties, were $3.0 billion in the second quarter of 2006, compared with $2.4 billion in the second quarter of 2005.

"We are pleased with Husky's exploration success and White Rose project execution," said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. "With a solid balance sheet and cash flow, Husky will continue to benefit from its integrated business strategy and quality asset base in this strong price environment."

Production in the second quarter of 2006 was 344,000 barrels of oil equivalent per day, compared with 308,900 barrels of oil equivalent per day in the second quarter of 2005. Total crude oil and natural gas liquids production was 231,800 barrels per day, compared with 194,000 barrels per day in the second quarter of 2005. Natural gas production was 672.8 million cubic feet per day, compared with 689.3 million cubic feet per day in the second quarter of 2005.

Husky's Tucker Oil Sands Project at Cold Lake, Alberta is on schedule and on budget. Construction of the facility which will use steam-assisted drainage technology (SAGD) is substantially complete. First steam is planned in August of 2006 with first oil targeted for the fourth quarter. During the production cycle, Husky expects to produce approximately 350 million barrels of bitumen with peak production of more than 30,000 barrels per day.

At the Sunrise Oil Sands Project, work is progressing on the front-end engineering design and Husky is continuing its evaluation of alternatives for the downstream portion of the project.

Husky successfully acquired an additional 14,560 acres of oil sands lease adjacent to its Saleski property. The acquisition increases Husky's land holdings in Saleski from 178,560 acres to 193,120 acres and the potential resources in Saleski to approximately 20.8 billion barrels of original bitumen in place.

At the White Rose oil field, the fifth production well began producing oil at the end of June and has increased reservoir production capacity to approximately 110,000 barrels of oil per day. A sixth production well is scheduled to come on stream at the end of 2006 and will further increase reservoir production capacity to 125,000 barrels of oil per day.

In June, Husky made a hydrocarbon discovery at the White Rose O-28 delineation well in the western section of the White Rose oil field. Based on the Company's current interpretation, the discovery at the O-28 well could contain an additional potential recoverable resource of 40 to 90 million barrels of oil. The proved plus probable reserves in the White Rose field were estimated at 240 million barrels (174 million barrels Husky's share).

In the South China Sea, Husky made a significant hydrocarbon discovery on the Liwan 3-1-1, Block 29/26. In accordance with the Company's current interpretation of the 2-D seismic and drilling results, the discovery could contain a potential recoverable resource of four to six trillion cubic feet of natural gas. As such, it would be one of the largest natural gas discoveries offshore China.

Offshore Indonesia, Husky was awarded the East Bawean II Block in the East Java Sea, increasing its holdings in the region by 4,255 square kilometres. The East Bawean II Block is located in the North East Java Basin approximately 200 kilometres north of the Company's BD gas field in the Madura Strait, offshore Indonesia. The acquisition of the East Bawean ll Block increases Husky's total holdings in Indonesia to 7,049 square kilometres or approximately 1.8 million acres. Husky holds a 100 percent interest in the Madura Strait and East Bawean II blocks.

Construction of Husky's Lloydminster Ethanol Plant in Lloydminster, Saskatchewan is essentially complete and commissioning activities have commenced with full production expected in the third quarter of 2006. In Minnedosa, Manitoba construction of the new ethanol plant is progressing on schedule with start-up planned in the third quarter of 2007.

For the first six months of 2006, Husky's net earnings were $1.5 billion or $3.54 per share (diluted), compared with $778 million or $1.84 per share (diluted) for the same period in 2005, an increase of 93 percent. Cash flow from operations for the first six months of 2006 was $2.1 billion or $4.88 per share (diluted), compared with $1.6 billion or $3.88 per share (diluted) for the same period in 2005.

Production in the first six months of 2006 was 348,700 barrels of oil equivalent per day, compared with 314,200 barrels of oil equivalent per day in the same period in 2005. Total crude oil and natural gas liquids production was 235,500 barrels per day, compared with 200,400 barrels per day during the first six months of 2005. Natural gas production was 679.0 million cubic feet per day, compared with 682.8 million cubic feet per day in the first six months of 2005.


MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") July 19, 2006


This MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes. Readers are also encouraged to refer to Husky's MD&A and Consolidated Financial Statements and 2005 Annual Information Form filed in 2006 with Canadian regulatory agencies and Form 40-F filed with the Securities and Exchange Commission ("SEC"), the U.S. regulatory agency. These documents are available at www.sedar.com and at www.sec.gov.

Forward-looking Statements

This MD&A contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. The reader is advised to refer to Section 14.0 "Forward-looking Statements or Information" for additional information.

Use of Pronouns and Other Terms Denoting Husky

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

Standard Comparisons in this Document

Unless otherwise indicated, the discussions in this MD&A with respect to results for the three months ended June 30, 2006 are compared with results for the three months ended June 30, 2005 and results for the six months ended June 30, 2006 are compared with results for the six months ended June 30, 2005. Discussions with respect to Husky's financial position as at June 30, 2006 are compared with its financial position at December 31, 2005.

Additional Reader Guidance


- The Consolidated Financial Statements and comparative financial

information included in this Interim Report have been prepared in

accordance with Canadian generally accepted accounting principles

("GAAP").

- All dollar amounts are in millions of Canadian dollars, unless

otherwise indicated.

- Unless otherwise indicated, all production volumes quoted are gross,

which represent the Company's working interest share before royalties.

- Prices quoted include or exclude the effect of hedging as indicated.


1.0 SUMMARY OF QUARTERLY RESULTS

Husky's net earnings for the second quarter of 2006 were $978 million, up $584 million compared with the second quarter of 2005. Included in net earnings during the second quarter of 2006 are tax benefits amounting to $328 million. These benefits relate to tax rate reductions by the governments of Canada, Alberta and Saskatchewan that were all substantively enacted during the quarter.

The White Rose oil field, which commenced operations in the fourth quarter of 2005, contributed significantly to the positive variance in the second quarter of 2006 as did higher crude oil prices. Unrealized gains from foreign currency translation and lower stock-based compensation also contributed to the higher net earnings in the second quarter. The positive variance in the second quarter was partially offset by higher cash taxes, lower natural gas prices, lower production volumes from the Terra Nova and Wenchang oil fields and lower upgrading differentials.



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

Financial Summary Three months ended

(millions of dollars, except June 30 March 31 Dec. 31 Sept. 30

per share amounts and ratios) 2006 2006 2005 2005

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

Sales and operating revenues,

net of royalties $ 3,040 $ 3,104 $ 3,207 $ 2,594

Segmented earnings

Upstream $ 822 $ 412 $ 533 $ 445

Midstream 140 150 135 61

Refined Products 52 16 17 27

Corporate and eliminations (36) (54) (16) 23

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

Net earnings $ 978 $ 524 $ 669 $ 556

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

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

Per share - Basic $ 2.31 $ 1.24 $ 1.58 $ 1.31

- Diluted 2.31 1.24 1.58 1.31

Cash flow from operations 1,103 967 1,197 944

Per share - Basic 2.60 2.28 2.82 2.23

- Diluted 2.60 2.28 2.82 2.23

Dividends per common share 0.25 0.25 0.25 0.14

Special dividend per common share - - 1.00 -

Total assets 16,405 15,859 15,797 14,712

Total long-term debt including

current portion 1,722 1,838 1,886 1,896

Return on equity(1) (percent) 34.8 29.6 29.2 22.9

Return on average capital

employed(1) (percent) 28.2 23.2 22.8 17.9

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

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

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

Financial Summary 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 $ 2,350 $ 2,094 $ 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

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

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

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 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(1) (percent) 20.2 18.3 17.0 17.7

Return on average capital

employed(1) (percent) 15.3 13.9 13.0 13.4

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

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

(1) Calculated for the twelve months ended for the periods shown.

 


Western Canada crude oil production for the second quarter of 2006 remained at the same level as compared with the first quarter of 2006. Natural gas sales volume decreased by 13 mmcf/day from the first quarter of 2006 to the second quarter of 2006. This decrease was primarily due to a higher number of plant turnarounds and repairs, pipeline and sales restrictions and tie-in delays.

In the second quarter of 2006, we drilled 45 gross (26 net) exploration wells in the Western Canada Sedimentary Basin ("WCSB") resulting in 8 gross (8 net) oil wells and 34 gross (16 net) gas wells. In the natural gas prone deep basin, foothills and northern plains areas we drilled 9 gross (5.5 net) wells resulting in 8 gross (5.1 net) natural gas wells. At June 30, 2006, 6 gross (3.5 net) wells were drilling or suspended in these regions.

Following successful completion of a fourth production well in May 2006, Husky achieved 100 mbbls/day (72.5 mbbls/day Husky's share) of production from the White Rose field. The field's production rates were kept at an average rate of 85 mbbls/day (62 mbbls/day Husky's share) until the fifth production well came on stream at the end of the quarter. The addition of the fifth production well has increased the field's productive capacity by 25 mbbls/day to 110 mbbls/day (80 mbbls/day Husky's share).

Terra Nova oil field production was 6.5 mbbls/day lower in the second quarter of 2006 compared with the first quarter of 2006 as a result of mechanical failure of components in the gearbox of both of the vessel's main power generators. The FPSO subsequently suspended production operations in early May and began preparing to disconnect from the riser buoy prior to disembarking for dry dock and commencement of the 2006 turnaround. Production operations are expected to resume in late September 2006.

Wenchang oil field production declined by 1.4 mbbls/day in the second quarter of 2006 compared with the first quarter of 2006 reflecting natural reservoir decline.



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

Daily Gross Production Three months ended

June 30 March 31 Dec. 31 Sept. 30 June 30

2006 2006 2005 2005 2005

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

Crude oil and NGL

(mbbls/day)

Western Canada

Light crude oil & NGL 29.8 31.3 30.1 31.8 31.7

Medium crude oil 28.5 29.4 31.0 30.3 30.6

Heavy crude oil 105.6 109.5 109.5 103.3 100.9

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

163.9 170.2 170.6 165.4 163.2

East Coast Canada

White Rose -

light crude oil 53.0 46.4 19.0 - -

Terra Nova -

light crude oil 2.8 9.3 12.2 10.2 13.5

China

Wenchang -

light crude oil 12.1 13.5 14.1 14.4 17.3

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

231.8 239.4 215.9 190.0 194.0

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

Natural gas (mmcf/day) 672.8 685.4 675.3 679.2 689.3

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

Total (mboe/day) 344.0 353.6 328.5 303.2 308.9

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

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

 


Production

During the first six months of 2006 White Rose was further developed and Husky's share averaged 49.7 mbbls/day. This increase in production of light crude was partially offset because the Terra Nova oil field was shut-in to prepare to move the FPSO to dry dock.

2.0 STRATEGIC PLANS AND CAPABILITIES

We have several major projects that are at various stages of development and, upon completion, are expected to result in sustained growth in enterprise value.

Upstream


- East Coast Exploration and Development

- Oil Sands Development

- Mackenzie River Valley Exploration

- China and Indonesia Exploration and Development

Midstream

- Upgrader Expansion

Refined Products

- Refinery Modifications

- Ethanol Plant Construction



2.1 UPSTREAM

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

Gross Production Six months Six months

ended Full Year ended Year ended

June 30 Forecast June 30 Dec. 31

2006 2006 2005 2005

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

Crude oil & NGL (mbbls/day)

Light crude oil & NGL 99.0 103 - 116 63.3 64.6

Medium crude oil 29.0 29 - 32 31.5 31.1

Heavy crude oil 107.5 115 - 120 105.6 106.0

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

235.5 247 - 268 200.4 201.7

Natural gas (mmcf/day) 679.0 680 - 730 682.8 680.0

Total barrels of

oil equivalent (mboe/day) 348.7 360 - 390 314.2 315.0

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

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

 


Our foundation assets in the WCSB currently provide the majority of the funding required to finance our strategic plans including our strategy with respect to the optimal exploitation of the significant remaining resources in the WCSB.

These exploitation activities involve increased drilling of infill and step-out wells, the installation of various types of enhanced recovery techniques, including thermal recovery of heavy oil and emerging technologies such as alkaline surfactant polymer floods. In addition, increased production from coalbed methane deposits is augmenting natural gas production.

We also plan to maintain exploration activities focused on natural gas prospects in the deep basin and the foothills and northern regions of Alberta and British Columbia where natural gas reservoirs are deeper and have been larger and prolific.

White Rose Oil Field

Following successful completion of a fourth production well, the White Rose oil field achieved 100 mbbls/day (72.5 mbbls/day Husky's share) of total production. Production rates were kept at an average rate of 85 mbbls/day (62 mbbls/day Husky's share) until the fifth production well came on production at the end of the quarter. The addition of the fifth producer has increased reservoir productive capacity to 110 mbbls/day total (80 mbbls/day Husky's share). A sixth production well, which is scheduled to come on stream at the end of 2006, will further increase reservoir productive capacity to 125 mbbls/day total (91 mbbls/day Husky's share).

Actual production will depend on the FPSO throughput capacity limitation, which will be evaluated during the third quarter of 2006.

On June 20, 2006 we announced a hydrocarbon discovery at the White Rose O-28 delineation well in the western section of the White Rose oil field. The O-28 well was drilled on Significant Discovery Licence 1024 to depths of up to 3,342 metres. The well revealed a 280 metre oil column in a multi-layered reservoir in the Ben Nevis Avalon formation. An additional side-track well is being drilled and logged to provide further information about reservoir quality, continuity and hydrocarbon contacts. Based on our current interpretation of the 3-D seismic and the O-28 well results, the discovery could contain a potential recoverable gross resource of 40 to 90 million barrels of oil. Our share of this potential recoverable resource will augment our proved and probable reserves which were approximately 173 million barrels of oil at the end of 2005. Husky plans to tie this western extension of the oil field back to the SeaRose FPSO.

East Coast Canada Exploration

In the West Bonne Bay region of the Jeanne d'Arc Basin on Significant Discovery Licence ("SDL") 1040, exploration drilling began during the second quarter. West Bonne Bay is located just to the northeast of the Terra Nova oil field. Under the terms of a farm-in agreement with Norsk Hydro, who currently hold a 90 percent interest, we will earn a 25 percent interest in SDL 1040 and an additional 7.5 percent in the North Ben Nevis SDL 1008 where we hold a 65.6 percent interest.

A seismic vessel has been contracted to finish the 3-D seismic program in the Jeanne d'Arc Basin that was halted last fall due to inclement weather. This program, along with additional 3-D seismic shooting in the vicinity of the White Rose and Terra Nova oil fields, will commence early July.

Tucker Oil Sands Project

At the Tucker Oil Sands project, construction is substantially complete and is on schedule to begin steam injection in August of 2006. Drilling and well completions are 100 percent complete. Operational readiness has been achieved with fully trained staff on-site. The project remains on schedule to produce first oil in the fourth quarter of 2006.

Sunrise Oil Sands Project

During the second quarter of 2006 progress at Sunrise included commencement of front-end engineering design, which is targeted to be complete by the third quarter of 2007. Various facility configuration studies are ongoing and collaborative work continued with various industry participants on regional infrastructure, including an access highway and airport. Modeling of the source water is ongoing and we plan to drill five source water evaluation wells prior to year-end. An additional 10 source water evaluation wells and 29 stratigraphic test wells are planned for the winter drilling season. Pad locations and trajectories for phase one horizontal wells are currently being determined.

Caribou and Saleski

During the second quarter we began evaluating core from stratigraphic test well programs completed at Saleski and Caribou during the winter and spring. Development planning is underway including water source and disposal studies for both projects and determination of the appropriate bitumen recovery process for Saleski.

Husky acquired one oil sands lease in the Saleski area of northern Alberta at the July 12, 2006 Alberta land sale (Lease L0402 located in Ranges 20 & 21, Township 87 W4M). The lease totals 14,560 acres and is estimated to contain 1.3 billion barrels of bitumen in place within the Grosmont and Nisku carbonate. The acquired lands are adjacent to Husky's existing holdings in the Saleski area and resulted in an increase in Husky's total land holdings from 178,560 acres to 193,120 acres (or from 279 sections to 302 sections) and increased Husky's bitumen in place estimate for Saleski from 19.5 billion barrels to 20.8 billion barrels.

Northwest Territories Exploration

In May 2006 Husky announced a natural gas discovery at the Stewart D-57 well. The D-57 discovery was drilled on Tulita District Land Corporation Freehold Block M-38. The well was drilled to a depth of 3,147 metres, cased to total depth and suspended. On open-hole testing, natural gas flowed from two Cretaceous intervals to the surface at a combined rate of 5 million cubic feet per day, confirming a hydrocarbon bearing column of at least 50 metres. This is the first successful Cretaceous hydrocarbon discovery in the Central Mackenzie region.

Husky also concluded its winter drilling program in the Summit Creek area approximately 26 kilometres northwest of the Stewart D-57 discovery. The program consisted of the Summit Creek K-44 well, an appraisal and deeper pool exploration well adjacent to the Summit Creek B-44 discovery well. Summit Creek K-44 was drilled on Exploration License ("EL") 397, 1.4 kilometres northeast of the B-44 discovery well. The well was drilled to a depth of 3,130 metres, cased to total depth and suspended. The results are being evaluated.

During the second quarter of 2006 we were awarded EL 441 (Block CMV-6), flanking the eastern boundary of EL 397. The licence area contains extensions of several plays from EL 397, including the Cretaceous natural gas play recently confirmed by our Stewart D-57 well. The licence requires a work commitment of $10.5 million over the next four years. We now hold interests in approximately 3,275 square kilometers in the Central Mackenzie Valley area.

Approximately 200 kilometres of seismic is being shot to better identify prospects for this winter's drilling program on EL 397.

China Exploration

On June 14, 2006 we announced a significant hydrocarbon discovery at Liwan 3-1-1, in the South China Sea.

Liwan 3-1-1 was drilled in a water depth of 1,500 metres on Block 29/26 in the Pearl River Mouth Basin and is the first deep water discovery made offshore China. The block is located approximately 250 kilometres south of Hong Kong. The well was drilled on existing 2-D seismic data to a total depth of 3,843 metres on a large structure with 60 square kilometres of closure and encountered 56 metres of net gas pay on logs over two zones. The 2-D seismic interpretation prior to drilling the well indicated a direct hydrocarbon response at the Liwan 3-1-1 location, which is present over a majority of the 60 square kilometre closure currently mapped. The porosity encountered in the pay zones averaged approximately 20 percent, based on petrophysical interpretation.

The Liwan 3-1-1 well will be sidetracked for further evaluation of the pay zone and we are currently planning a 3-D seismic survey for the near future to assess a number of similar structures which have been identified on 2-D seismic data. Further drilling on the block will follow after the evaluation of the 3-D data. Based on our current interpretation of the 2-D seismic and the Liwan 3-1-1 well results, the discovery could contain a potential recoverable resource of four to six trillion cubic feet of natural gas. China National Offshore Oil Corporation has the right to participate in the development of any discoveries up to a 51 percent working interest.

Also, in China, we are seeking tenders on a rig to drill an exploration well on Block 04/35 in the East China Sea. The well is planned for late 2006.

Indonesia Natural Gas Development

At Madura, Indonesia, the conceptual design for the BD natural gas field development has been submitted to the Indonesian regulatory agency, BPMIGAS, for consideration. Negotiations on a gas sales agreement and extension of the production sharing agreement continued through the second quarter of 2006. Completion of this project is contingent on the timing of government approval.

During the second quarter of 2006 we were awarded the Bawean II Block. This block is located in the same basin as the Madura BD natural gas field and contains similar prospects. We have committed to shoot 1,400 square kilometres of seismic and drill two wells in the first exploration phase.

2.2 MIDSTREAM

We are currently implementing various pipeline and terminal expansion initiatives coincident with the increasing level of upstream activity, particularly in the heavy oil/bitumen corridor and south to the main pipeline shipping systems at Hardisty, Alberta.

Lloydminster Upgrader

At the Lloydminster Upgrader the front-end engineering design with respect to plans to expand throughput capacity from approximately 80 to 150 mbbls/day of synthetic crude oil and diluent commenced. The plans also include modifications to the Upgrader that will permit processing of a 67 percent Cold Lake bitumen feedstock mix. During the second quarter of 2006 negotiations were completed and agreements executed with various process licensors. Front-end engineering design work is expected to be completed by the third quarter of 2007. Subject to project sanction, completion of the expansion could be achieved by the end of 2010.

2.3 Refined Products

Prince George Refinery Low Sulphur Upgrade

At the Prince George refinery the second phase of modifications to produce low sulphur diesel fuel is complete. The refinery now produces both low sulphur gasoline and ultra low sulphur diesel consistent with marketplace requirements. The refinery's design rate capacity is now 12 mbbls/day of low sulphur fuel, a 20 percent increase based on previously stated capacity.

Lloydminster and Minnedosa Ethanol Plants

To meet the increasing demand for ethanol blended gasoline, which currently ranges from 10 percent E-10 to 85 percent E-85 ethanol, we are currently constructing two motor fuel grade ethanol plants. One plant is located adjacent to our Upgrader at Lloydminster, Saskatchewan and the other at Minnedosa, Manitoba, the site of our existing ethanol plant. Each plant will have the same throughput capacity, producing 130 million litres of ethanol per year.

Construction of the Lloydminster plant is essentially complete and is in the final stages of commissioning.

Construction of the Minnedosa plant is approximately 20 percent complete. The plant is expected to be ready for start-up during the third quarter of 2007.

3.0 BUSINESS ENVIRONMENT

Husky's financial results are significantly influenced by its business environment. Average quarterly market prices were:



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

Average Benchmark Prices Three months ended

and U.S. Exchange Rate June 30 March 31 Dec. 31 Sept. 30 June 30

2006 2006 2005 2005 2005

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

WTI crude oil(1)

(U.S. $/bbl) 70.70 63.48 60.02 63.10 53.17

Brent crude oil(2)

(U.S. $/bbl) 69.62 61.75 56.90 61.54 51.58

Canadian par light

crude 0.3% sulphur

($/bbl) 78.97 69.40 71.65 77.04 66.43

Lloyd heavy crude oil

@ Lloydminster

($/bbl) 48.65 26.25 29.60 44.13 27.95

NYMEX natural gas(1)

(U.S. $/mmbtu) 6.79 8.98 12.97 8.49 6.73

NIT natural gas ($/GJ) 5.95 8.79 11.08 7.75 6.99

WTI/Lloyd crude blend

differential

(U.S. $/bbl) 17.99 29.20 24.24 18.90 21.27

U.S./Canadian dollar

exchange rate (U.S. $) 0.891 0.866 0.852 0.833 0.804

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

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

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

the next month.

(2) Dated Brent prices which are dated less than 15 days prior to loading

for delivery.

 


3.1 COMMODITY PRICE RISK

Our earnings depend largely on the profitability of our upstream business segment which is most significantly affected by fluctuations in oil and gas prices. Commodity prices have been, and are expected to continue to be, volatile due to a number of factors beyond our control. The effect of any single risk is not determinable with certainty as these are interdependent and our future course of action depends upon our assessment of all information available at any given time.

Crude Oil

WTI and Husky Average Crude Oil Prices

WTI, the benchmark crude price, has escalated throughout the period reported with some fluctuations, closely followed by Husky's light crude prices.

The prices received for our crude oil and NGL are related to the price of crude oil in world markets. Prices for heavy crude oil and other lesser quality crudes trade at a discount or differential to light crude oil due to the additional processing costs.

Following the typical seasonal lull in crude oil prices in the fourth quarter of 2005 prices recovered to and then exceeded the U.S. $70.00/bbl level ending the second quarter with a spot price of U.S. $73.94/bbl. The environment for crude oil prices, in the near-term, remains unchanged as a result of continued geopolitical strife and unpredictable weather patterns.

Natural Gas

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

Both U.S. and Canadian benchmark natural gas prices have decreased in 2006. Husky's natural gas prices, which are dominated by floating prices, followed suit.

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.

NYMEX natural gas prices peaked at the end of 2005, primarily as a result of hurricane related shut-in production, after which mild winter weather, high gas storage levels and mandatory draw downs caused prices to decline rapidly through the first quarter of 2006. Prices during the second quarter of 2006 fluctuated in the range of U.S. $6.00/mmbtu and U.S. $7.50/mmbtu and ended the quarter at U.S. $5.89/mmbtu for July deliveries.

Other Business Environment Risks

Please refer to our 2005 MD&A for a discussion about other business environment risks.

3.2 SENSITIVITY ANALYSIS

The following table indicates the relative annual 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 2006. 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

2006

Second

Quarter

Average Increase

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



Upstream and Midstream

WTI benchmark crude oil price 70.70 U.S. $1.00/bbl

NYMEX benchmark natural gas price(1) 6.79 U.S. $0.20/mmbtu

WTI/Lloyd crude blend differential(2) 17.99 U.S. $1.00/bbl

Exchange rate (U.S. $ per Cdn $)(3) 0.89 U.S. $0.01

Refined Products

Light oil margins 0.05 Cdn $0.005/litre

Asphalt margins 12.51 Cdn $1.00/bbl

Consolidated

Period end translation of U.S. $ debt

(U.S. $ per Cdn $) 0.90(4) U.S. $0.01

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

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

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



Effect on Pre-tax Effect on

Cash Flow Net Earnings

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

($ millions) ($/ ($ millions) ($/

share) share)

(5) (5)

Upstream and Midstream

WTI benchmark crude oil price 82 0.19 55 0.13

NYMEX benchmark natural gas price(1) 34 0.08 23 0.05

WTI/Lloyd crude blend differential(2) (29) (0.07) (19) (0.04)

Exchange rate (U.S. $ per Cdn $)(3) (68) (0.16) (46) (0.11)

Refined Products

Light oil margins 16 0.04 10 0.02

Asphalt margins 9 0.02 6 0.01

Consolidated

Period end translation of U.S. $ debt

(U.S. $ per Cdn $) 8 0.02

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

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

(1) Includes decrease in earnings related to natural gas consumption.

(2) Includes impact of upstream and upgrading operations only.

(3) Assumes no foreign exchange gains or losses on U.S. dollar

denominated long-term debt and other monetary items.

(4) U.S./Canadian dollar exchange rate at June 30, 2006.

(5) Based on June 30, 2006 common shares outstanding of 424.2 million.

 


4.0 RESULTS OF OPERATIONS

Quarterly Segmented Earnings

Husky's profitability is largely dependant on Upstream operations, partially supported by upgrading results during times when light/heavy crude oil differentials are wider.

4.1 UPSTREAM

Second Quarter

Upstream earnings were $515 million higher in the second quarter of 2006 than in the second quarter of 2005 as a result of the following factors:


- higher sales volume of light and heavy crude oil;

- higher light, medium and heavy crude oil prices; and

- lower income taxes resulting from rate reductions.

Partially offset by:

- lower sales volume of medium crude oil and natural gas;

- lower natural gas prices;

- higher unit operating costs; and

- higher unit depletion, depreciation and amortization.


Six Months

The factors that affected results for the second quarter were primarily responsible for variances in results for the six months ended June 30, 2006 except for natural gas prices, which were higher during the six month period in 2006 compared with the same period in 2005.



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

Upstream Earnings Summary Three months Six months

ended June 30 ended June 30

(millions of dollars) 2006 2005 2006 2005

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

Gross revenues $ 1,658 $ 1,154 $ 3,151 $ 2,194

Royalties 207 178 413 330

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

Net revenues 1,451 976 2,738 1,864

Operating and

administration expenses 308 249 619 489

Depletion, depreciation

and amortization 354 278 705 551

Income taxes (33) 142 180 278

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

Earnings $ 822 $ 307 $ 1,234 $ 546

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

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

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

Net Revenue Variance Analysis

Crude oil Natural

(millions of dollars) & NGL gas Other Total

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

Three months ended

June 30, 2005 $ 624 $ 332 $ 20 $ 976

Price changes 353 (49) - 304

Volume changes 205 (10) - 195

Royalties (60) 31 - (29)

Processing and sulphur - - 5 5

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

Three months ended

June 30, 2006 $ 1,122 $ 304 $ 25 $ 1,451

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

Six months ended

June 30, 2005 $ 1,197 $ 631 $ 36 $ 1,864

Price changes 490 75 - 565

Volume changes 384 (4) - 380

Royalties (84) - - (84)

Processing and sulphur - - 13 13

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

Six months ended

June 30, 2006 $ 1,987 $ 702 $ 49 $ 2,738

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

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

 


Unit Operating Costs

Unit operating costs were six percent higher in the second quarter of 2006 compared with the same period in 2005 due to higher costs for energy, labour, servicing natural gas compression, higher natural gas well count and production declines. The high level of industry activity has created increased demand for, and consequently, higher prices for oil field materials and services.

NETBACK AND UNIT OPERATING COST

Higher netbacks resulting from higher crude oil prices are only marginally offset by increases in operating costs.

Unit Depletion, Depreciation and Amortization

Unit depletion, depreciation and amortization expense increased 15 percent in the second quarter of 2006 compared with the same period in 2005. The increase was primarily due to net growth of the capital base in 2006 as a result of increased requirements for production maintenance capital for our properties in the WCSB, and the start-up of the White Rose oil field, which, since it is an offshore development, has a higher ratio of capital to reserves. In addition, the higher energy costs, as with operating costs, increased the cost of materials and services embedded in our capital costs.



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

Average Sales Prices Three months Six months

ended June 30 ended June 30

2006 2005 2006 2005

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

Crude Oil ($/bbl)

Light crude oil & NGL $ 73.74 $ 59.51 $ 70.35 $ 57.95

Medium crude oil 58.42 40.45 48.29 38.42

Heavy crude oil 48.12 27.95 26.73 25.13

Total average 60.18 40.09 52.54 37.59

Natural Gas ($/mcf)

Average 5.95 6.76 7.01 6.42

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

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

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

Effective Royalty Rates Three months Six months

Percentage of upstream ended June 30 ended June 30

sales revenues 2006 2005 2006 2005

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

Crude oil & NGL 12% 13% 11% 13%

Natural gas 15% 20% 18% 20%

Total 13% 16% 13% 15%

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

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

Upstream Revenue Mix Three months Six months

Percentage of upstream sales ended June 30 ended June 30

revenues, after royalties 2006 2005 2006 2005

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

Light crude oil & NGL 41% 31% 42% 31%

Medium crude oil 8% 10% 8% 10%

Heavy crude oil 28% 23% 23% 23%

Natural gas 23% 36% 27% 36%

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

100% 100% 100% 100%

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

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

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

Operating Netbacks

WCSB East Coast

Three months ended June 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 62.34 $ 57.50 $ 76.57 $ 58.11

Royalties 7.14 7.64 1.82 2.86

Operating costs 12.88 11.26 4.97 3.29

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

42.32 38.60 69.78 51.96

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

Medium Crude Oil (per boe)(1)

Sales Price 57.34 40.61 - -

Royalties 10.76 6.98 - -

Operating costs 11.52 10.05 - -

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

35.06 23.58 - -

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

Heavy Crude Oil (per boe)(1)

Sales Price 47.92 28.09 - -

Royalties 6.34 3.09 - -

Operating costs 10.28 9.48 - -

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

31.30 15.52 - -

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

Total Crude Oil (per boe)(1)

Sales Price 52.08 35.64 76.57 58.11

Royalties 7.28 4.65 1.82 2.86

Operating costs 10.95 9.90 4.97 3.29

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

33.85 21.09 69.78 51.96

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

Natural Gas (per mcfge)(2)

Sales Price 6.23 6.81 - -

Royalties 1.16 1.51 - -

Operating costs 1.09 1.00 - -

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

3.98 4.30 - -

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

Equivalent Unit (per boe)(1)

Sales Price 46.13 37.81 76.57 58.11

Royalties 7.15 6.49 1.82 2.86

Operating costs 9.17 8.26 4.97 3.29

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

$ 29.81 $ 23.06 $ 69.78 $ 51.96

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

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

International Total

Three months ended June 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 77.80 $ 66.11 $ 72.56 $ 60.20

Royalties 16.35 6.16 5.21 6.09

Operating costs 2.41 2.39 6.95 6.91

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

59.04 57.56 60.40 47.20

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

Medium Crude Oil (per boe)(1)

Sales Price - - 57.34 40.61

Royalties - - 10.76 6.98

Operating costs - - 11.52 10.05

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

- - 35.06 23.58

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

Heavy Crude Oil (per boe)(1)

Sales Price - - 47.92 28.09

Royalties - - 6.34 3.09

Operating costs - - 10.28 9.48

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

- - 31.30 15.52

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

Total Crude Oil (per boe)(1)

Sales Price 77.80 66.11 59.28 39.96

Royalties 16.35 6.16 6.44 4.66

Operating costs 2.41 2.39 9.07 8.79

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

59.04 57.56 43.77 26.51

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

Natural Gas (per mcfge)(2)

Sales Price - - 6.23 6.81

Royalties - - 1.16 1.51

Operating costs - - 1.09 1.00

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

- - 3.98 4.30

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

Equivalent Unit (per boe)(1)

Sales Price 77.80 66.11 52.19 40.29

Royalties 16.35 6.16 6.61 6.31

Operating costs 2.41 2.39 8.24 7.74

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

$ 59.04 $ 57.56 $ 37.34 $ 26.24

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

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

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

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

WCSB East Coast

Six months ended June 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 61.50 $ 53.92 $ 73.14 $ 59.42

Royalties 6.27 6.23 2.75 2.94

Operating costs 12.32 10.53 6.15 3.61

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

42.91 37.16 64.24 52.87

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

Medium Crude Oil (per boe)(1)

Sales Price 47.83 38.49 - -

Royalties 8.51 6.69 - -

Operating costs 12.02 10.30 - -

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

27.30 21.50 - -

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

Heavy Crude Oil (per boe)(1)

Sales Price 37.34 25.28 - -

Royalties 4.71 2.62 - -

Operating costs 10.76 9.35 - -

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

21.87 13.31 - -

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

Total Crude Oil (per boe)(1)

Sales Price 43.32 32.95 73.14 59.42

Royalties 5.66 4.06 2.75 2.94

Operating costs 11.25 9.75 6.15 3.61

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

26.41 19.14 64.24 52.87

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

Natural Gas (per mcfge)(2)

Sales Price 7.15 6.50 - -

Royalties 1.54 1.45 - -

Operating costs 1.04 0.97 - -

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

4.57 4.08 - -

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

Equivalent Unit (per boe)(1)

Sales Price 43.14 35.36 73.14 59.42

Royalties 7.09 5.91 2.75 2.94

Operating costs 9.24 8.19 6.15 3.61

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

$ 26.81 $ 21.26 $ 64.24 $ 52.87

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

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

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

International Total

Six months ended June 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 75.58 $ 62.42 $ 70.06 $ 57.61

Royalties 10.83 5.78 4.85 5.37

Operating costs 3.11 2.38 7.55 6.70

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

61.64 54.26 57.66 45.54

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

Medium Crude Oil (per boe)(1)

Sales Price - - 47.83 38.49

Royalties - - 8.51 6.69

Operating costs - - 12.02 10.30

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

- - 27.30 21.50

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

Heavy Crude Oil (per boe)(1)

Sales Price - - 37.34 25.28

Royalties - - 4.71 2.62

Operating costs - - 10.76 9.35

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

- - 21.87 13.31

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

Total Crude Oil (per boe)(1)

Sales Price 75.58 62.42 52.12 37.36

Royalties 10.83 5.78 5.25 4.13

Operating costs 3.11 2.38 9.60 8.69

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

61.64 54.26 37.27 24.54

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

Natural Gas (per mcfge)(2)

Sales Price - - 7.15 6.50

Royalties - - 1.54 1.45

Operating costs - - 1.04 0.97

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

- - 4.57 4.08

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

Equivalent Unit (per boe)(1)

Sales Price 75.58 62.42 49.14 37.94

Royalties 10.83 5.78 6.53 5.77

Operating costs 3.11 2.38 8.52 7.67

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

$ 61.64 $ 54.26 $ 34.09 $ 24.50

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

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

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

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

Upstream Capital Expenditures

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

Capital Expenditures Summary(1) Three months Six months

ended June 30 ended June 30

(millions of dollars) 2006 2005 2006 2005

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

Exploration

Western Canada $ 153 $ 153 $ 320 $ 314

East Coast Canada

and Frontier 4 14 25 18

International 36 19 37 23

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

193 186 382 355

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

Development

Western Canada 244 223 757 594

East Coast Canada 111 126 163 246

International 6 1 9 3

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

361 350 929 843

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

$ 554 $ 536 $ 1,311 $ 1,198

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

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

(1) Excludes capitalized costs related to asset retirement obligations

incurred during the period.

 


Upstream capital expenditures totaled $1,311 million, 84 percent of total consolidated capital expenditures during the first six months of 2006 compared with $1,198 million or 91 percent of the total, during the first six months of 2005.



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

Western Canada Wells Three months Six months

Drilled(1)(2) ended June 30 ended June 30

2006 2005 2006 2005

Gross Net Gross Net Gross Net Gross Net

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

Exploration Oil 8 8 10 10 30 30 35 32

Gas 34 16 36 21 196 100 132 93

Dry 3 2 5 5 19 17 19 19

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

45 26 51 36 245 147 186 144

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

Development Oil 70 59 65 58 196 171 131 119

Gas 30 22 47 44 254 216 278 265

Dry 2 2 5 5 11 11 15 15

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

102 83 117 107 461 398 424 399

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

Total 147 109 168 143 706 545 610 543

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

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

(1) Excludes stratigraphic test wells.

(2) Includes non-operated wells.

 


4.2 MIDSTREAM

Second Quarter

Upgrading earnings decreased in the second quarter of 2006 by $18 million compared with the second quarter of 2005 due to:


- narrower upgrading differential; and

- lower sales volume of synthetic crude oil due to an outage for

compressor repairs.

Partially offset by:

- lower natural gas and steam costs; and

- lower income taxes and adjustment for tax rate reductions.


Six Months

The factors that affected results for the second quarter were primarily responsible for variances in the results for the six months ended June 30, 2006.



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

Upgrading Earnings Summary Three months Six months

(millions of dollars, ended June 30 ended June 30

except where indicated) 2006 2005 2006 2005

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

Gross margin $ 136 $ 195 $ 344 $ 402

Operating costs 53 53 119 103

Other recoveries (2) (2) (3) (3)

Depreciation and amortization 6 4 12 9

Income taxes - 43 44 89

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

Earnings $ 79 $ 97 $ 172 $ 204

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

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

Selected operating data:

Upgrader throughput(1)

(mbbls/day) 68.8 71.3 70.1 71.7

Synthetic crude oil sales

(mbbls/day) 56.9 60.1 60.2 62.0

Upgrading differential

($/bbl) $ 22.73 $ 31.05 $ 28.73 $ 31.51

Unit margin ($/bbl) $ 26.35 $ 35.64 $ 31.61 $ 35.80

Unit operating cost(2)

($/bbl) $ 8.39 $ 8.12 $ 9.33 $ 7.91

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

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

(1) Throughput includes diluent returned to the field.

(2) Based on throughput.

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

Upgrading Earnings Variance Analysis

(millions of dollars)

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

Three months ended June 30, 2005 $ 97

Volume (10)

Margin (49)

Operating costs - energy related 5

Operating costs - non-energy related (5)

Depreciation and amortization (2)

Income taxes 43

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

Three months ended June 30, 2006 $ 79

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

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

Six months ended June 30, 2005 $ 204

Volume (12)

Margin (46)

Operating costs - energy related (4)

Operating costs - non-energy related (12)

Depreciation and amortization (3)

Income taxes 45

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

Six months ended June 30, 2006 $ 172

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

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

 


Second Quarter

Infrastructure and marketing earnings increased by $28 million in the second quarter of 2006 compared with the second quarter of 2005 due to:


- higher income associated with marketing natural gas and blended heavy

crude oil;

- higher pipeline margins; and

- lower income taxes including an adjustment for tax rate reductions.


Six Months

The factors that affected results for the second quarter were primarily responsible for variances in the results for the six months ended June 30, 2006 except that earnings from marketing blended heavy crude oil were lower than the comparable six month period in 2005.



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

Infrastructure and Marketing

Earnings Summary Three months Six months

(millions of dollars, ended June 30 ended June 30

except where indicated) 2006 2005 2006 2005

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

Gross margin - pipeline $ 28 $ 22 $ 54 $ 47

- other

infrastructure

and marketing 52 39 120 116

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

80 61 174 163

Other expenses 3 2 5 5

Depreciation and amortization 5 6 11 11

Income taxes 11 20 40 52

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

Earnings $ 61 $ 33 $ 118 $ 95

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

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

Selected operating data:

Aggregate pipeline

throughput (mbbls/day) 480 488 490 499

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

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

 


Midstream Capital Expenditures

Midstream capital expenditures totaled $87 million in the first six months of 2006; $75 million at the Lloydminster Upgrader, primarily for debottleneck and reliability projects and $12 million on pipelines and infrastructure.

4.3 REFINED PRODUCTS

Second Quarter

Refined products earnings increased by $32 million in the second quarter of 2006 compared with the second quarter of 2005 due to:


- higher marketing margins for gasoline and distillates; and

- higher sales volume of asphalt products.

Partially offset by:

- higher depreciation expense for the Prince George refinery and

marketing outlets.


Six Months

The factors that affected results for the second quarter were primarily responsible for variances in the results for the six months ended June 30, 2006.



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

Refined Products

Earnings Summary Three months Six months

(millions of dollars, ended June 30 ended June 30

except where indicated) 2006 2005 2006 2005

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

Gross margin - fuel sales $ 57 $ 24 $ 79 $ 53

- ancillary

sales 8 9 16 16

- asphalt sales 32 28 53 47

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

97 61 148 116

Operating and other expenses 19 19 35 36

Depreciation and amortization 13 11 23 20

Income taxes 13 11 22 22

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

Earnings $ 52 $ 20 $ 68 $ 38

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

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

Selected operating data:

Number of fuel outlets 506 521

Light oil sales

(million litres/day) 8.6 8.8 8.6 8.6

Light oil retail sales

per outlet

(thousand litres/day) 12.2 12.2 12.5 12.3

Prince George refinery

throughput (mbbls/day)(1) 3.7 9.5 6.5 9.8

Asphalt sales (mbbls/day) 24.9 19.7 21.3 18.7

Lloydminster refinery

throughput (mbbls/day) 25.4 21.6 26.2 24.3

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

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

(1) Prince George throughput decreased in the second quarter of 2006 as a

result of a plant shutdown for the commissioning of the low sulphur

diesel modifications.

 


Refined Products Capital Expenditures

Refined Products capital expenditures totaled $143 million in the first six months of 2006; $32 million at the Prince George refinery, $64 million at the Lloydminster ethanol plant and $40 million at the Minnedosa ethanol plant.

4.4 CORPORATE

Second Quarter

Corporate expense decreased by $27 million in the second quarter of 2006 compared with the second quarter of 2005 due to:


- gains on translation of U.S. denominated debt in the second quarter

2006 compared with losses in the second quarter of 2005; and

- lower stock-based compensation expense during the second quarter

of 2006.

Partially offset by:

- lower capitalized interest due to start-up of the White Rose oil

field; and

- higher profit elimination on inventory on-hand at the end of the

second quarter of 2006.


Six Months

The factors that affected results for the second quarter were primarily responsible for variances in the results for the six months ended June 30, 2006.



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

Corporate Summary Three months Six months

ended June 30 ended June 30

(millions of dollars)

income (expense) 2006 2005 2006 2005

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

Intersegment

eliminations - net $ (23) $ 14 $ (14) $ (9)

Administration

expenses (8) (5) (12) (11)

Stock-based

compensation (15) (77) (85) (98)

Accretion (1) (1) (1) (1)

Other - net (4) (3) (8) (6)

Depreciation and

amortization (5) (5) (11) (11)

Interest on debt (32) (37) (70) (72)

Interest capitalized 10 31 21 55

Interest income - - - 1

Foreign exchange

- realized (8) (1) 19 5

Foreign exchange

- unrealized 40 (19) 18 (32)

Income taxes 10 40 53 74

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

Loss $ (36) $ (63) $ (90) $ (105)

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

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

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

Foreign Exchange Rates Three months Six months

ended June 30 ended June 30

2006 2005 2006 2005

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

U.S./Canadian dollar

exchange rates:

At beginning of

period U.S. $0.857 U.S. $0.827 U.S. $0.858 U.S. $0.831

At end of period U.S. $0.897 U.S. $0.816 U.S. $0.897 U.S. $0.816

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

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

 


Consolidated Income Taxes

During the second quarter of 2006 consolidated income taxes consisted of $210 million of current taxes and a recovery of future taxes of $229 million compared with current taxes of $75 million and future taxes of $101 million in the same period of 2005.

The recovery of future taxes in the second quarter of 2006 resulted from recording non-recurring tax benefits of $328 million that arose due to changes in the tax rates for the governments of Canada ($198 million), Alberta ($90 million) and Saskatchewan ($40 million). All of this tax legislation received royal assent and was, therefore, substantively enacted in the second quarter of 2006.

The increase in current taxes in the second quarter of 2006 compared with the second quarter of 2005 was due to higher taxable income.

Corporate Capital Expenditures

Corporate capital expenditures totaled $13 million in the first six months of 2006 primarily for various office and information system upgrades.

5.0 LIQUIDITY AND CAPITAL RESOURCES

During the second quarter cash flow from operating activities financed all of our capital requirements and dividend payment. At June 30, 2006 we had $1.4 billion in unused committed credit facilities.

5.1 OPERATING ACTIVITIES

In the second quarter of 2006, cash generated from operating activities amounted to $1,302 million compared with $771 million in the second quarter of 2005. Higher cash flow from operating activities was primarily due to higher commodity prices, higher production volumes and a higher change in non-cash working capital.

5.2 FINANCING ACTIVITIES

In the second quarter of 2006, cash used in financing activities amounted to $339 million compared with $192 million in the second quarter of 2005. During the second quarter of 2006, higher dividends and non-cash working capital associated with financing activities primarily resulted in a higher use of cash compared with the second quarter of 2005. The change in non-cash working capital mainly related to a reduction of $108 million in outstanding accounts receivable that had been sold under our securitization program. The debt issuances and repayments presented in the Consolidated Statements of Cash Flows include multiple drawings and repayments under revolving debt facilities.

5.3 INVESTING ACTIVITIES

In the second quarter of 2006, cash used in investing activities amounted to $773 million compared with $585 million in the second quarter of 2005. Cash was used primarily for capital expenditures and provisions for turnarounds partially offset by proceeds from asset sales.

5.4 SOURCES OF CAPITAL

Liquidity describes a company's ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash 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 revenue to protect cash flow.



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

Sources and Uses of Cash Six months Year ended

ended June 30 December 31

(millions of dollars) 2006 2005

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

Cash sourced

Cash flow from operations(1) $ 2,070 $ 3,785

Asset sales 33 74

Proceeds from exercise of stock options 1 6

Proceeds from monetization of financial

instruments - 39

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

2,104 3,904

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

Cash used

Capital expenditures 1,543 3,068

Debt repayment - net 96 215

Special dividend on common shares - 424

Ordinary dividends on common shares 212 276

Settlement of asset retirement obligations 14 41

Other 13 32

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

1,878 4,056

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

Net cash (deficiency) 226 (152)

Increase (decrease) in non-cash working

capital (281) 394

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

Increase (decrease) in cash and cash

equivalents (55) 242

Cash and cash equivalents - beginning of period 249 7

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

Cash and cash equivalents - end of period $ 194 $ 249

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

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

(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, 2006, our working capital deficiency was $854 million compared with $1.0 billion at December 31, 2005. 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.

At June 30, 2006, we had unused committed long and short-term credit facilities totalling $1.4 billion. A total of $12 million of our borrowing credit facilities were used in support of outstanding letters of credit and an additional $54 million of letters of credit were outstanding at June 30, 2006 and supported by dedicated credit lines. During the second quarter of 2006 our long-term revolving credit facilities were extended from three to five year maturities.

Credit Ratings

During the second quarter, Standard & Poor's Ratings Services placed the Company's long-term corporate credit and senior unsecured debt ratings on CreditWatch with positive implications. As at June 30, 2006 the Company's senior unsecured debt was rated Baa2 by Moody's Investors Service, BBB by Standard & Poor's Ratings Services, BBB (high) by Dominion Bond Rating Service and BBB+ by Fitch Ratings.



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

Financial Ratios Three months Six months

ended June 30 ended June 30

(millions of dollars,

except ratios) 2006 2005 2006 2005

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

Cash flow

- operating

activities $ 1,302 $ 771 $ 2,426 $ 1,500

- financing

activities $ (339) $ (192) $ (848) $ (253)

- investing

activities $ (773) $ (585) $ (1,633) $ (1,251)

Debt to capital

employed (percent) 16.3 24.5

Corporate

reinvestment

ratio(1)(2) 0.8 1.0

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

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

(1) Calculated for the 12 months ended for the periods shown.

(2) Reinvestment ratio is based on net capital expenditures including

corporate acquisitions.

 


5.5 CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

Refer to Husky's 2005 annual Management's Discussion and Analysis under the caption "Cash Requirements" which summarizes contractual obligations and commercial commitments. There has been no material change in these amounts as at June 30, 2006.

5.6 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. At June 30, 2006, we had sold $242 million of accounts receivable under the securitization program. The securitization program permits the sale of a maximum $350 million of accounts receivable on a revolving basis. The accounts receivable are sold to an unrelated third party and in accordance with the agreement we must provide a loss reserve to replace defaulted receivables. The securitization agreement expires on January 31, 2009.

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.

6.0 TRANSACTIONS WITH RELATED PARTIES

We did not have any significant transactions with related parties during the first six months of 2006 or during the year ended December 31, 2005.

7.0 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 2006.

8.0 FINANCIAL AND DERIVATIVE INSTRUMENTS

Husky is exposed to market risks related to commodity prices, interest rates and foreign exchange rates as discussed under Section 3.0 "Business Environment". From time to time, we use financial and derivative instruments to manage our exposure to these risks.

8.1 POWER CONSUMPTION

At June 30, 2006, we had hedged power consumption as follows:



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

(millions of dollars, Notional

except where Volumes Unrecognized

indicated) (MW) Term Price Gain (Loss)

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

Fixed price purchase 19.0 July to $ 62.50/MWh $ -

Aug. 2006

19.0 July to $ 63.00/MWh (0.1)

Sept. 2006

38.0 Oct. to $ 62.95/MWh 0.3

Dec. 2006

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

$ 0.2

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

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

 


8.2 INTEREST RATE RISK MANAGEMENT

In the first six months of 2006, interest rate risk management activities resulted in a decrease to interest expense of $1 million.

The cross currency swaps resulted in an addition to interest expense of $5 million in the first six months of 2006.

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 2006, these swaps resulted in an offset to interest expense amounting to $1 million.

The amortization of previous interest rate swap terminations resulted in an additional $5 million offset to interest expense in the first six months of 2006.

8.3 FOREIGN CURRENCY RISK MANAGEMENT

Please refer to note 11 of the Consolidated Financial Statements.

9.0 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, 2005 available at www.sedar.com.

10.0 NEW ACCOUNTING STANDARDS

Effective January 1, 2006, we adopted the revised recommendations of the Canadian Institute of Chartered Accountants section 3831, "Non-monetary Transactions" which replaced section 3830 of the same name. The new recommendations require that all non-monetary transactions are measured based on fair value unless the transaction lacks commercial substance or is an exchange of product or property held for sale in the ordinary course of business. The guidance was effective for all non-monetary transactions initiated in periods beginning on or after January 1, 2006.

11.0 OUTSTANDING SHARE DATA



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

Six months Year ended

ended June 30 December 31

(in thousands, except per share amounts) 2006 2005

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

Share price(1)

High $ 75.64 $ 69.95

Low $ 58.00 $ 32.30

Close at end of period $ 70.06 $ 59.00

Average daily trading volume 624 664

Weighted average number of common shares

outstanding

Basic 424,163 423,964

Diluted 424,163 423,964

Issued and outstanding at end of period(2)

Number of common shares 424,187 424,125

Number of stock options 6,783 7,285

Number of stock options exercisable 3,145 1,533

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

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

(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, 2006

to July 11, 2006.

 


12.0 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 - 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 equals net earnings plus items not affecting cash which include accretion, depletion, depreciation and amortization, future income taxes, foreign exchange and other non-cash items.

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) 2006 2005

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

Non-GAAP

Cash flow from operations $ 2,070 $ 3,785

Settlement of asset retirement obligations (14) (41)

Change in non-cash working capital 370 (72)

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

GAAP

Cash flow - operating activities $ 2,426 $ 3,672

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

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

 


13.0 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 One hectare is equal to 2.47 acres

initial reserves Remaining reserves plus cumulative production

feedstock Raw materials which are processed into

petroleum products

design rate capacity The maximum continuous rated output of a

plant based on its design

(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.



14.0 FORWARD-LOOKING STATEMENTS OR INFORMATION

Certain statements in this Interim Report are forward-looking statements or information (collectively "forward-looking statements"), within the meaning of the applicable Canadian securities legislation, and Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The Company is hereby providing cautionary statements identifying important factors that could cause the Company's actual results to differ materially from those projected in forward-looking statements made in this Interim Report. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "intend," "plan," "projection," "could," "vision," "goals," "objective" and "outlook") are not historical facts and may be forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, forward-looking statements and information include: our steam injection and production plans for the Tucker in-situ oil sands project, our White Rose drilling, development and production plans, our West Bonne Bay drilling plans, our Lloydminster ethanol plant production plans, our Minnedosa ethanol plant commissioning plans, our throughput capacity projections for the ethanol plants, our East Coast seismic program, our Sunrise oil sands project design schedule, and water evaluation and stratigraphic drilling plans, our South China Sea drilling and seismic evaluation plans, our East China Sea drilling plans, and our Lloydminster Upgrader expansion design plans. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this Interim Report. Among the key factors that have a direct bearing on the Company's results of operations are the nature of the Company's involvement in the business of exploration, development and production of oil and natural gas reserves and the fluctuation of the exchange rate between the Canadian dollar and the United States dollar. These and other factors are discussed herein under "Management's Discussion and Analysis".

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements of the Company made by or on behalf of the Company, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to:


- fluctuations in commodity prices;

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

production levels as they are affected by our success at exploration

and development drilling and related activities and estimated decline

rates;

- the uncertainties resulting from potential delays or changes in plans

with respect to exploration or development projects or capital

expenditures;

- changes in general economic, market and business conditions;

- fluctuations in supply and demand for our products;

- fluctuations in the cost of borrowing;

- our use of derivative financial instruments to hedge exposure to

changes in commodity prices and fluctuations in interest rates and

foreign currency exchange rates;

- political and economic developments, expropriations, royalty and tax

increases, retroactive tax claims and changes to import and export

regulations and other foreign laws and policies in the countries in

which we operate;

- our ability to receive timely regulatory approvals;

- the integrity and reliability of our capital assets;

- the cumulative impact of other resource development projects;

- the maintenance of satisfactory relationships with unions, employee

associations and joint venturers;

- competitive actions of other companies, including increased

competition from other oil and gas companies or from companies that

provide alternate sources of energy;

- actions by governmental authorities, including changes in

environmental and other regulations that may impose restrictions in

areas where we operate;

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

relationships to fulfill their obligations; and

- the occurrence of unexpected events such as fires, blowouts, freeze-

ups, equipment failures and other similar events affecting us or

other parties whose operations or assets directly or indirectly

affect us and that may or may not be financially recoverable.


Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

15.0 CAUTIONARY NOTE REQUIRED BY NATIONAL INSTRUMENT 51-101

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

Husky's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Husky by Canadian securities regulatory authorities, which permits Husky to provide disclosure required by and consistent with those of the United States Securities and Exchange Commission and the Financial Accounting Standards Board in the United States in place of much of the disclosure expected by National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities." Please refer to "Disclosure of Exemption Under National Instrument 51-101" at page 2 of our Annual Information Form for the year ended December 31, 2005 filed with securities regulatory authorities for further information.

16.0 CAUTIONARY NOTE TO U.S. INVESTORS

The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated with actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this release and Interim Report, such as "probable reserves" and "recoverable resource", that the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. investors should refer to our Annual Report on Form 40-F available from us or the SEC for further reserve disclosure.

 


CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets

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

June 30 December 31

(millions of dollars) 2006 2005

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

(unaudited) (audited)

Assets

Current assets

Cash and cash equivalents $ 194 $ 249

Accounts receivable 747 856

Inventories 465 471

Prepaid expenses 70 40

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

1,476 1,616

Property, plant and equipment - (full cost

accounting) 23,881 22,375

Less accumulated depletion, depreciation

and amortization 9,166 8,416

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

14,715 13,959

Goodwill 160 160

Other assets 54 62

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

$ 16,405 $ 15,797

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

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

Liabilities and Shareholders' Equity

Current liabilities

Accounts payable and accrued liabilities $ 2,063 $ 2,391

Long-term debt due within one year (note 5) 267 274

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

2,330 2,665

Long-term debt (note 5) 1,455 1,612

Other long-term liabilities (note 6) 717 730

Future income taxes 3,089 3,270

Commitments and contingencies (note 8)

Shareholders' equity

Common shares (note 9) 3,527 3,523

Retained earnings 5,287 3,997

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

8,814 7,520

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

$ 16,405 $ 15,797

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

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

Common shares outstanding (millions) (note 9) 424.2 424.1

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

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

The accompanying notes to the consolidated financial statements are an

integral part of these statements.



Consolidated Statements of Earnings

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

Three months Six months

ended June 30 ended June 30

(millions of dollars,

except per share

amounts) (unaudited) 2006 2005 2006 2005

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

Sales and operating

revenues, net of

royalties $ 3,040 $ 2,350 $ 6,144 $ 4,444

Costs and expenses

Cost of sales and

operating expenses 1,638 1,331 3,465 2,482

Selling and

administration

expenses 50 40 77 69

Stock-based

compensation 15 77 85 98

Depletion,

depreciation and

amortization 383 304 762 602

Interest - net

(note 5) 22 6 49 16

Foreign exchange

(note 5) (32) 20 (37) 27

Other - net 5 2 8 5

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

2,081 1,780 4,409 3,299

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

Earnings before

income taxes 959 570 1,735 1,145

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

Income taxes (note 7)

Current 210 75 414 142

Future (229) 101 (181) 225

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

(19) 176 233 367

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

Net earnings $ 978 $ 394 $ 1,502 $ 778

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

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

Earnings per share

Basic $ 2.31 $ 0.93 $ 3.54 $ 1.84

Diluted $ 2.31 $ 0.93 $ 3.54 $ 1.84

Weighted average

number of common

shares outstanding

(millions)

Basic 424.2 423.9 424.2 423.8

Diluted 424.2 423.9 424.2 423.8

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

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



Consolidated Statements of Retained Earnings

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

Three months Six months

ended June 30 ended June 30

(millions of dollars)

(unaudited) 2006 2005 2006 2005

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

Beginning of period $ 4,415 $ 3,027 $ 3,997 $ 2,694

Net earnings 978 394 1,502 778

Dividends on common

shares (106) (59) (212) (110)

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

End of period $ 5,287 $ 3,362 $ 5,287 $ 3,362

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

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

The accompanying notes to the consolidated financial statements are an

integral part of these statements.



Consolidated Statements of Cash Flows

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

Three months Six months

ended June 30 ended June 30

(millions of dollars)

(unaudited) 2006 2005 2006 2005

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

Operating activities

Net earnings $ 978 $ 394 $ 1,502 $ 778

Items not affecting

cash

Accretion (note 6) 9 9 18 17

Depletion,

depreciation and

amortization 383 304 762 602

Future income

taxes (note 7) (229) 101 (181) 225

Foreign exchange (41) 17 (42) 24

Other 3 3 11 (2)

Settlement of asset

retirement

obligations (6) (9) (14) (14)

Change in non-cash

working capital

(note 4) 205 (48) 370 (130)

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

Cash flow

- operating

activities 1,302 771 2,426 1,500

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

Financing activities

Bank operating

loans financing

- net (62) (48) - (15)

Long-term debt

issue 251 1,029 1,226 2,451

Long-term debt

repayment (300) (1,150) (1,322) (2,393)

Proceeds from

exercise of stock

options - 3 1 4

Proceeds from

monetization of

financial

instruments - 30 - 30

Dividends on common

shares (106) (59) (212) (110)

Change in non-cash

working capital

(note 4) (122) 3 (541) (220)

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

Cash flow

- financing

activities (339) (192) (848) (253)

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

Available for investing 963 579 1,578 1,247

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

Investing activities

Capital expenditures (683) (613) (1,543) (1,304)

Asset sales 1 14 33 57

Other (12) (2) (13) (2)

Change in non-cash

working capital

(note 4) (79) 16 (110) (2)

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

Cash flow - investing

activities (773) (585) (1,633) (1,251)

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

Increase (decrease) in

cash and cash

equivalents 190 (6) (55) (4)

Cash and cash

equivalents at

beginning of period 4 9 249 7

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

Cash and cash

equivalents at end

of period $ 194 $ 3 $ 194 $ 3

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

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

The accompanying notes to the consolidated financial statements are an

integral part of these statements.

>>

Notes to the Consolidated Financial Statements

Six months ended June 30, 2006 (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

2006 2005 2006 2005 2006 2005

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

Three months

ended June 30

Sales and

operating

revenues, net

of royalties $ 1,451 $ 976 $ 404 $ 393 $ 2,267 $ 1,611

Costs and

expenses

Operating,

cost of

sales,

selling and

general 308 249 319 249 2,190 1,552

Depletion,

depreciation

and

amortization 354 278 6 4 5 6

Interest

- net - - - - - -

Foreign

exchange - - - - - -

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

662 527 325 253 2,195 1,558

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

Earnings (loss)

before income

taxes 789 449 79 140 72 53

Current

income

taxes 156 69 29 (2) 20 (4)

Future

income

taxes (189) 73 (29) 45 (9) 24

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

Net earnings

(loss) $ 822 $ 307 $ 79 $ 97 $ 61 $ 33

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

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

Capital

expenditures

- Three

months ended

June 30 $ 554 $ 536 $ 38 $ 30 $ 11 $ 7

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

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

Six months

ended June 30

Sales and

operating

revenues, net

of royalties $ 2,738 $ 1,864 $ 809 $ 746 $ 4,731 $ 3,063

Costs and

expenses

Operating,

cost of

sales,

selling

and general 619 489 581 444 4,562 2,905

Depletion,

depreciation

and

amortization 705 551 12 9 11 11

Interest

- net - - - - - -

Foreign

exchange - - - - - -

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

1,324 1,040 593 453 4,573 2,916

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

Earnings (loss)

before income

taxes 1,414 824 216 293 158 147

Current

income taxes 299 122 53 9 39 (11)

Future income

taxes (119) 156 (9) 80 1 63

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

Net earnings

(loss) $ 1,234 $ 546 $ 172 $ 204 $ 118 $ 95

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

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

Capital

employed - As

at June 30 $ 9,400 $ 7,878 $ 538 $ 490 $ 311 $ 570

Capital

expenditures

- Six months

ended

June 30 $ 1,311 $ 1,198 $ 75 $ 47 $ 12 $ 13

Total assets

- As at

June 30 $13,436 $11,575 $ 912 $ 751 $ 718 $ 871

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

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



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

Corporate and

Refined Products Eliminations(1) Total

2006 2005 2006 2005 2006 2005

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

Three months

ended June 30

Sales and

operating

revenues, net

of royalties $ 674 $ 560 $(1,756) $(1,190) $ 3,040 $ 2,350

Costs and

expenses

Operating,

cost of

sales,

selling and

general 596 518 (1,705) (1,118) 1,708 1,450

Depletion,

depreciation

and

amortization 13 11 5 5 383 304

Interest

- net - - 22 6 22 6

Foreign

exchange - - (32) 20 (32) 20

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

609 529 (1,710) (1,087) 2,081 1,780

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

Earnings (loss)

before income

taxes 65 31 (46) (103) 959 570

Current

income

taxes 3 (1) 2 13 210 75

Future

income

taxes 10 12 (12) (53) (229) 101

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

Net earnings

(loss) $ 52 $ 20 $ (36) $ (63) $ 978 $ 394

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

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

Capital

expenditures

- Three

months ended

June 30 $ 79 $ 43 $ 7 $ 4 $ 689 $ 620

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

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

Six months

ended June 30

Sales and

operating

revenues, net

of royalties $ 1,220 $ 997 $(3,354) $(2,226) $ 6,144 $ 4,444

Costs and

expenses

Operating,

cost of

sales,

selling

and general 1,107 917 (3,234) (2,101) 3,635 2,654

Depletion,

depreciation

and

amortization 23 20 11 11 762 602

Interest

- net - - 49 16 49 16

Foreign

exchange - - (37) 27 (37) 27

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

1,130 937 (3,211) (2,047) 4,409 3,299

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

Earnings (loss)

before income

taxes 90 60 (143) (179) 1,735 1,145

Current

income taxes 12 (2) 11 24 414 142

Future income

taxes 10 24 (64) (98) (181) 225

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

Net earnings

(loss) $ 68 $ 38 $ (90) $ (105) $ 1,502 $ 778

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

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

Capital

employed - As

at June 30 $ 577 $ 399 $ (290) $ (234) $10,536 $ 9,103

Capital

expenditures

- Six months

ended

June 30 $ 143 $ 48 $ 13 $ 8 $ 1,554 $ 1,314

Total assets

- As at

June 30 $ 1,005 $ 727 $ 334 $ 134 $16,405 $14,058

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

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

(1) 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, 2005, 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, 2005.


Note 3 Change in Accounting Policies


Non-monetary Transactions

Effective January 1, 2006, the Company adopted the revised

recommendations of the Canadian Institute of Chartered Accountants

section 3831, "Non-monetary Transactions" which replaced section 3830 of

the same name. The new recommendations require that all non-monetary

transactions are measured based on fair value unless the transaction

lacks commercial substance or is an exchange of product or property held

for sale in the ordinary course of business. The guidance was effective

for all non-monetary transactions initiated in periods beginning on or

after January 1, 2006.

 


Note 4 Cash Flows - Change in Non-cash Working Capital

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

Three months Six months

ended June 30 ended June 30

2006 2005 2006 2005

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

a) Change in non-cash

working capital

was as follows:

Decrease (increase)

in non-cash

working capital

Accounts

receivable $ 5 $ 25 $ 109 $ (20)

Inventories (26) (86) 6 (140)

Prepaid expenses (23) (7) (19) (18)

Accounts payable

and accrued

liabilities 48 39 (377) (174)

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

Change in non-cash

working capital 4 (29) (281) (352)

Relating to:

Financing

activities (122) 3 (541) (220)

Investing

activities (79) 16 (110) (2)

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

Operating

activities $ 205 $ (48) $ 370 $ (130)

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

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

b) Other cash flow

information:

Cash taxes paid $ 44 $ 76 $ 173 $ 159

Cash interest

paid $ 47 $ 43 $ 79 $ 73

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

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

Note 5 Long-term Debt

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

June 30 Dec 31 June 30 Dec 31

Maturity 2006 2005 2006 2005

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

Cdn $ Amount U.S. $ Denominated

Long-term debt

7.125% notes 2006 $ 167 $ 175 $ 150 $ 150

6.25% notes 2012 446 467 400 400

7.55%

debentures 2016 223 233 200 200

6.15% notes 2019 335 350 300 300

8.45% senior

secured

bonds - 99 - 85

Medium-term

notes 2007-9 300 300 - -

8.90%

capital

securities 2028 251 262 225 225

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

Total

long-term

debt 1,722 1,886 $ 1,275 $ 1,360

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

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

Amount due

within

one year (267) (274)

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

$ 1,455 $ 1,612

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

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

Interest - net consisted of:

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

Three months Six months

ended June 30 ended June 30

2006 2005 2006 2005

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

Long-term debt $ 31 $ 36 $ 68 $ 70

Short-term debt 2 1 3 2

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

33 37 71 72

Amount capitalized (10) (31) (21) (55)

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

23 6 50 17

Interest income (1) - (1) (1)

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

$ 22 $ 6 $ 49 $ 16

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

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

Foreign exchange

consisted of:

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

Three months Six months

ended June 30 ended June 30

2006 2005 2006 2005

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

(Gain) loss on

translation of U.S.

dollar denominated

long-term debt $ (66) $ 22 $ (67) $ 31

Cross currency swaps 27 (4) 26 (6)

Other losses 7 2 4 2

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

$ (32) $ 20 $ (37) $ 27

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

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

Note 6 Other Long-term Liabilities


Asset Retirement Obligations

Changes to asset retirement obligations were as

follows:


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

Six months

ended June 30

2006 2005

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

Asset retirement obligations at beginning of

period $ 557 $ 509

Liabilities incurred 10 8

Liabilities disposed - (7)

Liabilities settled (14) (14)

Accretion 18 17

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

Asset retirement obligations at end of period $ 571 $ 513

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

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



At June 30, 2006, the estimated total undiscounted inflation adjusted

amount required to settle the asset retirement obligations was

$3.4 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 7 Income Taxes


The recovery of future taxes in the second quarter of 2006 resulted from

recording non-recurring tax benefits of $328 million that arose due to

changes in the tax rates for the governments of Canada ($198 million),

Alberta ($90 million) and Saskatchewan ($40 million). All of this tax

legislation received royal assent and was, therefore, substantively

enacted in the second quarter of 2006. There were no similar tax rate

benefits recorded in the first quarter of 2006 or during the first six

months of 2005.


Note 8 Commitments and Contingencies


The Company has no material litigation other than 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 9 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

2006 2005

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

Number of Number of

Shares Amount Shares Amount

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

Balance at beginning

of period 424,125,078 $ 3,523 423,736,414 $ 3,506

Exercised - options

and warrants 62,265 4 246,341 9

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

Balance at June 30 424,187,343 $ 3,527 423,982,755 $ 3,515

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

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


Stock Options

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

below:


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

Six months ended June 30

2006 2005

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

Weighted Weighted

Number of Average Number of Average

Options Exercise Options Exercise

(thousands) Prices (thousands) Prices

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

Outstanding, beginning

of period 7,285 $ 25.81 9,964 $ 22.61

Granted 567 $ 69.33 175 $ 35.29

Exercised for common

shares (62) $ 20.97 (217) $ 16.27

Surrendered for cash (834) $ 22.84 (1,646) $ 18.10

Forfeited (173) $ 40.18 (281) $ 24.46

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

Outstanding at June 30 6,783 $ 29.49 7,995 $ 23.92

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

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

Options exercisable at

June 30 3,145 $ 23.59 2,281 $ 21.98

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

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



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

June 30, 2006

Outstanding Options Options Exercisable

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

Weighted Weighted Weighted

Range of Number of Average Average Number of Average

Exercise Options Exercise Contractual Options Exercise

Price (thousands) Prices Life (years) (thousands) Prices

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

$13.96

- $14.99 92 $ 14.56 2 92 $ 14.56

$15.00

- $22.99 173 $ 19.75 2 97 $ 18.78

$23.00

- $23.99 5,194 $ 23.83 3 2,876 $ 23.83

$24.00

- $39.99 352 $ 32.07 3 80 $ 31.39

$40.00

- $55.99 440 $ 51.96 4 - $ -

$56.00

- $73.80 532 $ 70.26 5 - $ -

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

6,783 $ 29.49 3 3,145 $ 23.59

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

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

Note 10 Employee Future Benefits

Total benefit costs recognized were as follows:

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

Three months Six months

ended June 30 ended June 30

2006 2005 2006 2005

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

Employer current

service cost $ 5 $ 5 $ 9 $ 9

Interest cost 3 3 5 5

Expected return on

plan assets (2) (2) (3) (4)

Amortization of net

actuarial losses - - - 1

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

$ 6 $ 6 $ 11 $ 11

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

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

Note 11 Financial Instruments and Risk Management


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


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

June 30 Dec. 31

2006 2005

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

Commodity price risk management

Power consumption $ - $ -

Interest rate risk management

Interest rate swaps 2 7

Foreign currency risk management

Foreign exchange contracts (27) (32)

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

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


Commodity Price Risk Management

Power Consumption

At June 30, 2006, the Company had hedged power consumption as follows:


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

Notional

Volumes

(MW) Term Price

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

Fixed price purchase 19.0 July to Aug. 2006 $ 62.50/MWh

19.0 July to Sept. 2006 $ 63.00/MWh

38.0 Oct. to Dec. 2006 $ 62.95/MWh

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

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


The impact of the hedge program during the first six months of 2006 was a

loss of $1.0 million (2005 - loss of $0.1 million).

Natural Gas Contracts

At June 30, 2006, the unrecognized gains (losses) on external offsetting

physical purchase and sale natural gas contracts were as follows:


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

Unrecog-

Volumes nized

(mmcf) Gain (Loss)

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

Physical purchase contracts 32,747 $ (1)

Physical sale contracts (32,747) $ 5

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

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

/T/

Interest Rate Risk Management

During the first six months of 2006, the Company realized a gain of

$1 million (2005 - gain of $9 million) from interest rate risk management

activities.

Foreign Currency Risk Management

During the first six months of 2006, the Company realized a loss of

$21 million (2005 - gain of $7 million) from all foreign currency risk

management activities.

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,

2006, $242 million in outstanding accounts receivable had been sold under

the program, a reduction of $108 million in the second quarter compared

with $350 million in outstanding account receivable sold at December 31,

2005. In July 2006, the program to sell accounts receivable was further

reduced by $17 million to $225 million.

Husky Energy will release its second quarter financial results after markets close on Wednesday, July 19, 2006. A conference call for analysts and investors will be held on Thursday, July 20, 2006 at 4:15 p.m. (EST).

Mr. John C.S. Lau, President & Chief Executive Officer and other officers will be participating in the call.

Media are invited to listen to the conference call by dialing 1-800-377- 5794 beginning at 4:05 p.m. (EST). Those 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. (EST), then dialing reservation number 21298690. The PostView will be available until Thursday, August 17, 2006.

Husky Energy is a Canadian based, integrated energy and energy-related company headquartered in Calgary, Alberta. Husky Energy is publicly traded on the Toronto Stock Exchange under the symbol HSE.



FOR FURTHER INFORMATION PLEASE CONTACT:

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

or

Husky Energy Inc.
Tanis Thacker
Senior Analyst, Investor Relations
(403) 298-6747

or

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